Edgar Filing: CARRIZO OIL & GAS INC

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Form 10-K

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

For the Fiscal Year Ended December 31, 2010

Commission File Number 000-29187-87

Carrizo Oil & Gas, Inc.

(Exact name of registrant as specified in its charter)


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:

Common Stock, $0.01 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. YES x NO ¨

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 ¨ NO x

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 x NO ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES ¨ NO ¨

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. ¨

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 ¨ NO x

At June 30, 2010, the aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $489.1 million based on the closing price of such stock on such date of $15.53.

At March 25, 2011, the number of shares outstanding of the registrant’s Common Stock was 38,925,175.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the Registrant’s 2011 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, 2010.

TABLE OF CONTENTS


Forward Looking Statements			3
PART I			5
Item 1. and Item 2. Business and Properties			5
Item 1A. Risk Factors			26
Item 1B. Unresolved Staff Comments			40
Item 3. Legal Proceedings			44
Item 4. Reserved			44
PART II			45
Item 5. Market for Registrant’s Common Stock, Related Shareholder Matters and Issuer Purchases of Equity Securities			45
Item 6. Selected Financial Data			46
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			47
Item 7A. Qualitative and Quantitative Disclosures About Market Risk			67
Item 8. Financial Statements and Supplementary Data			68
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure			68
Item 9A. Controls and Procedures			68
Item 9B. Other Information			69
PART III			69
Item 10. Directors, Executive Officers and Corporate Governance			69
Item 11. Executive Compensation			69
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters			69
Item 13. Certain Relationships and Related Transactions, and Director Independence			69
Item 14. Principal Accountant Fees and Services			69
PART IV			70
Item 15. Exhibits and Financial Statement Schedules			70

Forward-Looking Statements.

This annual report contains statements concerning our expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements include, among others, statements regarding:

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our growth strategies;

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our ability to explore for and develop natural gas and oil resources successfully and economically;

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our estimates of the timing and number of wells we expect to drill and other exploration activities;

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our estimates regarding timing and levels of production;

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anticipated trends in our business;

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the effects of competition on us;

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our future results of operations;

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our liquidity and our ability to finance our exploration and development activities;

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our capital expenditure plan;

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plans regarding our North Sea assets;

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future market conditions in the oil and gas industry;

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our ability to make, integrate and develop acquisitions; and

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the impact of governmental regulation, taxes, market changes and world events.

You generally can identify our forward-looking statements by the words “anticipate,” “believe,” budgeted,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “scheduled,” “should,” or other similar words. Such statements involve risks and uncertainties, including, but not limited to, those relating to the worldwide economic downturn, availability of financing, our dependence on our exploratory drilling activities, the volatility of and changes in oil and gas prices, the need to replace reserves depleted by production, operating risks of oil and gas operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and impact of oil and gas reserve estimation and disclosure requirements, activities and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, borrowing base determinations and availability under our senior credit facility, evaluations of the Company by lenders under our senior credit facility, the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, air emissions and climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, availability of equipment, actions by our midstream and other industry partners, weather, availability of financing, actions by lenders, our ability to obtain permits and licenses, the results of audits and assessments, the failure to obtain certain bank and lease consents, the existence of title defects, delays, costs and difficulties relating to our joint ventures, actions by joint venture partners, results of exploration activities and other factors detailed in this annual report.

We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

Some of the factors that could cause actual results to differ from those expressed or implied in forward-looking statements are described under Part II, Item 1A., “Risk Factors” and in other sections of this annual 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 our forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, we undertake no duty to update any forward-looking statement.

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

PART I

Item 1. and Item 2. Business and Properties

OVERVIEW

General

Carrizo Oil & Gas, Inc. is a Houston-based independent energy company which, together with its subsidiaries (collectively, “Carrizo,” the “Company” or “we”) is actively engaged in the exploration, development, and production of oil and gas in the United States and United Kingdom. Our current operations are principally focused in proven, producing oil and gas plays primarily in the Barnett Shale in North Texas, the Marcellus Shale in Appalachia, the Eagle Ford Shale in South Texas, the Niobrara Formation in the Denver-Julesberg Basin (the “Niobrara”) in Colorado and the UK North Sea where our Huntington field discovery is currently under development. Carrizo controls significant prospective acreage blocks and utilizes advanced drilling and completion technology along with sophisticated 3-D seismic techniques to identify potential oil and gas drilling opportunities and to optimize reserve recovery.

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 43%, while simultaneously maintaining a CAGR on our production of 26%. During 2010, we added, net of production, 275.6 Bcfe to proved reserves, for a reserve replacement ratio of 749%. Please read “Oil and Gas Reserve Replacement” for more information on our reserve replacement ratio. This reserve replacement ratio was achieved in spite of record production in 2010 of 36.8 Bcfe, an 11% increase from 2009. At year-end 2010, our proved reserves of 841 Bcfe were approximately 80% natural gas and approximately 20% crude oil, condensate and natural gas liquids, as compared to 85% and 15% at year-end 2009, respectively.

Our Board of Directors has approved a capital expenditure plan of $340 million for 2011. This plan reflects our strategy of controlling capital costs and maintaining financial flexibility in light of current economic conditions and is comparable to our $325 million capital expenditures in 2010. We currently expect to commit the majority of our 2011 capital expenditure plan on the continued development of our properties in the Barnett Shale, Marcellus Shale, Eagle Ford Shale, the Niobrara, and the U.K. North Sea. The level of our expected Marcellus Shale capital expenditures has been decreased by the obligation of our joint venture partner to carry a portion of our costs. We expect to allocate approximately 90% of our 2011 capital expenditure plan for drilling. In addition, we have entered into a limited recourse project financing arrangement which will fund approximately $31 million of our $53 million capital expenditures plan in the U.K. North Sea. We intend to finance our 2011 capital expenditure plan primarily from cash flow from operations, our senior secured credit facility in the U.S., and our senior secured revolving credit facility in the U.K. Other available sources of funding include: proceeds from the possible selective sale of non-core assets, offerings of securities and joint ventures where partners are required to carry a portion of our capital costs.

The table below highlights our primary areas of activity:


	Proved Reserves (Bcfe) December 31, 2010		Capital Expenditures ($ in millions)
	Proved Reserves (Bcfe) December 31, 2010		2010 Actual		2011 Plan
Natural Gas Plays:
Barnett Shale		680	$	151	$	75
Marcellus Shale		3		45		42
Oil/NGL Plays:
Eagle Ford Shale		90		81		140
Niobrara Formation		2		26		27
U.K. North Sea		36		6		53
Other Project Areas in the U.S.		30		15		3

Total		841	$	324	$	340

Restatement of Previously Issued Financial Statements

During the third quarter of 2010, we received cash distributions of $20.8 million on our B Unit investment in ACP II, as further described under “—Natural Gas Plays—Avista Joint Venture.” We followed the cost method of accounting for the B Units and recognized cash distributions received with respect to the B Units as Distribution Income-Related Party in the consolidated statements of operations included in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010. However, we subsequently concluded that under the full cost method of accounting, the cash distributions should be considered sales of oil and gas properties and accordingly, should be recognized as a reduction of capitalized oil and gas property costs.

The effect of restating our financial statements for the three-month and nine-month periods ended September 30, 2010 to recognize the cash distributions received on the B Units as a reduction of capitalized oil and gas property costs rather than distribution income-related party and related income tax effects, resulted in a decrease in each of net income and total shareholders’ equity of $11.5 million from the previously reported amounts for the three months and nine months ended September 30, 2010, which represents a decrease in diluted income per common share of $0.32 and $0.34 from the previously reported amounts for the three months and nine months ended September 30, 2010, respectively, with a corresponding decrease in proved oil and gas properties of $20.5 million and an increase in net income tax assets and liabilities of $9.0 million from the previously reported amounts as of September 30, 2010. The restatement also resulted in a decrease in cash flows from operating activities and a corresponding increase in cash flows from investing activities of $20.8 million from the previously reported amounts for the nine months ended September 30, 2010.

The restatement did not affect our balance of cash and cash equivalents as of September 30, 2010 or net income or loss for any of our previously issued financial statements for periods prior to the three-month period ended September 30, 2010. EBITDA, as defined in both the senior credit facility to which we were a party during the third quarter of September 2010 (the “Prior Credit Facility”) or our current senior credit facility (the “Revolving Credit Facility”), includes cash distributions received on the our B Unit investment in ACP II and, accordingly, the restatement had and will have no impact on our compliance with the financial covenants under the terms of the Prior Credit Facility or Revolving Credit Facility and will have no impact on our ability to draw on the Revolving Credit Facility’s available borrowing base. See Note 15 to the Consolidated Financial Statements for further discussion.

Natural Gas Plays

At December 31, 2010, our natural gas proved reserves were 670 Bcf, a 31% increase from 513 Bcf at December 31, 2009, approximately 93% of which was located in the Barnett Shale. Our natural gas production increased to 35.7 Bcf (98 MMcf/d) in 2010, a 12% increase from the 32.0 MMcf (88 MMcf/d) in 2009. Our natural gas production exit rate for 2010 was 125 MMcf/d, which was 36% above the exit rate for 2009.

Barnett Shale

In 2003, we began active participation in the Barnett Shale through acquisition of acreage. As of December 31, 2010, we held interests in approximately 68,253 gross (44,810 net) acres, 316 gross (224 net) producing wells and 42 gross (21.4 net) wells that were drilled but waiting on completion and/or pipeline connection. Of these wells, we operated 222 gross (200 net) producing wells and 30 gross (20.1 net) wells drilled and waiting on completion and/or pipeline connection. During 2010, we drilled 65 gross wells (36 net), of which we operated 46 gross wells (34 net), and completed and brought on production 54 gross wells (44 net). Approximately 55% of our 68,253 gross acres in the Barnett Shale is either in currently designated producing units or in units on which wells have been drilled and are waiting on completion and/or pipeline connection. Our 2010 production in the Barnett Shale was a record 32 Bcfe, 23% above 2009 production of 26 Bcfe. Our production exit rate in the Barnett Shale for 2010 was a record 113 MMcfe/d. Total proved reserves for the Barnett Shale were 680 Bcfe at December 31, 2010, approximately 92%, or 626 Bcfe, of which was natural gas.

As of December 31, 2010, we were operating three rigs in the Barnett Shale and expect to operate one of these rigs in the Barnett Shale throughout 2011. We plan to relocate one of these rigs to the Eagle Ford Shale in March 2011 and release another rig in May 2011 when the rig contract expires. We currently expect our 2011 Barnett Shale drilling efforts to require an investment of approximately $75 million for drilling and completion costs, which will be spent primarily in the core of the Barnett Shale in Southeast Tarrant County where we continue to experience the highest reserves and production rates and lowest operating costs of all of our properties in the Barnett Shale. This capital expenditure plan is designed to allow us to maintain a targeted production rate of approximately 100-110 Mmcfe/d in the Barnett Shale for 2011 while holding our core acreage.

Typical costs to drill and complete a Barnett Shale horizontal well were approximately $3 million during 2010. Although we experienced an increase in completion costs due to increased demand for frac crews from other shale plays during 2010, we expect such costs to moderate in 2011 resulting from new pressure pumping equipment coming online and the completion of lease capture drilling.

Marcellus Shale

We began active participation in the Marcellus Shale in 2007. The Marcellus Shale is substantially larger in aerial extent (over 63 million acres) than the Barnett Shale (over 3 million acres in the core areas of the Barnett) and the Marcellus Shale, 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 to effectively explore for and develop natural gas in the Marcellus Shale. Our activities in the Marcellus Shale are currently conducted through two joint ventures described below.

As of December 31, 2010, we owned interests in 305,726 gross (117,921 net) acres in the Marcellus shale trend, principally in Pennsylvania, West Virginia and New York. During 2010, we drilled five gross (0.4 net) horizontal wells and two gross (0.9 net) vertical wells to test our acreage, of which one gross (0.4) vertical well was waiting on completion at December 31, 2010. We operated two gross (0.9 net) vertical wells drilled in 2010. In 2011, we plan to spend approximately $42 million in the Marcellus Shale which includes $35 million for drilling, seismic and other infrastructure development in Pennsylvania and $7 million related to frac work and seismic analysis in West Virginia. These amounts do not include an estimated $51 million of our share of costs that will be carried by our Pennsylvania joint venture partner, Reliance Marcellus II, LLC. We currently have four rigs operating or under agreement to begin operating in Pennsylvania in the early part of 2011.

Avista Joint Venture

Effective as of August 2008, our wholly-owned subsidiary, Carrizo (Marcellus) LLC, entered into a joint venture with an affiliate of Avista Capital Partners, LP, a private equity fund (Avista Capital Partners, LP, together with its affiliates (“Avista”). Steven A. Webster, Chairman of the Company’s Board of Directors, serves as Co-Managing Partner and President of Avista. See Note 10 to our Consolidated Financial Statements.

We serve as operator of the properties covered by this joint venture and also perform specified management services for the Avista affiliate that is our partner in the joint venture. An operating committee composed of one representative of each party provides overall supervision and direction of joint operations. 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.

Subject to specified exceptions (including the Reliance transactions described below), net cash flow from hydrocarbon production from the joint venture properties and related sales proceeds, if the properties are sold, will be allocated (a) 75% to Avista and 25% to us until Avista has recovered the remainder of its investment, (b) thereafter, 100% to us until we recover an equal amount and (c) thereafter in accordance with the parties’ participating interests, which are currently 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 were issued a class of interests (“B Units”) in Avista’s joint venture entity, ACP II Marcellus, LLC (“ACP II”), that entitles us to increasing percentages of ACP II’s distributions to Avista if specified internal rates-of-return and return–on-investment thresholds with respect to Avista’s investment in ACP II 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. During the third and fourth quarters of 2010, we received aggregate cash distributions of approximately $38.8 million in respect of this interest.

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.

As part of the closing of the transactions with Reliance described below, we and Avista amended our existing joint venture agreements to provide that the properties that we and Avista sold to Reliance, as well as the properties we committed to the joint venture with Reliance, are not subject to the terms of the Avista joint venture, and that the Avista joint venture’s area of mutual interest will generally not include Pennsylvania, in which those properties are located. Our Marcellus joint venture with Avista will otherwise continue and currently includes approximately 174,583 net acres, primarily in West Virginia and New York. Pursuant to the terms of the Avista area of mutual interest, effective December 31, 2010, the initial area of mutual interest was reduced to specified halos in which the joint venture was active.

Reliance Joint Venture

In September 2010, we completed the sale of 20% of our interests in substantially all of our oil and gas properties in Pennsylvania that had been subject to the Avista joint venture to Reliance Marcellus II, LLC, (“Reliance”) a wholly-owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited, for $13.1 million in cash and a commitment by Reliance to pay 75% of certain of our future development costs up to approximately $52.0 million, (“Carry Commitment”) as further described below. Simultaneously with the closing of this transaction, ACP II closed the sale of its entire interest in the same properties to Reliance for a purchase price of approximately $327 million. In December 2010, we entered into a settlement agreement with Reliance providing for the resolution of defects in title that Reliance alleged with respect to the properties it acquired from us and Avista. In the agreement, we agreed to undertake specified curative measures with respect to the properties we and Avista sold to Reliance, and to indemnify Reliance on our own behalf and on behalf of Avista with respect to any specified third party claims (in addition to existing customary indemnification obligations under the purchase agreement). In connection with entering into the settlement agreement, we entered into an agreement with Avista by which it agreed to indemnify us for amounts we pay on its behalf under the settlement agreement, if any.

In connection with these sale transactions, we and Reliance also entered into agreements to form a new joint venture with respect to the interests purchased by Reliance from us and Avista. The Carrizo/Reliance joint venture agreement covers approximately 107,963 net acres in northern and central Pennsylvania. Under the terms of the agreement, we generally retained a 40% working interest in the acreage and Reliance generally owns a 60% working interest. In addition to funding its own share of future development obligations, Reliance agreed to fund 75% of our portion of these costs until September 2012 or until the earlier full utilization of the up to $52.0 million development carry, subject to certain conditions and extensions.

We have agreed to various restrictions on our ability to transfer our properties covered by the Reliance joint venture. Additionally, following the expiration of the Carry Commitment, we are subject to a mutual right of first offer on direct and indirect property transfers for the remainder of a ten-year development period (through September 2020), subject to specified exceptions. We have also granted an option in favor of Reliance to purchase a 60% (as adjusted over time) share of acreage purchased directly or indirectly by us after the closing. This option, which covers substantially all of Pennsylvania, is exercisable at our cost plus, in the case of direct property sales, a specified premium, and is subject to specified exceptions. We serve as operator of the properties covered by this joint venture, with Reliance having the right to assume operatorship of 60% of undeveloped acreage in portions of central Pennsylvania beginning as early as September 2011 and, for a three-year period (through September 2013) to purchase all of our 40% interest in such acreage at a specified price. Operations under the joint venture will generally be required to conform to a budget approved by an operating committee that includes representatives of both parties, subject to exceptions, including those for sole risk operations and in the event of defaults by the parties. The parties have also generally agreed until 2013 to forego the ability conduct sole risk operations and to certain other limits to such operations thereafter. Reliance has also agreed to certain limitations with respect to specified actions taken with respect to us.

Crude Oil and Liquids Plays and Projects

At December 31, 2010, our crude oil and liquids proved reserves were 28.5 MMBOE, a 92% increase from 14.8 MMBOE at December 31, 2009. The significant increase in crude oil and liquids reserves was due to the execution of our new growth strategy in crude oil and liquids-rich plays announced in April of 2010 resulting in the addition of 10.7 MMBOE of crude oil and liquids to our proved reserves in the Eagle Ford Shale (15 MMBOE including associated gas), and the approval of our Huntington field development by our joint venture and the UK Department of Energy and Climate Change in November 2010, adding 5.3 MMBOE of crude oil to our proved reserves (6.0 MMBOE including associated gas). While our crude oil and liquids production increased to 176,237 BOE (483 Bbls/d) in 2010, a 2% increase from 173,618 BOE (476 Bbls/d) in 2009, our crude oil and liquids production exit rate for 2010 was 1,500 Bbls/d, which was 420% above the exit rate for 2009 due to the benefit of new production from our Eagle Ford development.

Eagle Ford Shale

We announced a new growth strategy to increase our liquids production in April 2010, undertaking a leasing program targeting the gas condensate window of the Eagle Ford Shale. We acquired approximately 20,000 net acres primarily in LaSalle and Dimmit counties in south Texas. During 2010, we drilled five gross (5.0 net) wells, three of which were completed before the end of 2010, the fourth was completed in January 2011 and the fifth well was completed in March 2011. In late March 2011, Eagle Ford gross production from these five wells was approximately 1,400 Bbls/d and 3.7 MMcf/d. We resumed development drilling in early March by relocating a rig currently in the Barnett Shale to the Eagle Ford Shale. We expect to add a second rig later in the second quarter of 2011. As of December 31, 2010, we have approximately 15 million BOE of proved reserves in the Eagle Ford, approximately 71%, or 10.7 million BOE, of which is crude oil and liquids.

Niobrara Formation

As part of our new growth strategy in crude oil and liquids, we also acquired approximately 61,000 net acres in the Niobrara located in the Denver-Julesberg Basin in Weld County, Colorado. In 2010, we drilled three gross (3.0 net) Niobrara wells, one of which was completed in 2010 with the remaining two wells completed during the first quarter of 2011.

U.K. North Sea

We use a low cost entry business model in the U.K. North Sea that allows us to acquire prospective acreage without making any initial capital commitments. This strategy led directly to the Huntington field discovery located primarily on block 22/14b, where we retain a 15% working interest. The Huntington Forties reservoir development plan was approved by our joint venture and the U.K. Department of Energy and Climate Change in November 2010 and the field is under development with initial production currently expected in the first quarter of 2012. As of December 31, 2010, our proved reserves in the Huntington Forties reservoir were approximately 6.0 million BOE, approximately 87% of which was crude oil. The deeper Huntington Fulmar reservoir is currently planned for future appraisal.

On January 28, 2011, the Company and its Carrizo UK Huntington Ltd. subsidiary (“Carrizo UK”), as borrower, entered into a Senior Secured Multicurrency Credit Facility Agreement with BNP Paribas and Societe Generale, as lead arrangers and original lenders (the “Huntington Facility”). The Huntington Facility is secured by substantially all of Carrizo UK’s assets with limited recourse to the Company. The Huntington Facility provides financing for a substantial portion of Carrizo UK’s 15% share of the development costs associated with the Huntington Field development through a term loan facility, a cost overrun facility and a letter of credit facility. Initial borrowings under the term loan facility are conditioned on, among other things, our having made an approximately $22 million equity contribution to Carrizo UK, which was completed in February 2011. We continue to consider 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 complete a transaction on terms that are acceptable to us or at all.

In addition to our main activity on the Huntington development, we have been successful in acquiring new acreage in four of the last five UK bid rounds, including two new exploration licenses acquired in December 2010. In addition to the license containing our Huntington development, as of March 25, 2011, we held interests in four other licenses (excluding licenses that we have notified the U.K. government that we intend to relinquish during 2011). By virtue of our bid exploration strategy, each of these licenses is within ten miles of established facilities, allowing the use of existing infrastructure. Each of these four licenses has an initial term of four years and no drilling commitments. At the end of the initial term, we can commit to drill a well, extend the license or relinquish the license. The licenses can also be extended while relinquishing certain acreage under the license. If the decision is made to commit to drill a well, we and our partners in that license will have four years to drill a well on that license. On one of these licenses, we have elected to extend the license on certain acreage. No such decision has been made on the remaining three licenses. The estimated cost to satisfy all remaining committed work obligations on these four licenses is approximately $1.3 million over the next four years.

Other Project Areas in the United States

In addition to our core plays and project areas, we have additional wells, acreage positions and limited reserves in the onshore Gulf Coast area, the Camp Hill Field in Texas and certain other resource plays. Our total proved reserves in these other areas are 29.8 Bcfe,

or less than 4% of our total proved reserves. We have currently budgeted to spend $3.0 million in capital expenditures during 2011 in these other areas.

Business Strategy

Measured Growth Through the Drillbit

Our objective is to increase value through the execution of a business strategy focused on organic growth through the drillbit. Key elements of our business strategy include:

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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 100% drilling success rate in the Barnett Shale area since our entrance into the play in 2003. We expect to allocate approximately 90% of our 2011 capital expenditure plan for drilling and development.

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Pursue Growth in Crude Oil and Liquids-Rich Plays. In April 2010, we announced a new growth strategy in crude oil and liquids-rich plays driven by the attractive economics associated with those commodities. We moved quickly to implement this strategy and at December 31, 2010 owned over 20,000 net acres in the Eagle Ford Shale and over 61,000 net acres in the Niobrara. Since our announcement, we have drilled five horizontal gross wells (5.0 net) in the Eagle Ford Shale and three gross wells (3.0 net) in the Niobrara.

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Control Operating and Capital Costs. We emphasize efficiencies to lower our costs to find, develop and produce our oil and gas reserves. This includes concentrating on our core areas, which allows us to optimize drilling and completion techniques, as well as benefit from economies of scale. In addition, as we operate a significant percentage of our properties, the majority of our capital expenditure plan is discretionary allowing us the ability to reduce or reallocate our spending in response to changes in market conditions. For example, our discretionary capital spending has been strategically redeployed to pursue growth in crude oil and liquids-rich plays.

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Maintain Our Financial Flexibility. We are committed to preserving our financial flexibility. We have historically funded our capital program with a combination of cash generated from operations, proceeds from the sale of non-core assets, proceeds from sales of securities, proceeds, payments or carried interest from our joint ventures with Reliance and Avista and borrowings under our bank credit facilities.

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Focus on Areas Where We Have Experience and a Technical Advantage. One of our primary focuses is on the Barnett Shale where our wells have generally longer-lived reserves and where our management, technical staff and field operations teams have significant experience. We believe we have developed a technical advantage from operating over 211 horizontal wells in this play. We are now leveraging this advantage in other shale trends, principally in the Marcellus and Eagle Ford Shales, and in the Niobrara. We plan to focus a majority of our capital expenditures in these core areas, where we have acquired, or are acquiring significant acreage positions and a large drillsite inventory.

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Maintain a Conservative Exploration and Development Portfolio. In recent years, 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. 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 well funded partners to ensure that we are able to move forward on projects in a timely manner. Our joint ventures with an affiliate of Reliance Industries in most of Pennsylvania, with an affiliate of Avista in other parts of the Marcellus Shale and with Sumitomo Corporation in the Barnett Shale are prominent examples of this strategy. We also attempt to limit our exposure to reductions in natural gas prices by actively hedging production. As of December 31, 2010, we had hedged approximately 29,303,000 MMBtus of forecasted natural gas production through 2012. Our current long-term strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to 36 months.

Our Competitive Strengths

We believe we have the following competitive strengths that will support the execution of our business strategy:

•

Large inventory of drilling prospects. We have developed a significant inventory of future drilling locations, primarily in our well-established position in the Southeast Tarrant County area of the Barnett Shale. As of December 31, 2010, we owned leases covering approximately 162,000 net acres in our focus areas of the Barnett Shale and Marcellus Shale. At December 31, 2010, we had an inventory of 42 gross wells (21.0 net) in the Barnett Shale that had been drilled and were awaiting fracturing, completion or pipeline connection. Approximately 52% of our estimated proved reserves at December 31, 2010 were undeveloped and an additional 3% were developed, non-producing reserves. In addition, as part of our growth strategy in crude oil and liquid-rich plays, we owned over 61,000 net leasehold acres in the Niobrara and over 20,000 net leasehold acres in the Eagle Ford Shale at December 31, 2010.

•

Successful drilling history. We follow a disciplined approach to drilling wells by utilizing a 3-D seismic-driven exploratory and development drilling program and by applying proven horizontal drilling and hydraulic-fracturing technology. Since our entrance into the Barnett Shale in 2003, our drilling success rate has been 100%. Additionally, we rely on advanced technologies, including 3-D seismic analysis, to better define geologic risks, thereby enhancing the results of our drilling efforts.

•

Experienced management and professional workforce. We employ 36 oil and gas professionals, including geophysicists, petrophysicists, geologists, petroleum engineers and production and reservoir engineers and technical support staff, who have an average of over 18 years of experience. We believe our experience and expertise, particularly as they relate to successfully identifying and developing resource plays, is a competitive advantage.

•

Operational control. As of December 31, 2010, we operated approximately 66% of the wells in which we held an interest. Of those wells we operate, we hold an average interest of approximately 87%. Our significant operational control provides us with the flexibility to align capital expenditures with cash flow as we are generally able to adjust drilling plans in response to changes in commodity prices.

EXPLORATION APPROACH

Our exploration strategy in our shale resource plays has been to accumulate significant leasehold positions in areas with known shale thickness and thermal maturity in the proximity of known or emerging pipeline infrastructures. A component of our exploitation strategy, particularly in urban areas within the Barnett Shale, is to 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. We next acquire 3-D seismic data over these leases to assist in well placement and development optimization. Even in the relatively lower-risk, reserve-proven trends, such as the Barnett Shale, 3-D seismic data interpretation is instrumental in our development program, significantly reducing geologic risk and allowing optimal well paths and spacing. Finally, we form drilling units and utilize sophisticated horizontal drilling, multi-stage simultaneous fracing programs and micro-seismic techniques designed to maximize the production rate and recoverable reserves from a unit area. Primarily due to the continuing down-turn in natural gas prices, we seek to reduce costs by drilling more wells on units where we hold a lower working interest than our historic average. In addition, we seek to enter into joint ventures with well funded partners that will pay a disproportionate share of the drilling and completion costs of wells that we drill. In 2010, we sold 20% of our interests in our Pennsylvania properties to Reliance who agreed to pay 75% of certain of our drilling and completion costs up to approximately $52 million over the next two years. In 2009, we entered into a strategic alliance with a subsidiary of Sumitomo Corporation of Japan, wherein we sold to it a 12.5% working interest in 16 of our drilling units in the Barnett Shale. Sumitomo agreed to pay approximately 16.7% of the drilling and completion costs on future wells to earn the 12.5% working interest in the wells that we currently expect to drill in those units. In certain instances we also seek 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 timing the fracing, completion and pipeline connection costs of our horizontal wells to coincide with periods of lower services costs.

We strive to achieve a balance between acquiring acreage, seismic data (2-D and 3-D) and timely project evaluation through the drillbit to ensure that we minimize the costs to test for commercial reserves while building a significant acreage position. Our first exploration wells in these trends are frequently vertical wells because they allow us to evaluate thermal maturity and rock property data, while also permitting us to test various fracing and completion techniques without incurring the cost of drilling horizontal wells. As discussed above, we have shifted some of our focus toward liquids-rich plays to take advantage of the attractive economics associated with those commodities.

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.” We complement our exploratory drilling portfolio through the use of these outside sources of project generation and typically retain operator rights. Specific drill-sites are typically chosen by our own geoscientists or, in urban areas, are dictated by available leases.

OPERATING APPROACH

Our management team has extensive experience in the development and management of exploration and development projects in the Barnett Shale and along the Gulf Coast. We believe that the experience we have gained in the Barnett Shale, 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, onshore Gulf Coast and, more recently, the Marcellus Shale, Eagle Ford Shale and Niobrara, will play a significant part in our future success.

We generally seek to obtain lease operator status and control over field operations, and in particular seek to control decisions regarding 3-D survey design parameters and drilling and completion methods. As of December 31, 2010, we operated 346 gross (302.7 net) producing oil and gas wells. We generally seek to control operations for most new exploration and development taking advantage of our technical staff experience in horizontal drilling and hydraulic fracing. During 2010, we operated 46 of the 65 gross wells drilled in the Barnett Shale, one of the six gross wells drilled in the Marcellus Shale, three of the three gross wells drilled in the Eagle Ford Shale and the one gross well drilled in the Niobrara.

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 capital 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 allocated our capital expenditure plan to numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. Wells may currently be part of our capital expenditure plan 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 wells included in our capital expenditure plan 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 oil and gas 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 drill sites or wells included in our capital expenditure plan will, if drilled, encounter reservoirs of commercially productive oil or 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—Oil and gas drilling is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.”

Oil and Gas Reserves

The following table sets forth our estimated net proved oil and gas reserves and the PV-10 value of such reserves as of December 31, 2010. The reserve data and the present value as of December 31, 2010 were prepared by LaRoche Petroleum Consultants, Ltd., Ryder Scott Company Petroleum Engineers and Fairchild and Wells, Inc. For further information concerning these independent third party engineers’ estimates of our proved reserves at December 31, 2010, see the reserve reports included as exhibits to this Annual Report on Form 10-K. The PV-10 value was prepared using an unweighted arithmetic average of the first day of the month oil and gas

prices for each month in the prior twelve-month period ended December 31, 2010, discounted at 10% per annum on a pre-tax basis, and is not intended to represent the current market value of the estimated oil and gas reserves owned by us. For further information concerning the present value of future net revenues from these proved reserves, see Notes 2 and 14 of our Notes to Consolidated Financial Statements.

Summary of Oil and Gas Reserves as of December 31, 2010

Based on Average 2010 Prices

(Dollars in thousands)


	Oil, Condensate and Natural Gas Liquids (MBbls)		Natural Gas (MMcf)		Total (Mmcfe) (1)		PV-10 Value (2) (3)
U.S. Proved
Developed		7,388		358,543		402,869	$	574,822
Undeveloped		15,823		306,624		401,563		234,776

Total Proved		23,211		665,167		804,432		809,598


U.K. Proved
Developed		—		—		—		—
Undeveloped		5,263		4,684		36,263		193,985

Total Proved		5,263		4,684		36,263		193,985


Total Proved
Developed		7,388		358,543		402,869		574,822
Undeveloped		21,086		311,308		437,826		428,761

Total Proved		28,474		669,851		840,695	$	1,003,583

(1)	Natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil or natural gas liquids which represents their approximate relative energy content.

(2)

The PV-10 value as of December 31, 2010 is pre-tax and was determined by using the average of oil and gas prices at the beginning of each month in the twelve-month period prior to December 31, 2010, which averaged $72.13 per Bbl of oil, $35.18 per Bbl of natural gas liquids and $3.47 per Mcf of natural gas in the United States and $78.96 per Bbl of oil and $8.38 per Mcf of natural gas for the North Sea. Management believes that the presentation of PV-10 value may be considered a non-GAAP financial measure as defined in Item 10(e) of Regulation S-K. Therefore, we have included a reconciliation of the measure to the most directly comparable GAAP financial measure (standardized measure of discounted future net cash flows in footnote (3) below). Management believes that the presentation of PV-10 value provides useful information to investors because it is widely used by analysts and investors in evaluating oil and gas companies. Because many factors that are unique to each individual company may impact the amount of future income taxes to be paid, the use of the pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance of our oil and gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other oil and gas companies. Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and gas properties and in evaluating acquisitions. The PV-10 value is not a measure of financial or operating performance under GAAP, nor is it intended to represent the current market value of the estimated oil and gas reserves owned by us. PV-10 value should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

(3)	Future income taxes and present value discounted (10%) future income taxes were $543.6 million and $254.8 million, respectively. Accordingly, the after-tax PV-10 value of Total Proved Reserves (or standardized measure of discounted future net cash flows) is $748.8 million.

Proved Undeveloped Reserves

United States. At December 31, 2010 and 2009, we had 401.6 Bcfe and 267.8 Bcfe of proved undeveloped reserves, respectively. In 2010, we (a) added 211.0 Bcfe which included 124.4 Bcfe and 84.5 Bcfe of proved undeveloped reserves as a result of drilling and additional offset locations in the Barnett and Eagle Ford shales, respectively, (b) converted a net of 31.4 Bcfe of reserves from proved undeveloped to proved developed, substantially all of which were in the Barnett Shale, (c) increased previously estimated proved undeveloped reserves by a net 2.1 Bcfe based on operational performance and (d) removed 47.9 Bcfe of proved undeveloped reserves in the Barnett Shale due to a shift in future drilling priorities focusing more on drilling in the core of the Barnett Shale.

Costs incurred relating to the development of proved undeveloped reserves were approximately $35.9 million in 2010, as compared to $34.8 million in 2009. Costs incurred relating to the development of proved undeveloped reserves are currently projected to be approximately $152.0 million in 2011, $164.9 million in 2012, and $169.5 million in 2013. All proved undeveloped reserves drilling locations are scheduled to be drilled prior to the end of 2015. In 2009, in accordance with oil and gas reserve estimation and disclosure requirements that we adopted effective December 31, 2009, we removed 5.4 MMbls of oil reserves previously classified as proved in the Camp Hill Field that are not associated with wells that are expected to be both drilled prior to December 31, 2014 and into which we planned to inject steam prior to December 31, 2014. We added no additional proved reserves in the Camp Hill Field during 2010.

U.K. North Sea. At December 31, 2010 we had approximately 6.0 million BOE of proved undeveloped reserves which were added during the year as a consequence of our field development plan being approved by our joint venture and the U.K. Department of Energy and Climate Change in late 2010.

Other

Reserve Matters. 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.” All of our proved reserves are determined by independent third party engineers.

Our future oil and 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, LaRoche Petroleum Consultants, Ltd., Ryder Scott Company Petroleum Engineers and Fairchild and Wells, Inc. each used the price based on the unweighted average of oil and gas prices at the beginning of each month in the twelve-month period ended December 31, 2010, 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 gas production subsequent to December 31, 2010. 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 679.9 Bcfe, or 80.9% of our proved reserves, for the year ended December 31, 2010. Ryder Scott Company Petroleum Engineers determined 144.8 Bcfe, or 17.2% of our proved reserves, for the year ended December 31, 2010. Fairchild and Wells, Inc. determined 16.0 Bcfe, or 1.9% of our proved reserves, for the year ended December 31, 2010.

Qualifications of Third Party Engineers

As discussed above, we engaged LaRoche Petroleum Consultants, Ltd., Ryder Scott Company Petroleum Engineers and Fairchild and Wells, Inc., independent third party reserve engineers, to perform independent estimates of our proved reserves. The technical person responsible for review of our reserve estimates at each of these firms meets the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. None of these firms own an interest in our properties or is employed on a contingent fee basis.

Internal Controls

A significant component of our internal controls in our reserve estimation effort is our practice of using independent third-party reserve engineering firms to determine 100% of our year-end reserves. The qualifications of each of these firms are discussed above under “Qualifications of Third Party Engineers.”

Our internal reserve engineers are three individuals at the Company who are primarily responsible for reviewing the reserves estimates prepared by the Company’s third party engineering firms. Each of these individuals has over 25 years of experience in the petroleum industry and extensive experience in the estimation of reserves and the review of reserve reports prepared by third party engineering firms.

These three individuals along with other Company personnel, review the inputs and assumptions made in the reserve estimates prepared by the third party engineer firms and assess them for reasonableness. The reserve reports are also reviewed by senior management, including the Chief Executive Officer, who is a registered petroleum engineer and holds a B. S. in Mechanical Engineering from the University of Colorado and the Chief Operating Officer, who holds a B.S. in Petroleum Engineering from Texas A&M University.

Oil and Gas Reserve Replacement

Finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success. Given the inherent decline of hydrocarbon reserves resulting from production, 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. It is relevant to note the percentage of our reserves that were producing in the United States was 45% in 2010, 45% in 2009 and from 42% in 2008. Set forth below is our reserve replacement ratio for the years ended December 31, 2010, 2009 and 2008. We have no reserves that are producing in the UK North Sea.


	2010			2009			2008
U.S. Reserve Replacement Ratio		650	%		400	%		705	%
World-wide Reserve Replacement Ratio		749	%		400	%		705	%

Oil and Gas Volumes, Prices and Production 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 gas for the periods indicated.


	Year Ended December 31,
	2010		2009		2008
Production volumes
Oil (MBbls)		176		174		186
Natural gas (MMcf)(1)		35,751		32,002		24,513
Natural gas equivalent (MMcfe)		36,808		33,044		25,632
Average sales prices
Oil (per Bbl)	$	78.64	$	58.85	$	99.74
Natural gas (per Mcf)		3.48		3.20		7.80
Natural gas equivalent (per Mcfe)		3.75		3.41		8.19
Average costs (per Mcfe)(2)	$	0.52	$	0.91	$	1.28

(1)	Includes 1,659.2; 1,975.2 and 965.7 MMcfe of natural gas liquids in 2010, 2009 and 2008, respectively.

(2)	Includes direct lifting costs (labor, repairs and maintenance, materials and supplies), workover costs, transportation costs and the administrative costs of production offices, and insurance and property.

Acquisition, Exploration and Development Capital Expenditures and Finding and Development Costs

Our finding and development costs for the years ended December 31, 2010, 2009 and 2008 are reflected in the table below.


	Year Ended December 31,
	2010		2009			2008
	(In thousands, except MMcfe and per Mcfe amounts)

Unproved property acquisition costs	$	127,589	$	35,248		$	271,618
Exploration costs		139,862		77,255			235,382
Development costs		62,952		55,270			49,626
Asset retirement obligations		1,031		(1,390	)		630

Total costs incurred ⁽¹⁾	$	331,434	$	166,383		$	557,256

Total proved reserves added (MMcfe)		275,632		132,326			180,594

Average all-sources finding cost (per Mcfe)	$	1.20	$	1.26		$	3.09

Average finding and development cost (per Mcfe)⁽²⁾	$	0.95	$	1.16		$	1.68

Average drilling finding cost (per Mcfe)	$	0.74	$	0.99		$	1.58

(1)	Total costs incurred include capitalized overhead of $5.3 million, $5.6 million and $7.8 million and exclude capitalized interest on unproved properties of $20.7 million, $19.7 million and $20.5 million for the years ended December 31, 2010, 2009 and 2008, respectively.

(2)	Comprised of all exploration and development costs incurred in the year plus the leasehold and seismic costs attributable to all proved drilling locations additions in the year.

For the three year period ended December 31, 2010, our total cost for exploration, development and acquisition activities was approximately $1,055.1 million. Total exploration, development and acquisition activities for the three year period ended December 31, 2010 have added approximately 588.6 Bcfe of net proved reserves at an all-sources finding cost of $1.79 per Mcfe.

Our finding and development cost computation excludes net additions/(reductions) to total future development costs with respect to proved developed non-producing and proved undeveloped properties necessary to convert those properties into proved producing properties of $379.0 million, $(12.3) million, and $47.6 million at December 31, 2010, 2009 and 2008, respectively, and includes total

additions to proved undeveloped reserves of 170.0 Bcfe, 28.7 Bcfe and 53.3 Bcfe for the years ended December 31, 2010, 2009 and 2008, respectively. Accordingly, had we included future development costs in our computations, the average all-sources finding costs would have been $2.44, $1.16 and $3.35 per Mcfe for the years ended December 31, 2010, 2009 and 2008, respectively. Year on year, future development costs increased in 2010 by approximately $379.0 million net, largely comprised of (1) $267.5 million increase in the Eagle Ford Shale for the development costs attributable to an 14.1 MMBOE increase in proved undeveloped reserves (2) $78.4 million increase in the North Sea future development costs attributable to a 6.0 MMBOE increase in proved undeveloped reserves, and (3) a $31.0 million net increase in the Barnett Shale future development costs comprised of (a) an approximate $127.1 million increase in future development costs associated with the additions to proved developed non-producing and proved undeveloped reserves, (b) a net $(52.1) million reduction from proved undeveloped wells that are currently not in the drilling plan as we shift our drilling efforts to the core of the Barnett Shale, and (c) a net reduction of $(44.0) million for the development of proved non-producing and proved undeveloped wells during the year.

In order to maintain continued growth, 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 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.

Drilling Activity

The following table sets forth our drilling activity for the years ended December 31, 2010, 2009 and 2008 by geographical area. 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,
	2010				2009				2008
	Gross		Net		Gross		Net		Gross		Net
Exploratory Wells - Productive
United States		57		28.9		46		22.4		83		60.0
U.K. North Sea		—		—		—		—		1		0.2

Total		57		28.9		46		22.4		84.0		60.2

Exploratory Wells - Nonproductive
United States		3		2.3		1		0.8		2		0.3
U.K. North Sea		—		—		—		—		—		—

Total		3		2.3		1		0.8		2		0.3

Development Wells - Productive
United States		28		13.4		16		13.0		31		24.2
U.K. North Sea		—		—		—		—		—		—

Total		28		13.4		16		13.0		31		24.2

Development Wells - Nonproductive
United States		—		—		—		—		3		3.0
U.K. North Sea		—		—		—		—		—		—

Total		—		—		—		—		3		3.0

The wells are in various stages of development and/or stages of production.

As of December 31, 2010, we are in the process of drilling four gross (2.8 net) wells in the United States and evaluating six gross (5.4 net) wells that are waiting on completion in our new growth plays in the United States. These wells are not included in the table above.

Productive Wells

The following table sets forth the number of productive oil and gas wells in which we owned an interest as of December 31, 2010.


	Company Operated				Non-Operated				Total
	Gross		Net		Gross		Net		Gross		Net

Oil		95		89.8		4		0.8		99		90.7
Natural gas		251		212.9		171		37.7		422		250.5

Total		346		302.7		175		38.5		521		341.2

Acreage Data

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2010. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would permit production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves.


	Developed Acreage				Undeveloped Acreage				Total
	Gross		Net		Gross		Net		Gross		Net

Barnett Shale — Texas		37,682		25,595		30,571		19,215		68,253		44,810
Marcellus Shale
New York		2,117		158		35,393		7,900		37,510		8,058
Pennsylvania		1,222		313		135,755		49,133		136,977		49,446
West Virginia		801		389		116,304		52,996		117,105		53,385
Virginia and other		53		27		14,082		7,005		14,135		7,032

Marcellus Shale Total		4,193		887		301,534		117,034		305,727		117,921
Eagle Ford Shale - Texas		2,475		2,451		31,616		17,920		34,091		20,371
Niobrara Formation- Colorado		1,920		1,920		100,133		59,738		102,053		61,658
Other (1)		37,972		16,522		251,345		178,597		289,317		195,119
Total United States		84,242		47,375		715,199		392,504		799,441		439,879
Total U.K. North Sea		—		—		295,268		176,122		295,268		176,122

Total		84,242		47,375		1,010,467		568,626		1,094,709		616,001

(1)	“Other” principally includes other non-resource plays in Texas and Louisiana; the Camp Hill Field; Fayetteville Shale in Arkansas; the New Albany Shale in Kentucky and Illinois; the Floyd/Neal Shale in Mississippi; the Barnett/Woodford in West Texas and New Mexico; and the Bakken in North Dakota.

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). If no production is established on our leases that are in their primary term, approximately 33 % of our acreage will expire in 2011, 11% will expire in 2012 and 33% will expire in 2013. Substantially all of any acreage allowed to expire in 2011 is expected to relate to non-core acreage where we have limited remaining amounts of unproved property costs.

Marketing

Our production is marketed to third parties consistent with industry practices. Typically, our oil and gas is sold at the wellhead. Oil is sold at field-posted prices plus a bonus and natural gas is sold under contract at a negotiated price which is based on quoted prices for specified locations, such as WAHA or Houston Ship Channel, and then discounted back to the wellhead based upon a number of factors normally considered in the industry, such as distance from the well to the central sales point, well pressure, quality of natural gas and prevailing supply and demand conditions. We continued with the strategic decision, made in 2009, to sell as much of our natural gas production at the wellhead as possible, so that we could concentrate our efforts and resources on exploration and production which we believe are more consistent with our competitive expertise, rather than in natural gas pipeline operation, natural gas marketing and sales. As a consequence we, sold most of the pipelines that we owned in the Barnett Shale. In 2009, we also entered into an ordinary course gas purchase agreement with DTE Energy to purchase our natural gas at the wellhead from most of our operated properties in the Barnett Shale at competitive market prices based on a differential to several sales points in East Texas. We do not believe the loss of any one of our purchasers would materially affect our ability to sell the oil and gas we produce. We believe other purchasers are available in all our areas of operations.

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.

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

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demand for oil and gas;

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the extent of production of oil and gas and, in particular, domestic production and imports;

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the proximity and capacity of natural gas pipelines and other transportation facilities;

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the marketing of competitive fuels; and

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the effects of state and federal regulations on oil and gas production and sales.

See “Item 1A. Risk Factors—Oil and gas prices are highly volatile, and lower oil and gas 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.”

In addition to selling our oil and gas at the wellhead, we work with various pipeline companies to assure capacity for our natural gas. In late 2009, we entered into a strategic alliance with Delphi Midstream Partners LLC to provide gathering and midstream pipeline solutions for our future operated Marcellus Shale production in portions of Northern Pennsylvania. We also conduct an active hedging program in order to ensure stable cash flow to fund our exploration and production activities. 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 financial instruments to manage the price risks associated with our production. Our derivative financial instruments may result in our making cash payments or prevent us from benefiting from increases in prices for oil and gas” and “If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. Our ability to sell natural gas and/or receive market prices for our natural gas may be adversely affected by pipeline and gathering system capacity constraints.”

Competition and Technological Changes

We encounter competition from other oil and gas 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 oil and gas 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 oil and gas 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

Oil and gas operations are subject to various federal, state, local and international environmental regulations that may change from time to time, including regulations governing oil and gas 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 oil and gas 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 oil and gas, protect rights to produce oil and gas between owners in a common reservoir, control the amount of oil and gas 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:

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require permits for the drilling of wells;

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mandate that we maintain bonding requirements in order to drill or operate wells; and

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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 oil and gas properties and the unitization or pooling of oil and gas 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 oil and gas 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 oil and gas 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 oil and gas 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 is 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 existing infrastructure. In order to partly alleviate this issue, commencing in 2009, 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 crude 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 crude oil and natural gas 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 2010, or what the ultimate effect on our sales of oil, gas 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 oil and gas 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 oil and gas 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 oil and gas. 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 oil and gas 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 environmental risks and governmental regulations, including those relating to benzene emissions and hydraulic fracturing, and new regulations may be more stringent.”

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. Moreover, changes in environmental laws and regulations occur frequently, and stricter laws, regulations or enforcement policies could significantly increase our compliance costs. Further, stricter requirements could negatively impact our production and operations. For example, the Texas Commission on Environmental Quality (“TCEQ”) and the RRC have been

evaluating possible additional regulation of air emissions in the Barnett Shale area, in response to concerns about allegedly high concentrations of benzene in the air near drilling sites and natural gas processing facilities. These initiatives could lead to more stringent air permitting, increased regulation and possible enforcement actions at the local, state, and federal levels. Additionally, the EPA is currently considering, pursuant to a court-mandated settlement, whether to strengthen regulations under the CAA, including the New Source Performance Standards (“NSPS”), Maximum Achievable Control Technology (“MACT”) standards and residual risk standards, affecting a wide array of air emission sources in the oil and gas industry. Please read “Part II, Item 1A. Risk Factors — We are subject to various environmental risks and governmental regulations, including those relating to benzene emissions and hydraulic fracturing, and new regulations may be more stringent.”

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. Similarly, the U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by us and others in the oil and gas industry in the hydraulic fracturing process. Please read “Item 1A. Risk Factors — We are subject to various environmental risks and governmental regulations, including those relating to benzene emissions and hydraulic fracturing, and new regulations may be more stringent.”

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 our financial position or results of operations.

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

There is increasing attention in the United States and worldwide being paid to the issue of climate change and the contributing effect of greenhouse gas (“GHG”) emissions. On September 22, 2009, the EPA issued a “Mandatory Reporting of Greenhouse Gases” final rule (“Reporting Rule”) which was subsequently amended on July 20, 2010. The Reporting Rule establishes a new comprehensive scheme, beginning in 2011, requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions occurring in the prior calendar year on a facility-by-facility basis. On November 9, 2010, the EPA issued final rules applying these regulations to the oil and gas source category including oil and natural gas production facilities, natural gas processing, transmission, distribution and storage facilities. In addition, on December 15, 2009, the EPA published a Final Rule, also known as the EPA’s Endangerment Finding, finding that current and projected concentrations of six key GHGs in the atmosphere threaten the environment and public health and the welfare of current and future generations. Following issuance of the Endangerment Finding, the EPA promulgated final motor vehicle GHG emission standards under the CAA on April 1, 2010 that will require reduction in emissions of GHGs from motor vehicles beginning in 2011, the effect of which could reduce demand for motor fuels refined from crude oil. Also, on May 13, 2010, the EPA issued a prepublication version of a final rule to address permitting of GHG emissions from stationary sources under the CAA Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions, to be phased in through a multistep process, with the largest sources being the first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control

technology” standards, which will be established by the states or, in some instances, by the EPA on a case-by-case basis. In November 2010 EPA issued guidance on GHG best available control technology that will assist the various agencies in making these determinations. In addition, the U.S. Congress is currently considering a number of legislative proposals to restrict GHG emissions and more than 20 states, either individually or as part of regional initiatives, have begun taking actions to control and/or reduce GHG emissions. Moreover, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for GHGs, became binding on all those countries that had ratified it. International discussions are currently underway to develop an international scheme for the regulation and reduction of GHGs. While it is not possible at this time to predict how regulation that may be enacted to address GHG emissions would impact our business, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing oil and gas exploration in the areas of the United States or the North Sea in which we operate could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. In addition, existing or new laws, regulations or treaties (including incentives to conserve energy or use alternative energy sources) could have a negative impact on our business if such incentives reduce demand for oil and gas.

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 oil and gas 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 our assessment of 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 oil and gas operations.

Title to Properties; Acquisition Risks

We believe we currently have satisfactory title to all of our producing properties in the specific areas in which we operate except where failure to do so would not have a material adverse effect on our business and operations in each such area. 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 perform limited investigations 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 in conjunction with the 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 Revolving Credit Facility is secured by substantially all of our proved producing domestic oil and gas properties.

In acquiring producing properties, we assess the recoverable reserves, future domestic oil and gas 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 fully assess 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 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 gas production representing at least 10% of its oil and gas revenues as follows:


	Year Ended December 31,
	2010			2009			2008

DTE Energy Trading, Inc.		63	%		54	%		39	%
Cokinos Natural Gas Company			*			*		11	%
Crosstex Energy			*			*		10	%

*	Revenues were below 10%.

We do not believe the loss of any one of our purchasers would materially affect our ability to sell the oil and gas we produce. We believe other purchasers are available in our areas of operations. See “Additional Oil and Gas Disclosures – Marketing.”

Employees

At December 31, 2010, we had 132 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 read and copy any materials we file with the Commission at the Commission’s Public Reference Room at 1100 F Street, N.E., Washington, D.C. 20549. You may obtain information regarding the Public Reference Room by calling the Commission at 1-800-SEC-0330.

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:

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Audit Committee Charter;

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Compensation Committee Charter;

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Nominating Committee Charter;

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Code of Ethics and Business Conduct; and

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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 on our website at www.crzo.net under “About Carrizo Oil & Gas, Inc. — Governance.”

Item 1A.

Risk Factors

Oil and gas prices are highly volatile, and lower oil and gas prices will negatively affect our financial position, planned capital expenditures and results of operations.

At times since July 2008, publicly quoted spot natural gas and, to a lesser extent, oil prices reached levels significantly lower than the record levels reached at that time. In the past, some oil and gas companies have reduced or curtailed production to mitigate the impact of low oil and gas prices. We have made similar decisions on selected properties in the recent past and may decide to curtail additional production as a result of a decrease in prices in the future. The decrease in natural gas prices has had a significant impact on our financial position, planned capital expenditures and results of operations. Further volatility in oil and gas prices or a prolonged period of low oil and gas prices may materially adversely affect our financial position, liquidity (including our borrowing capacity under our Revolving 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 oil and gas. Historically, the markets for oil and gas have been volatile, and those markets are likely to continue to be volatile in the future. It is impossible to predict future oil and gas price movements with certainty. Prices for oil and gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond our control. These factors include:

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the level of consumer product demand;

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overall economic conditions;

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weather conditions;

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domestic and foreign governmental relations, regulations and taxes;

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the price and availability of alternative fuels;

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political conditions and unrest in oil producing regions;

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the level and price of foreign imports of oil and liquefied natural gas; and

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the ability of the members of the Organization of Petroleum Exporting Countries to agree upon and maintain production constraints and oil price controls.

Oil and gas 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 oil and gas involves numerous risks, including the risk that no commercially productive oil or gas 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:

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unexpected or adverse drilling conditions;

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elevated pressure or irregularities in geologic formations;

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equipment failures or accidents;

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adverse weather conditions;

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compliance with governmental requirements; and

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shortages or delays in the availability of drilling rigs, crews and equipment.

Because we identify the areas desirable for drilling in certain areas 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 oil or gas 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 position by reducing our available cash and resources. The potential for production decline rates for our wells could be greater than we expect. 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:

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the results of our exploration efforts and the acquisition, review and analysis of the seismic data;

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the availability of sufficient capital resources to us and the other participants for the drilling of the prospects;

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the approval of the prospects by the other participants after additional data has been compiled;

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economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and gas and the availability and prices of drilling rigs and crews; and

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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 plan 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.

Instability in the global financial system may have impacts on our liquidity and financial condition that we currently cannot predict.

Instability 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 continue to improve from their lows in early 2009. 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 oil and gas derivative instruments 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 oil and gas, or further reductions in the prices of oil and gas, 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 situation cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial position.

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 oil and gas reserves and their estimated value, including many factors beyond the control of the producer. The reserve data in this annual report represents only estimates. Reservoir engineering is a subjective and inexact process of estimating underground accumulations of oil and gas 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. In late 2008, the SEC adopted new rules regarding the classification of reserves. We adopted these oil and gas reserve estimation and disclosure requirements effective December 31, 2009 and, accordingly, the requirements became effective with the reserves reported in our Annual Report on Form 10-K for the year ended December 31, 2009. However, the interpretation of these rules and their applicability in different situations remain unclear in many respects. Changing interpretations of the classification standards or disagreements with our interpretations could cause us to write-down reserves.

As of December 31, 2010, approximately 55% 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, 2010 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 reasonable certainty with respect to development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.

The discounted future net cash flows in this annual report are not necessarily the same as the current market value of our estimated oil and gas reserves. As required by the current requirements for oil and gas reserve estimation and disclosures, the estimated discounted future net cash flows from proved reserves are based on the average of the sales price on the first day of each month in the applicable year, with costs determined as of the date of the estimate. Actual future net cash flows also will be affected by factors such as:

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the actual prices we receive for oil and gas;

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our actual operating costs in producing oil and gas;

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the amount and timing of actual production;

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supply and demand for oil and gas;

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increases or decreases in consumption of oil and gas; and

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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 Accounting Standards Codification Topic 932, “Extractive Activities—Oil and Gas” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.

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

In general, the volume of production from oil and gas 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 oil and gas 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 gas leases with third parties and these third parties may not be able to fulfill their commitments to our projects.

We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations, 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 volatility in oil and gas 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. Some of our project partners have experienced 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, 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 position.

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 Revolving Credit Facility or new credit facilities may not be available in the future. Even if additional capital becomes available, it may not be on terms acceptable to us. As in the past, without additional capital resources, we may be forced to limit or defer our planned oil and gas 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 oil and gas properties, in turn negatively affecting our business, financial position and results of operations.

The risks associated with our debt and the provisions of our debt agreements could adversely affect our business, financial position and results of operations.

We have demands on our cash resources, including interest expense, operating expenses and funding of our capital expenditures. Our level of debt, the demands on our cash resources and the provisions of our Revolving Credit Facility, the Huntington Facility, our Convertible Senior Notes and our Senior Notes may have adverse consequences on our operations and financial results, including:

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placing us at a competitive disadvantage compared to our competitors that have lower debt service obligations and significantly greater operating and financial flexibility than we do;

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limiting our financial flexibility, including our ability to borrow additional funds, pay dividends, make certain investments and issue equity on favorable terms or at all;

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limiting our flexibility in planning for, and reacting to, changes in business conditions;

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increasing our interest expense on our variable rate borrowings if interest rates increase;

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requiring us 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;

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requiring 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, which may be on unfavorable terms; and

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making us more vulnerable to downturns in our business or the economy.

In addition, the provisions of our Revolving Credit Facility, the Huntington Facility and our Senior Notes place restrictions on us and certain of our subsidiaries with respect to incurring additional indebtedness and liens, making dividends and other payments to shareholders, repurchasing or redeeming our common stock, redeeming our senior notes, making investments, acquisitions, mergers

and asset dispositions, entering into hedging transactions and other matters. Our Revolving Credit Facility and the Huntington Facility also require that specified financial ratios be maintained. Although we currently believe that all of these financial covenants can be met with the business plan that we have put in place, our business plan and our compliance with these covenants are based on a number of assumptions, the most important of which is relatively stable natural gas prices 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 Revolving Credit Facility, including the covenants related to working capital and the ratios described above. Pursuant to the Revolving Credit Facility, we are subject to financial ratio covenants which include, but are not limited to, the maintenance of the following financial covenants: (1) a total net debt to Consolidated EBITDA (as defined in the Revolving Credit Facility) ratio of not more than (a) 4.75 to 1.00 for any fiscal quarter ending on or after March 31, 2011 and on or before December 31, 2011, (b) 4.25 to 1.00 for any fiscal quarter ending on or after March 31, 2012 and on or before June 30, 2012 and (c) 4.00 to 1.00 for any fiscal quarter ending on or after September 30, 2012; (2) a current ratio of not less than 1.0 to 1.0; (3) a senior debt to EBITDA ratio of not more than 2.50 to 1.00; and (4) an EBITDA to interest expense ratio of not less than 2.50 to 1.00. In order to provide a further margin of comfort with regard to these financial covenants, we may seek to further reduce our capital expenditure plan, sell additional non-strategic assets or opportunistically modify or increase our derivative instruments to the extent permitted under our Revolving Credit Facility. We cannot assure you 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 Revolving Credit Agreement if a precipitous decline in natural gas prices were to occur in the future.

The borrowing base under our Revolving Credit Facility and the borrowing base under the Huntington Facility may be reduced below the amount of borrowings outstanding under those facilities.

Under the terms of our Revolving Credit Facility, our borrowing base is subject to redeterminations at least semi-annually based in part on prevailing oil and gas prices. A negative adjustment could occur if the estimates of future prices used by the banks in calculating the borrowing base are significantly lower than those used in the last redetermination. The next redetermination of our borrowing base is scheduled to occur in May 2011. The portion of our borrowing base made available to us is subject to the terms and covenants of the Revolving Credit Facility including, without limitation, compliance with the ratios and other financial covenants of such facility. In the event the amount outstanding under our Revolving Credit Agreement 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.

Under the terms of the Huntington Facility, availability under each of the term loan facility and the cost overrun facility are subject to borrowing bases that are generally based on consolidated cash flow and debt service projections for Carrizo UK. These borrowing bases are subject to redetermination at least semi-annually, with the next redetermination of the borrowing bases scheduled to occur in May 2011. In the event the outstanding principal balance under the Huntington Facility term loan facility and cost overrun facility exceeds the aggregate borrowing base for such facility at any time as a result of a redetermination of such facility’s borrowing base, Carrizo UK will be obligated to make a payment to cure the deficiency within five business days. Carrizo UK may not have sufficient funds to make any required repayment. If Carrizo UK does not have sufficient funds and is otherwise unable to negotiate renewals of its borrowings or arrange new financing., it may default under the Huntington Facility.

We have in the past identified material weaknesses in our internal controls over financial reporting, and the identification of any material weaknesses in the future could affect our ability to ensure timely and accurate financial statements.

At the end of several periods during the last five years, our management identified material weaknesses in our internal controls over financial reporting. The Public Company Accounting Oversight Board has defined a material weakness as a control deficiency, or combination of control deficiencies, that results in a reasonable possibility that a material misstatement of the annual or interim statements will not be prevented or detected on a timely basis. Accordingly, a material weakness increases the risk that the financial information we report contains material errors.

Although we have taken actions to remediate the past material weaknesses in our internal controls over financial reporting, these measures may not be sufficient to ensure that our internal controls are effective in the future. In addition, our history of material weaknesses, any future material weaknesses, or any failure to effectively address a material weakness or other control deficiency or implement required new or improved controls, or difficulties encountered in their implementation, could limit our ability to obtain financing, harm our reputation, disrupt our ability to process key components of our results of operations and financial position timely and accurately and cause us to fail to meet our reporting obligations under rules of the SEC and NASDAQ Stock Market LLC and our various debt arrangements.

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 December 31, 2010, we have participated or are participating in the drilling of only 16 gross (3.6 net) wells in the Marcellus Shale area. Other operators in the Appalachian Basin have significantly more experience in the drilling of Marcellus Shale wells, including the drilling of horizontal wells. 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 and community interest groups, regulatory agencies and other governmental entities. As a result, we may face significant opposition to, or increased regulation of, our operations that may make it difficult or impossible to obtain permits and other needed authorizations to operate, result in operational delays, or otherwise make operating more costly or difficult than operating elsewhere.

If we are unable to acquire adequate supplies of water for our Marcellus Shale drilling operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules, our ability to produce gas commercially and in commercial quantities could be impaired.

As with all of our resource plays, we use a substantial amount of water in our Marcellus Shale drilling operations. Our inability to locate sufficient amounts of water, or treat and dispose of water after drilling, could adversely impact our Marcellus Shale operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Furthermore, future environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse affect on our operations and financial performance.

We may not increase our acreage positions in areas with exposure to oil, condensate and natural gas liquids.

If we are unable to increase our acreage position in the Niobrara or Eagle Ford Shale, this may detract from our efforts to realize our growth strategy in crude oil and liquids-rich plays, which was announced in April 2010. Additionally, we may be unable to find or consummate other opportunities in these areas or in other areas with similar exposure to oil, condensate and natural gas liquids on similar terms or at all.

We have limited experience drilling wells in the Niobrara and in the Eagle Ford Shale and less information regarding reserves and decline rates in these shale formations than in other areas of our operations.

We have limited exploration and development experience in the Niobrara and in the Eagle Ford Shale. We have participated in the drilling of three horizontal gross (3.0 net) wells in the Niobrara and have participated in five horizontal gross (5.0 net) wells in the Eagle Ford Shale. Other operators in these areas have significantly more experience in the drilling of wells, including the drilling of horizontal wells. As a result, we have less information with respect to the ultimate recoverable reserves, the production decline rate and other matters relating to the exploration, drilling and development of the Niobrara and the Eagle Ford Shale than we have in other areas in which we operate.

A substantial portion of our reserves is located in an urban area, which could increase our costs of development and delay production.

Our current primary core producing area is located in largely urban portions of the Barnett Shale, which could disproportionately expose us to operational and regulatory risk in that area. At December 31, 2010, approximately 81% of our proved reserves and approximately 87% of our then current production were located in the Barnett Shale. The core of the Barnett Shale is located in and around the greater Dallas-Fort Worth, Texas metropolitan area and much of our operations are within the city limits of various municipalities in that region, such as Arlington and Mansfield, Texas. In such urban or other populated areas, we may incur additional expenses, including expenses relating to mitigation of noise, odor and light that may be emitted in our operations, expenses related to the appearance of our facilities and limitations regarding when and how we can operate. The process of obtaining permits for drilling or for gathering lines to move our natural gas to market in such areas may be more time consuming and costly than in more rural

areas. In addition, we may experience a higher rate of litigation or increased insurance and other costs related to our operations or facilities in such highly populated areas.

We face strong competition from other oil and gas companies.

We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of exploratory prospects and proven properties. Our competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established companies that have been engaged in the oil and gas 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 oil and gas 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 oil and gas 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 oil and gas 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 environmental risks and governmental regulations, including those relating to benzene emissions and hydraulic fracturing, and future regulations may be more stringent.

Oil and gas operations are subject to various federal, state, local and foreign laws and 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 oil and gas wells below actual production capacity in order to conserve supplies of oil and gas. Other federal, state, local and foreign 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 oil and gas, by-products thereof and other substances and materials produced or used in connection with oil and gas operations, including drilling fluids and wastewater. In addition, we may incur costs arising out of property damage, including environmental damage caused by previous owners or operators of property we purchase or lease or relating to third party sites, or injuries to employees and other persons. 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 result in substantial costs, delay our operations or otherwise have a material adverse effect on our business, financial position and results of operations.

Moreover, changes in environmental laws and regulations occur frequently and such laws and regulations tend to become more stringent over time. Stricter laws, regulations or enforcement policies could significantly increase our compliance costs and negatively impact our production and operations. For example, the TCEQ and the RRC have been evaluating possible additional regulation of air emissions in the Barnett Shale area, in response to concerns about allegedly high concentrations of benzene in the air near drilling sites and natural gas processing facilities. These initiatives, or other similar initiatives, could lead to more stringent air permitting, increased regulation and possible enforcement actions at the local, state, and federal levels. Additionally, the EPA is currently evaluating, pursuant to a court-mandated settlement, whether to adopt measures to strengthen certain regulations under the CAA, including the NSPS, MACT and residual risk standards, affecting a wide array of air emission sources in the oil and gas industry. If these or other initiatives result in an increase in regulation, it could increase our costs or reduce our production, which could have a material adverse effect on our results of operations and cash flows.

Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays like the Barnett Shale, the Marcellus Shale, the Eagle Ford Shale and the Niobrara. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas production. The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by us and others in the oil and gas industry in the hydraulic fracturing process. Sponsors of bills currently pending before the U.S. Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers and service providers. In addition, these bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating and compliance costs and additional regulatory burdens that could make it more difficult or commercially impracticable for us to perform hydraulic fracturing, delaying the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing. Additionally, the EPA has commenced a comprehensive research study to investigate the potential adverse environmental impacts of hydraulic fracturing, including on water quality and public health, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. The initial EPA study results are expected to be available in late 2012. Further, in light of the explosion and fire on the drilling rig Deepwater Horizon in the Gulf of Mexico, as well as recent incidents involving the release of natural gas and fluids as a result of drilling activities in the Marcellus Shale, there have been a variety of regulatory initiatives at both the federal and state levels to restrict oil and gas drilling operations in certain locations. For example, the New York legislature recently approved a temporary moratorium on drilling involving hydraulic fracturing and the Governor of Pennsylvania has instituted a moratorium on leasing state forest land for gas drilling. Additionally, the New York State Department of Environmental Conservation has ceased issuing exploration and production drilling permits, pending completion of an environmental impact statement regarding hydraulic fracturing, and the U.K. and EU Parliaments have each discussed implementing a drilling moratorium in the U.K. North Sea. We use hydraulic fracturing extensively and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or offshore drilling, including legislation and regulation in the states of New York and Pennsylvania, could reduce the volumes of oil and gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.

President Obama’s 2011 Fiscal Year Budget includes proposals that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production companies. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial position and results of operations.

Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and gas that we produce.

There is increasing attention in the United States and worldwide being paid to the issue of climate change and the contributing effect of GHG emissions. The EPA has issued a prepublication version of a final rule to address permitting of GHG emissions from stationary sources. In addition, the U.S. Congress is currently considering a number of legislative proposals to restrict GHG emissions and more than 20 states, either individually or as part of regional initiatives, have begun taking actions to control and/or reduce GHG emissions. While it is not possible at this time to predict how regulation that may be enacted to address GHG emissions would impact our business, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing oil and gas exploration in the areas of the United States or the North Sea in which we operate could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. In addition, existing or new laws, regulations or treaties (including incentives to conserve energy or use alternative energy sources) could have a negative impact on our business if such incentives reduce demand for natural gas. See “Item 1. and Item 2. Business and Properties—Additional Oil and Gas Disclosures – Regulation; Global Climate Change” for additional information.

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

The oil and gas business involves operating hazards such as:

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well blowouts;

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mechanical failures;

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explosions;

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uncontrollable flows of oil, natural gas or well fluids;

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fires;

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geologic formations with abnormal pressures;

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pipeline ruptures or spills;

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releases of toxic gases; and

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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 in addition to the hazards described above, such as capsizing, collisions and damage or loss from adverse weather conditions. Additionally, the occurrence of other events such as blowouts and oil spills in marine environments can make containment and remediation more difficult and costly than on land. These conditions can and have caused substantial damage to facilities and interrupted 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. Additionally, offshore operations generally involve increased costs and more expansive regulatory requirements as compared to onshore 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, losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot insure fully against pollution and environmental risks. 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. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

We conduct a substantial portion of our operations through joint ventures, which subject us to additional risks that could have a material adverse effect on the success of these operations, our financial position and our results of operations.

We conduct a substantial portion of our operations through joint ventures with third parties, including ACP II, Reliance and an affiliate of Sumitomo Corporation. We may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture and to pay their share of capital and other costs of the joint venture. The performance of these third party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside our control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely affected.

Our joint venture arrangements may involve risks not otherwise present when exploring and developing properties directly, including, for example:

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our joint venture partners may share certain approval rights over major decisions;

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our joint venture partners may not pay their share of the joint venture’s obligations, leaving us liable for their shares of joint venture liabilities;

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we may incur liabilities as a result of an action taken by our joint venture partners;

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our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives; and

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disputes between us and our joint venture partners may result in delays, litigation or operational impasses.

The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to transact the business that is the subject of such joint venture, which would in turn negatively affect our financial condition and results of operations.

Our joint venture with Reliance contemplates that we will make significant capital expenditures and subjects us to certain legal and financial terms that could adversely affect us.

In 2010, we completed the sale to Reliance of 20% of our interests in oil and gas properties in parts of Pennsylvania in the Marcellus Shale for approximately $13.1 million in cash and the Carry Commitment. At that time, we entered into agreements with Reliance to form a new joint venture with respect to the interests being purchased by Reliance from us and ACP II such that we generally retained a 40% working interest in the acreage and Reliance generally owns a 60% working interest.

The agreements under which we formed this joint venture subject us to various risks, limit the actions we may take with respect to our properties and require us to grant rights to Reliance that could limit our ability to benefit fully from future positive developments. The joint venture requires us to make significant capital expenditures. If we do not timely meet our financial commitments or otherwise do not comply with our joint venture agreements, our rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture will be adversely affected.

Reliance’s obligation to fund the Carry Commitment expires with respect to any portion of the Carry Commitment not utilized by September 10, 2012, subject to certain extensions. We have agreed to various restrictions on our ability to transfer our properties covered by the joint venture. Additionally, following the expiration of the Carry Commitment, we are subject to a mutual right of first offer on direct and indirect property transfers for the remainder of a ten-year development period (through September 2020), subject to specified exceptions. We have also granted an option to Reliance to purchase a 60% (as adjusted over time) share of acreage in the area of mutual interest purchased directly or indirectly by us after the closing. This option, which covers substantially all of Pennsylvania, is exercisable at our cost plus, in the case of direct property sales, a specified premium, and is subject to specified exceptions. We serve as operator of the properties covered by this joint venture, with Reliance having the right to assume operatorship of 60% of the undeveloped acreage in portions of central Pennsylvania beginning as early as September 2011 and, for a three-year period (through September 2013), to purchase all of our 40% interest in such acreage at a specified price. Operations under the joint venture will generally be required to conform to a budget approved by an operating committee that includes representatives of both parties, subject to exceptions, including those for sole risk operations and in the event of defaults by the parties. The parties have also generally agreed until 2013 to forego the ability to conduct sole risk operations and to certain other limits to such operations thereafter. Reliance has substantially greater financial resources than we have and we may not be able to secure the funding necessary to participate in operations Reliance proposes, thereby reducing our ability to benefit from the joint venture.

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;

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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.

If our access to markets is restricted, it could negatively impact our production, our income and ultimately our ability to retain our leases. Our ability to sell natural gas and/or receive market prices for our natural gas may be adversely affected by pipeline and gathering system capacity constraints.

Market conditions or the unavailability of satisfactory oil and gas transportation arrangements may hinder our access to oil and gas markets or delay our production. The availability of a ready market for our oil and gas production depends on a number of factors, including the demand for and supply of oil and gas and the proximity of reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms could materially harm our business. Our productive properties may be located in areas with limited or no access to pipelines, thereby necessitating delivery by other means, such as trucking, or requiring compression facilities. Such restrictions on our ability to sell our oil or gas may have several adverse affects, including higher transportation costs, fewer potential purchasers (thereby potentially resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an extended time, possibly causing us to lose a lease due to lack of production. There is currently only limited pipeline and gathering system capacity in the Marcellus Shale and, to a lesser extent, the Barnett Shale. In the Barnett Shale area, we have several wells that have been drilled and fractured and are awaiting connection to gas gathering systems. At times, our midstream partner in this area has reported scheduling delays in connecting these wells, which has delayed our additional production. In addition, delays in upgrading this system in the past have led to increased back pressure at our wells, further contributing to decreased deliverability from them.

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 and the Marcellus Shale, we have entered into firm transportation agreements for a portion of our production in the Barnett Shale and Marcellus Shale in order to assure our ability, and that of our purchasers, to successfully market the gas that we produce. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements are more costly than interruptible or short-term transportation agreements.

If production in the Marcellus Shale by oil and gas companies continues to expand, the amount of natural gas being produced by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently available in these areas. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the current economic climate, certain pipeline projects that are planned for the Marcellus Shale may not occur for lack of financing. In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas to interstate pipelines. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell natural gas production at significantly lower prices than those we currently project, which could materially and adversely affect our results of operations.

A portion of our oil and gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flow.

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

In acquiring producing properties, we assess the recoverable reserves, future oil and gas 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 position 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 also 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 position and results of operations. Our ability to grow will depend on a number of factors, including:

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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;

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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;

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our ability to maintain or enter into new relationships with project partners and independent contractors;

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the results of our drilling program;

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hydrocarbon prices; and

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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 position 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 oil and gas.

Because oil and gas prices are unstable, we periodically enter into price-risk-management transactions such as fixed-rate swaps, costless collars, puts, calls and basis differential swaps to reduce our exposure to price declines associated with a portion of our oil and gas 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 oil and gas. Our derivative arrangements may apply to only a portion of our production, thereby providing only partial protection against declines in oil and gas 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 oil and gas or a sudden, unexpected event materially impacts oil or gas 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 gas properties.

During periods when oil and gas prices are relatively high, 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 impairments of oil and gas properties that would reduce our shareholders’ equity.

We use the full cost method of accounting for our oil and gas properties. Accordingly, we capitalize all productive and nonproductive costs directly associated with property acquisition, exploration and development activities to cost centers established on a country-by-country basis. Under the full cost method, the capitalized cost of oil and gas properties, less accumulated amortization and related deferred income taxes may not exceed the “cost center ceiling” which is equal to the sum of the present value of estimated future net revenues from proved reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, plus the costs of properties not subject to amortization, plus the lower of the cost or estimated fair value of unproved properties included in the costs being amortized, less related income tax effects. If the net capitalized costs exceed the cost center ceiling, we recognize the excess as an impairment of oil and gas properties. This impairment does not impact cash flows from operating activities but does reduce our earnings and shareholders’ equity. The risk that we will be required to recognize impairments of our oil and gas properties increases during periods of low oil and/or gas prices. In addition, impairments 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 under “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.” An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period. We recorded non-cash impairments of oil and gas properties at the end of 2008, the end of the first quarter of 2009 and the end of 2009 with respect to our U.S. cost center and at the end of the second quarter of 2010 with respect to our U.K. cost center. We could incur additional impairments of oil and gas properties in the future, particularly as a result of a decline in oil and/or gas prices.

We could lose our ability to use NOLs that we have accumulated over the years.

Our ability to utilize NOL carryforwards to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of our stock by 5% shareholders and our offering of stock during any three-year period resulting in an aggregate change of more than 50% in our beneficial ownership. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (a) the fair market value of our equity multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. As of December 31, 2010, we believe an ownership change occurred in February 2005 with an annual limitation of approximately $12.6 million. Moreover, based on our knowledge of our shareholder ownership, we do not believe that an ownership change has occurred since February 2005 that would further limit our ability to utilize our NOLs. Because our pre-change NOLs are approximately $9.8 million, we do not believe we have a Section 382 limitation on our ability to utilize our NOL carryforwards as of December 31, 2010. Future equity transactions involving the Company or 5% shareholders of the Company (including, potentially, relatively small transactions and transactions beyond our control) could cause further ownership changes and therefore a limitation on the annual utilization of NOLs.

Enactment of a Pennsylvania severance tax on natural gas could adversely impact our results of operations and the economic viability of exploiting natural gas drilling and production opportunities in Pennsylvania.

Legislation has been proposed in the Pennsylvania House of Representatives for the adoption of a severance tax on the production of natural gas in Pennsylvania. The amount of the proposed tax, which has been supported by the governor, is 5% of the value of the natural gas at wellhead, plus 4.6 cents per 1,000 cubic feet of natural gas severed. The specific characteristics, including the scope and magnitude, of the tax have not been determined. A substantial portion of our Marcellus Shale acreage is located in the Commonwealth of Pennsylvania. If Pennsylvania adopts such a severance tax, it could adversely impact our results of operations and the economic viability of exploiting natural gas drilling and production opportunities in Pennsylvania.

We may incur losses as a result of title deficiencies.

We purchase working and revenue interests in the oil and gas 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 oil and gas 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 oil and gas 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:

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currency restrictions and exchange rate fluctuations;

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loss of revenue, property and equipment as a result of expropriation, nationalization, war or insurrection;

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increases in taxes and governmental royalties (including, by way of illustration, the recently announced potential U.K. production tax increases discussed below under “The recently-announced U.K. Budget 2011 includes a production tax increase that could have a material adverse effect on the results of our North Sea operations”);

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renegotiation of contracts with governmental entities and quasi-governmental agencies;

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changes in laws and policies governing operations of foreign-based companies;

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labor problems; and

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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 recently-announced U.K. Budget 2011 includes a production tax increase that could have a material adverse effect on the results of our North Sea operations.

On March 23, 2011, the U.K. Chancellor of the Exchequer introduced the U.K. Budget 2011. The U.K. Budget 2011 includes a production tax increase, raising the existing supplementary charge levied on profits from North Sea oil and gas production from 20%

to 32%, with effect from March 24, 2011. This charge is in addition to applicable corporation taxes. If the U.K. Budget 2011 is adopted, it will increase the tax burden on our U.K. production in the future and could have a material adverse effect on the results of our North Sea operations.

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

A 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. See “We may not have enough insurance to cover all of the risks we face.”

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. 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. Despite holding this ratio constant at six Mcf to one Bbl, 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.

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

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry well, the reporting to the appropriate authority that the well has been abandoned.

Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed acreage. The number of acres assignable to productive wells.

Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. This definition has been abbreviated from the applicable definition contained in Rule 4-10(a)(6) of Regulation S-X.

Development Costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. Development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are incurred to (i) gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building and relocating public roads, gas lines and power lines, to the extent necessary in developing the proved reserves, (ii) drill and equip development wells, development-type stratigraphic test wells and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly, (iii) acquire, construct and install, production facilities such as leases, flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems, and (iv) provide improved recovery systems.

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

Dry well. An exploratory, development or extension well that proves to be incapable of producing either natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well.

Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in Rule 4-10(a)(16) of Regulation S-X.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of natural gas or oil in another 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.”

Fracing. Fracing is the process of hydraulic fracture stimulation using a liquid (usually water) that is forced into an underground formation under high pressure and a proppant (usually sand or ceramics) to “prop” open the fracture after they are opened by the liquid, on reservoirs with low permeability to stimulate and improve the flow of hydrocarbons from these reservoirs. Fracing is an essential technology in shale reservoirs and other unconventional resource plays where nearly all wells are frac’d in order to produce commercial hydrocarbon production.

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. The geological terms “structural feature” and “stratigraphic condition” are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas of interest, etc.

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. Despite holding this ratio constant at six Mcf to one Bbl, 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.

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

MMBOE. One million barrels of oil equivalent. See definition of BOE.

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. See definition of Mcfe.

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 determined in accordance with Commission guidelines, 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%.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities.

Productive well. A well that is found to be capable of producing natural gas or oil in sufficient quantities to justify completion as a natural gas or oil well.

Proved developed reserves. Reserves that are both proved and developed.

Proved reserves. Has the meaning given to such term in Rule 4-10(a)(22) of Regulation S-X, which defines proved reserves as:

The quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

The area of a reservoir considered proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves that can be produced economically, based on prices used to estimate reserves, through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves. Reserves that are both proved and undeveloped.

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%.

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

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

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

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 economic quantities of oil or gas regardless of whether such acreage contains proved reserves.

Undeveloped oil and gas reserves. Reserves of any category 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.

(i) Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility, based on pricing used to estimate reserves, at greater distances.

(ii) Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances are estimates for undeveloped reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.

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.

Reserved

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	55	President, Chief Executive Officer and Director
J. Bradley Fisher	50	Vice President and Chief Operating Officer
Paul F. Boling	57	Chief Financial Officer, Vice President, Secretary and Treasurer
David L. Pitts	44	Vice President and Chief Accounting Officer
Gregory E. Evans	61	Vice President of Exploration
Richard H. Smith	53	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.

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.

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.

David L. Pitts has served as Vice President and Chief Accounting Officer since January 2010. Prior to that time, he served as an audit partner with Ernst & Young. Prior to his employment at Ernst &Young from 2002 to 2009, David was a senior manager with Arthur Andersen. Mr. Pitts is a CPA and holds a B.S. from Southwest Baptist 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
2009
First Quarter	$	21.19	$	6.71
Second Quarter		23.21		8.42
Third Quarter		26.85		14.75
Fourth Quarter		30.22		20.20
2010
First Quarter	$	28.85	$	21.17
Second Quarter		25.23		15.20
Third Quarter		24.25		14.81
Fourth Quarter		34.78		22.82

The closing market price of our common stock on March 25, 2011 was $36.06 per share. As of March 25, 2011, there were an estimated 170 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 Revolving 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, 2005 to December 31, 2010, 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, 2005 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.

LOGO


	S&P		AMEX		COGI
December 31, 2005		100		100		100
December 31, 2006		114		114		117
December 31, 2007		118		118		222
December 31, 2008		72		72		65
December 31, 2009		89		89		107
December 31, 2010		101		101		140

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 2010.

As described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources,” we have issued, and may issue, warrants and common stock under the land agreement In issuing any warrants and common stock (including common stock underlying the warrants) under the land agreement, we will rely on the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended, for transactions not involving a public offering. Under the Land Agreement, we issued warrants to purchase 57,461 shares of common stock in 2010, warrants to purchase 8,297 shares of common stock on February 1, 2011 and warrants to purchase 10,311 shares of common stock on March 4, 2011. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Lease Option Arrangements” for more information about these warrants, including the conversion prices.

Item 6.

Selected Financial Data

Our financial information set forth below for each of the five years in the period ended December 31, 2010, 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,
	2010			2009			2008			2007			2006
	(In thousands, except per share data)
Statements of Operations Data:
Total revenues	$	139,462		$	114,079		$	216,677		$	125,789		$	82,945
Costs and expenses:
Oil and gas operating expenses		31,017			30,204			37,885			24,662			16,428
Impairment of oil and gas properties		2,731			338,914			178,470			—			—
Depreciation, depletion and amortization		47,030			52,005			58,311			41,899			31,129
Gas purchases		1,336			1,497			6,570			—			—
General and administrative		35,906			30,136			23,425			18,912			14,909
Accretion expense related to asset retirement obligations		216			308			154			374			496

Total costs and expenses		118,236			453,064			304,815			85,847			62,962

Operating income (loss)		21,226			(338,985	)		(88,138	)		39,942			19,983
Gain (loss) on derivative instruments, net		47,782			41,465			37,499			(1,366	)		16,457
Loss on extinguishment of debt		(31,023	)		—			(5,689	)		—			(294	)
(Impairment) recovery of investment in
Pinnacle Gas Resources, Inc.		165			(2,091	)		—			—			35
Interest expense, net of amounts capitalized		(22,518	)		(18,577	)		(9,461	)		(13,994	)		(8,127	)
Other income, net		47			36			17			130			427

Income (loss) before income taxes		15,679			(318,152	)		(65,772	)		24,712			28,481
Income tax (expense) benefit		(5,729	)		113,307			20,725			(9,243	)		(10,233	)

Net income (loss)	$	9,950		$	(204,845	)	$	(45,047	)	$	15,469		$	18,248

Basic income (loss) per common share	$	0.29		$	(6.61	)	$	(1.49	)	$	0.58		$	0.73

Diluted income (loss) per common share	$	0.29		$	(6.61	)	$	(1.49	)	$	0.57		$	0.71

Basic weighted average common shares outstanding		33,861			31,006			30,326			26,641			25,081
Diluted weighted average common shares outstanding		34,305			31,006			30,326			27,120			25,565
Statements of Cash Flows Data:
Net cash provided by operating activities	$	94,416		$	133,372		$	148,754		$	95,231		$	65,437
Net cash used in investing activities		(270,296	)		(162,453	)		(555,345	)		(227,724	)		(161,576	)
Net cash provided by financing activities		176,171			27,734			403,749			135,111			72,822
Other Cash Flows Data:
Capital expenditures	$	(347,808	)	$	(182,907	)	$	(571,291	)	$	(247,003	)	$	(201,773	)
Proceeds from (repayments of) debt⁽¹⁾		(840	)		31,652			279,259			65,742			39,464
Proceeds from common stock offerings, net of offering costs		188,534			—			135,075			71,926			33,525
Balance Sheet Data:
Working capital (deficit)	$	(58,672	)	$	(47,328	)	$	(57,602	)	$	(50,053	)	$	(17,014	)
Property and equipment, net		983,057			733,700			986,629			646,810			445,447
Total assets		1,144,134			863,107			1,071,702			708,663			494,795
Total debt, net of debt discount		558,254			520,336			475,961			254,501			188,758
Total shareholders’ equity		456,636			247,609			440,085			310,721			212,274

(1)	Repayments include amounts refinanced.

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

Restatement of Previously Issued Financial Statements

During the third quarter of 2010, we received cash distributions of $20.8 million on our B Unit investment in ACP II, as further described under “—Natural Gas Plays—Avista Joint Venture.” We followed the cost method of accounting for the B Units and recognized cash distributions received with respect to the B Units as Distribution Income-Related Party in the consolidated statements of operations included in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010. However, we have since concluded that under the full cost method of accounting, the cash distributions should be considered sales of oil and gas properties and accordingly, should be recognized as a reduction of capitalized oil and gas property costs.

The effect of restating our financial statements for the three-month and nine-month periods ended September 30, 2010 to recognize the cash distributions received on the B Units as a reduction of capitalized oil and gas property costs rather than distribution income-related party and related income tax effects, resulted in a decrease in each of net income and total shareholders’ equity of $11.5 million from the previously reported amount for the three months and nine months ended September 30, 2010, which represents a decrease in diluted income per common share of $0.32 and $0.34 from the previously reported amounts for the three months and nine months ended September 30, 2010, respectively, with a corresponding decrease in proved oil and gas properties of $20.5 million and an increase in net income tax assets and liabilities of $9.0 million from the previously reported amounts as of September 30, 2010. The restatement also resulted in a decrease in cash flows from operating activities and a corresponding increase in cash flows from investing activities of $20.8 million from the previously reported amounts for the nine months ended September 30, 2010.

General Overview

In 2010, we recognized revenues from oil and gas sales of $138.1 million, record production of 36.8 Bcfe and a record level of proved oil and gas, at December 31, 2010, of 840.7 Bcfe. The key drivers to our success in 2010 included the following:

Drilling program. Our success is largely dependent on the results of our drilling program. For the year ended December 31, 2010, we drilled 88 gross (44.6 net) wells with an apparent success rate of 97% that was comprised of: (a) 65 of 65 gross (35.8 net) wells in the Barnett Shale, (b) 6 of 6 gross (0.9 net) wells in the Marcellus Shale, (c) 3 of 3 gross (3.0 net) wells in the Eagle Ford Shale, (d) one of one gross (1.0 net) well in the Niobrara, and (e) 10 of 13 gross (1.6 net) wells in other project areas in the U.S. At December 31, 2010, 42 of these gross (21.4 net) wells were awaiting completion or pipeline connections.

Production and reserve growth. Our production for the year ended December 31, 2010 was a record 36.8 Bcfe, or 101 MMcfe/d, and reflects an increase of 11% from 2009 production of 33.0 Bcfe. The increase in production was primarily attributable to the addition of new Barnett Shale wells. As a result of our drilling program discussed above, our proved oil and gas reserves increased 40% to 840.7 Bcfe at December 31, 2010, as compared to 601.9 Bcfe at December 31, 2009 and replacing 749% of 2010’s record production.

Commodity prices. Our average gas price during 2010 was $3.48 per Mcf (excluding the impact of our derivative instruments), $0.28 per Mcf greater than the 2009 price of $3.20. Our average oil price in 2010 was $78.64 per Bbl, or $19.79 greater than in 2009. Commodity prices are affected by changes in market demand, 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.

Financial flexibility. During 2010, we took steps to strengthen our financial flexibility and provide funding to accelerate the development of our crude oil and liquids-rich plays in Eagle Ford Shale and the Niobrara. We issued $400 million of 8.625% Senior Notes due 2018 (“Senior Notes”) and used the proceeds to retire $300 million of our 4.375% Convertible Senior Notes that were first callable in 2013. In addition, we successfully completed two equity offerings for a total of 7.2 million shares for aggregate proceeds of $188.5 million.

Recent Events

New Growth Strategy

In 2010 we announced a new growth strategy in crude oil and liquids-rich plays. As part of this effort, we completed the acquisition of acreage in an unconventional play that is rich in condensate and natural gas liquids located in the Eagle Ford Shale, principally in LaSalle County, Texas. In addition, we acquired acreage in a conventional oil play located in the Niobrara in Weld County, Colorado. In the Eagle Ford Shale we owned approximately 20,000 net acres as of December 31, 2010 and during 2010 drilled 5 horizontal gross wells (5.0 net) comprised of 3 gross (3.0 net) wells in production and 2 gross (2.0 net) wells that were waiting on completion at December 31, 2010. In the Niobrara we now own approximately 61,000 net acres and during 2010 drilled 3 horizontal gross (3.0 net) wells comprised of one gross (1.0 net) well in production and two gross (2.0 net) wells that were waiting on completion at December 31, 2010. As a result of our drilling efforts in these new areas, our domestic oil reserves at December 31, 2010 increased 210%, or 7.2 MMBOE, compared to December 31, 2009.

New Senior Secured Revolving Credit Facility

On January 27, 2011, we entered into the Revolving Credit Facility with BNP Paribas, as Administrative Agent (the “Agent”), certain other agents and a group of lenders (the “Revolving Credit Facility”). The Revolving Credit Facility provides for a revolving credit facility up to $750 million and matures on January 27, 2016. It is secured by substantially all of our oil and gas assets (other than those located in the North Sea) and is guaranteed by certain of our subsidiaries: Bandelier Pipeline Holding, LLC, Carrizo Marcellus Holding Inc., Carrizo (Marcellus) LLC, Carrizo (Marcellus) WV LLC, CLLR, Inc., Hondo Pipeline, Inc. and Mescalero Pipeline, LLC.

For a description of the Revolving Credit Facility see “—Financing Arrangements—Revolving Credit Facility.”

Huntington Field Development Project Credit Agreement

On January 28, 2011, the Company and Carrizo UK, a wholly-owned subsidiary of the Company incorporated in England and Wales, as Borrower, entered into a Huntington Facility. The Huntington Facility is secured by substantially all of Carrizo UK’s assets and is limited recourse to the Company. The Huntington Facility provides financing for a substantial portion of Carrizo UK’s share of costs associated with the Huntington Field development project in the U.K. North Sea. For a description of the Huntington Facility see “—Financing Arrangements—Huntington Field Development Project Credit Facility.”

Private Offering of Senior Notes, Tender Offer for Convertible Senior Notes and Common Stock Offerings

On November 2, 2010, we completed our private placement of $400 million aggregate principal amount of the Senior Notes at a price to the public equal of 99.302% of the principal amount. The Senior Notes are guaranteed by certain of our subsidiaries: CLLR, Inc.; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC; Carrizo Marcellus Holding, Inc.; Hondo Pipeline, Inc.; Bandelier Pipeline Holding, LLC; and Mescalero Pipeline, LLC. The net proceeds of approximately $387.5 million (after deducting initial purchasers’ discounts and our expenses) were used to repay in full borrowings outstanding under the Prior Credit Facility and to fund in part the tender offer for $300 million of our Convertible Senior Notes issued May 2008 in aggregate principal amount $373.8 million due 2028.

On November 2, 2010, in connection with the issuance of the Senior Notes, we and the guarantors of the Senior Notes entered into a supplement to the indenture governing the Convertible Senior Notes. Pursuant to this supplemental indenture, the guarantors of the Senior Notes also became guarantors of the Convertible Senior Notes. The guarantee of the Convertible Senior Notes was required under the indenture for the Convertible Senior Notes as a result of the issuance of their guarantees of the Senior Notes.

In November 2010, we completed a tender offer for $300 million aggregate principal amount of the Convertible Senior Notes for an aggregate consideration of approximately $306.3 million, including accrued and unpaid interest on the Convertible Senior Notes. Each holder received $1,000 for each $1,000 principal amount of Convertible Senior Notes purchased in the tender offer, plus accrued and unpaid interest. The Company recognized a $31.0 million pre-tax loss on extinguishment of debt as a result of the purchase of the Convertible Senior Notes in the tender offer, substantially all of which was non-cash representing the associated unamortized discount and deferred financing costs. After our purchase of $300 million aggregate principal amount of Convertible Senior Notes, $73.8 million aggregate principal amount of Convertible Senior Notes remain outstanding as of December 31, 2010.

As a result of the purchase of Convertible Senior Notes in our tender offer and the recent issuance of our Senior Notes, our debt service expenses will increase as the Senior Notes bear a higher stated interest rate than the Convertible Senior Notes and the principal

amount of the Senior Notes issued are $100 million more than the principal amount of the Convertible Senior Notes purchased in the tender offer. The 2018 maturity of the Senior Notes, however, extends beyond June 1, 2013, the date on which the holders of the remaining $73.8 million Convertible Senior Notes will first be able to require us to purchase the Convertible Senior Notes.

In April 2010, we sold 3.22 million shares of our common stock in an underwritten public offering at a price to the underwriter of $23.00 per share. We used the net proceeds of approximately $74.1 million to repay borrowings under the Prior Credit Facility, which has since been terminated.

In December 2010, we sold 3.98 million shares of our common stock in an underwritten public offering at a price to the underwriter of $28.90 per share. We used the net proceeds of approximately $114.9 million to repay a portion of the outstanding borrowings under the Prior Credit Facility.

Marcellus Shale Joint Ventures

As of December 31, 2010, we owned interests in 305,726 gross (117,921 net) acres in the Marcellus shale trend, principally in Pennsylvania, New York and West Virginia. During 2010, we drilled five gross (0.4 net) horizontal wells and two gross (0.9 net) vertical wells to test our acreage, of which one gross (0.4 net) vertical well was waiting on completion at December 31, 2010. We operated two gross (0.9 net) vertical wells drilled in 2010.

In September 2010, we completed the sale of 20% of our interests in substantially all of our oil and gas properties in Pennsylvania that had been subject to our joint venture with Avista to Reliance, for $13.1 million in cash and a commitment by Reliance to pay 75% of certain of our future development costs up to approximately $52.0 million, (the “Carry Commitment”) as further described below. Simultaneously with the closing of this transaction, Avista, through its joint venture entity ACP II, closed the sale of its entire interest in the same properties to Reliance for a purchase price of approximately $327 million. In December 2010, we entered into a settlement agreement with Reliance providing for the resolution of defects in title that Reliance alleged with respect to the properties it acquired from us and Avista. In the agreement, we agreed to undertake specified curative measures with respect to the properties we and Avista sold to Reliance, and to indemnify Reliance on our own behalf and on behalf of Avista with respect to any specified third party claims (in addition to existing customary indemnification obligations under the purchase agreement). In connection with entering into the settlement agreement, we entered into an agreement with Avista by which it agreed to indemnify us for amounts we pay on its behalf under the settlement agreement, if any.

As part of the closing of the transactions with Reliance described above, we and Avista amended our existing joint venture agreements to provide that the properties that we and Avista sold to Reliance, as well as the properties we committed to the joint venture with Reliance, are not subject to the terms of the Avista joint venture, and that the Avista joint venture’s area of mutual interest will generally not include Pennsylvania, in which those properties are located. Our Marcellus joint venture with Avista will

otherwise continue and currently includes approximately 174,583 net acres, primarily in West Virginia and New York. Pursuant to the terms of the Avista area of mutual interest, effective December 31, 2010, the initial area of mutual interest was reduced to specified halos in which the joint venture was active.

Outlook for 2011

Our outlook for 2011 remains challenging, primarily as a result of the low spot and futures prices for natural gas, but our outlook for the long-term future remains positive. Production growth and commodity prices that permit us to drill, develop and produce at a profit are key to our future success, and we believe the following measures will continue to have a positive impact on our results in 2011:

Eagle Ford and Niobrara. Since our decision in early 2010 to enter into the crude oil and liquids-rich plays in the Eagle Ford Shale and Niobrara, and through December 31, 2010, we drilled five horizontal gross (5.0 net) wells in the Eagle Ford Shale and drilled three gross (3.0 net) wells in the Niobrara. Production results at December 31, 2010 from the three Eagle Ford Shale and the one Niobrara wells that had been completed were 1,095 and 360 Bbls/d, respectively. We resumed development drilling in early March 2011 by relocating a rig that was operating in the Barnett Shale to the Eagle Ford. We expect to add a second rig later in the second quarter of 2011. We completed the fourth and fifth wells in the Eagle Ford in January and March 2011, respectively and we completed the second and third wells in the Niobrara in January and March 2011, respectively.

Marcellus Shale. As a result of the joint venture with Reliance, we plan to accelerate our exploration activities in the Marcellus Shale. We have drilled seven gross (1.3 net) wells in the Marcellus Shale in 2010, including four gross wells (0.6 net) in Pennsylvania, of which one gross (0.4 net) well was waiting on completion at December 31, 2010. In the third quarter of 2010, we entered into two long-term contracts for drilling rigs in the Marcellus Shale, one rig under long-term contract began work in the fourth quarter of 2010 and the other of which is expected to begin work in the second quarter of 2011. We have recently entered into a six-month contract for a third rig with an option to extend this contract for an additional six months. This rig is currently drilling in Northeast Pennsylvania. Finally, we recently signed a two year contract on a fourth rig that is currently expected to work in our central Pennsylvania area, commencing later in the second quarter of 2011. Additionally, we expect to continue our Marcellus joint venture activities in West Virginia with Avista.

U.K. North Sea. In early 2011, we entered into the Huntington Facility to provide for the financing of a substantial portion of the Company’s share of costs associated with the Huntington Field development project in the U.K. North Sea. Construction, refurbishment and installation of offshore facilities and pipelines, as well as drilling of the development wells, are expected to commence in the second quarter of 2011. We currently expect production to begin in the first quarter of 2012.

Control capital costs and maintain financial flexibility. Our Board of Directors has approved a capital expenditure plan for 2011 of $340 million, and we are striving to maintain our financial flexibility and a positive production growth profile. A weakening in commodity prices may cause us to reduce our capital expenditure plan for 2011.

2011 capital expenditure plan. In 2011, we plan to focus on the drilling and development of our key oil and gas plays. Our 2011 capital expenditure plan has been set at $340 million and includes approximately $253 million for drilling (including $129 million in the Eagle Ford Shale, $75 million for the Barnett Shale, $25 million for the Niobrara and $21 million in the Marcellus Shale), $34 million for leasehold and seismic costs and $53 million for the Huntington field development in the U.K. North Sea, of which $31 million will be funded by our Huntington Facility with the remaining $22 million funded by the equity investment we made in our U.K. North Sea subsidiary during the first quarter of 2011. Our capital expenditures could vary from our current plan depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions and other factors.

Results of Operations

Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009

Revenues from oil and gas production for 2010 increased 23% to $138.1 million from $112.7 million in 2009. Production volumes for oil and gas in 2010 increased 11% to 36.8 Bcfe from 33.0 Bcfe in 2009. The increase in production for the year ended December 31, 2010 as compared to the year ended December 31, 2009 was primarily due to increased production from new Barnett Shale wells partially offset by normal production decline and the shut in of a high volume gas well in the Gulf Coast area for a workover and

sidetrack during the third quarter of 2010. Average natural gas prices increased to $3.48 per Mcf in 2010 from $3.20 in 2009. Average oil prices increased 34% to $78.64 per barrel from $58.85 per barrel in 2009.

The following table summarizes production volumes, average sales prices and oil and gas revenues for the years ended December 31, 2010 and 2009:


					2010 Period Compared to 2009 Period
	December 31,				Increase		% Increase
	2010		2009		(Decrease)		(Decrease)
Production volumes-
Oil and condensate (Mbbls)		176		174		2		1	%
Natural gas and NGLs (MMcf)		35,751		32,002		3,749		12	%
Average sales prices-
Oil and condensate (per Bbl)	$	78.64	$	58.85	$	19.79		34	%
Natural gas and NGLs (per Mcf)		3.48		3.20		0.28		9	%
Oil and gas revenues (In thousands) -
Oil and condensate	$	13,859	$	10,217	$	3,642		36	%
Natural gas and NGLs		124,264		102,482		21,782		21	%

Total	$	138,123	$	112,699	$	25,424		23	%

Lease operating expenses for 2010 decreased 6% to $23.7 million (or $0.64 per Mcfe) from $25.1 million (or $0.76 per Mcfe) in 2009. A decrease in service costs and lower transportation costs were partially offset by increased operating expenses associated with increased production. The decrease in service costs was driven primarily by a decrease in operating expenses related to a pipeline and gathering system that was sold during the fourth quarter of 2009 and the increase in production from our Tarrant County Barnett Shale area, which has comparatively less associated salt water production that must be disposed of than production from other areas. The decrease in transportation costs was primarily due to our decision to begin selling our natural gas production at the wellhead in July 2009.

Production taxes increased from $0.1 million in 2009 to $3.6 million in 2010 as a result of a severance tax refund of $2.0 million in 2009 and higher prices and increased production in 2010.

Ad valorem taxes decreased 26% to $3.7 million in 2010 from $5.0 million in 2009 primarily due to lower property valuations in 2010.

Depreciation, depletion and amortization (“DD&A”) expense for 2010 decreased 10% to $47.0 million (or $1.28 per Mcfe) from $52.0 million (or $1.57 per Mcfe) in 2009. This decrease in DD&A was primarily due to impairment charges in the first and fourth quarters of 2009 that reduced the depletable base of the full cost pool, partially offset by increased production and increased future development costs attributable to crude oil and natural gas liquids reserves added during the fourth quarter of 2010, which have a higher future development cost per equivalent unit than our proved gas reserves. We expect a higher depletion rate in 2011 as we continue to pursue our new growth strategy in crude oil and liquids-rich plays due to the higher future development costs per equivalent unit associated with such plays as compared to the Company’s gas reserves.

In June 2010, we concluded that it was uneconomical to pursue development on the license covering the Monterey field in the U.K. North Sea and terminated further development efforts resulting in a full-cost ceiling test impairment of $2.7 million ($1.7 million net of income taxes) for the year ended December 31, 2010 with respect to the U.K. cost center. The significant decline in oil and natural gas prices since mid-2008 and the continued depressed price of natural gas in 2009, caused the discounted present value of future net cash flows from our proved oil and gas reserves to fall below our net book basis in the proved oil and gas properties at March 31, 2009 and December 31, 2009. This resulted in non-cash, full cost ceiling test write-downs of $216.4 million ($138.0 million net of income taxes) and $122.5 million ($78.1 million net of income taxes) at March 31, 2009 and December 31, 2009, respectively.

General and administration (“G&A”) expense for 2010 increased 19% to $35.9 million from $30.1 million in 2009. The increase was due primarily to (a) increased stock-based compensation largely attributable to additional stock appreciation rights (“SARs”) granted in July 2010 and existing SARs that increased in fair value in the second half of 2010, and (b) increased compensation costs

largely due to an increase in the number of employees in 2010 partially offset by (c) the expense associated with a pledge of $1.0 million made to the University of Texas at Arlington (“UTA”), a university located within the area of our significant operations in the Barnett Shale, in the third quarter of 2009 for which there is no corresponding expense in the 2010 period.

The net gain on derivatives was $47.8 million for the year ended December 31, 2010, comprised of (i) $14.6 million of unrealized gains on derivatives and (ii) $33.2 million of realized gains on derivatives. The net gain on derivatives was $41.5 million for the year ended December 31, 2009, comprised of (i) $74.9 million of unrealized gains on derivatives and (ii) $33.4 million of realized losses on derivatives.

In November 2010, we completed a tender offer for $300 million aggregate principal amount outstanding of the Convertible Senior Notes for an aggregate consideration of approximately $306.3 million, including accrued and unpaid interest on the Convertible Senior Notes. We recognized a $31.0 million pre-tax loss on extinguishment of debt as a result of the purchase of the Convertible Senior Notes in the tender offer, substantially all of which was non-cash representing the associated unamortized discount and deferred financing costs.

Interest expense and capitalized interest in 2010 were $43.3 million and $20.7 million, respectively, as compared to $38.3 million and $19.7 million in 2009, respectively. The net increase was primarily due to interest on the $400 million aggregate principal amount of 8.625% Senior Notes which were issued in the fourth quarter of 2010, increased amortization of deferred financing costs related to the Prior Credit Facility, partially offset by decreased interest attributable to the $300 million aggregate principal amount of the 4.375% Convertible Senior Notes repurchased in the tender offer during the fourth quarter of 2010 and higher capitalized interest due to higher levels of unproved properties during 2010.

Our overall effective tax rate was 36.5% for 2010 and 35.6% for 2009. The increase in the effective tax rate was primarily due to a true-up of prior year estimates of state income taxes during 2010 and state income taxes on the cash distributions received on our B Unit investment in ACP II during the third and fourth quarters of 2010.

Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008

Revenues from oil and gas production for 2009 decreased 47% to $112.7 million from $209.8 million in 2008. Production volumes for oil and gas in 2009 increased 29% to 33.0 Bcfe from 25.6 Bcfe in 2008. Average natural gas prices for 2009 decreased 59% to $3.20 per Mcf compared to $7.80 per Mcf in 2008, and average oil prices for 2009 decreased 41% to $58.85 per barrel from $99.74 per barrel in 2008. The increase in natural gas production was primarily due to the production from new wells in the Barnett Shale.

The following table summarizes production volumes, average sales prices and oil and gas revenues for the years ended December 31, 2009 and 2008:


					2009 Period Compared to 2008 Period
	December 31,				Increase			% Increase
	2009		2008		(Decrease)			(Decrease)
Production volumes-
Oil and condensate (Mbbls)		174		186		(12	)		(6	)%
Natural gas (MMcf)⁽¹⁾		32,002		24,513		7,489			31	%
Average sales prices-
Oil and condensate (per Bbl)	$	58.85	$	99.74	$	(40.89	)		(41	)%
Natural gas (per Mcf)		3.20		7.80		(4.60	)		(59	)%
Oil and gas revenues (In thousands) -
Oil and condensate	$	10,217	$	18,598	$	(8,381	)		(45	)%
Natural gas		102,482		191,231		(88,749	)		(46	)%

Total	$	112,699	$	209,829	$	(97,130	)		(46	)%

⁽¹⁾	Includes 1,975.2 and 965.7 MMcfe of natural gas liquids in 2009 and 2008, respectively.

Lease operating expenses for 2009, including transportation, production and ad valorem taxes, decreased 20% to $30.2 million (or $0.91 per Mcfe) from $37.9 million (or $1.48 per Mcfe) in 2008. The decrease in operating expenses was due to lower production taxes of $5.1 million associated with refunds from certain wells that qualified for a tight-gas sands tax credit for prior production periods and approximately $3.0 million in lower transportation costs in the Barnett Shale primarily due to our decision to begin selling our natural gas production at the wellhead in July 2009.

The significant decline in oil and gas prices in the second half of 2008 and the continued depressed price of natural gas in 2009 caused the discounted present value of future net cash flows from our proved oil and gas reserves to fall below the net capitalized costs of our proved oil and gas properties at March 31, 2009 and December 31, 2009. This resulted in non-cash impairments of our oil and gas properties of $216.4 million ($138.0 million net of income taxes) and $122.5 million ($78.1 million net of income taxes) at March 31, 2009 and December 31, 2009, respectively. At December 31, 2008, we recorded a non-cash impairment of oil and gas properties of $178.5 million ($116.0 million net of income taxes).

DD&A expense for 2009 decreased 11% to $52.0 million from $58.3 million in 2008. This decrease was primarily due to impairment charges in the fourth quarter of 2008 and the first quarter of 2009 that reduced the depletable base of the full cost pool and due to lower overall finding costs of new reserves added primarily in the fourth quarter of 2009.

G&A expense for 2009 increased 29% to $30.1 million from $23.4 million in 2008. The increase in G&A was due primarily to an increase in non-cash, stock-based compensation of $5.3 million as a result of additional stock-based compensation awards. In addition, during 2009, we made a $1.0 million pledge to UTA, a university located within the area of our significant operations in the Barnett Shale.

The net gain on derivatives was $41.5 million for the year ended December 31, 2009, comprised of (1) $74.9 million of unrealized gains on derivatives and (2) $33.4 million of realized losses on derivatives.

Interest expense and capitalized interest in 2009 were $38.3 million and $19.7 million, respectively, as compared to $30.3 million and $20.5 million in 2008, respectively. The increase in interest expense was attributable to increased borrowings under the Prior Credit Facility and higher effective interest rates.

Our overall effective tax rate was 35.6% for 2009 and 31.5% for 2008. The increase in the effective tax rate was due to higher state income taxes and lower non-deductible expenses in 2009 as compared to 2008.

Liquidity and Capital Resources

2011 Capital Expenditure Plan and Funding Strategy. For 2011, our Board has established a capital expenditure of $340 million which includes approximately $253 million for drilling (including $129 million in the Eagle Ford Shale, $75 million for the Barnett Shale, $25 million for the Niobrara and $21 million in the Marcellus Shale), $34 million for leasehold and seismic costs and $53 million for the Huntington field development in the U.K. North Sea of which $31 million will be funded by our Huntington Facility – described below with the remaining $22 million funded by the equity investment we made in our U.K. North Sea subsidiary during the first quarter of 2011. We intend to finance the remainder of our 2011 capital expenditure plan primarily from the sources described below under “—Sources and Uses of Cash.” Our capital program could vary depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions and other factors.

Sources and Uses of Cash. For the year ended December 31, 2010, capital expenditures, net of proceeds from asset sales, exceeded our net cash provided by operations. During 2010, we funded our capital expenditures with cash provided by operations, proceeds from the sale of oil and gas properties, cash distributions on our B Unit investment in ACP II, proceeds from the sales of equity securities, payments or carried interest from our joint ventures with Reliance and Avista, and borrowings under the Senior Credit Facility, including the increased capacity under the Prior Credit Facility that was made available following repayment of borrowings with proceeds from our April and December equity offerings, the transactions relating to our Marcellus joint ventures with Reliance and Avista and net proceeds from our November 2010 Senior Notes offering. Potential 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 oilfield services. We hedge a portion of our production to mitigate the risk of a decline in oil and/or gas prices.

•

Borrowings under the Revolving Credit Facility. In February 2011, we closed a new $750 million Revolving Credit Facility with a current borrowing base of $350 million. This facility matures in January 2016 and expanded our ability to enter into project financing arrangements such as our Huntington Facility. At March 25, 2011, $155 million of borrowings were outstanding under the Revolving Credit Facility. The next borrowing base redetermination is currently scheduled for May 1, 2011. We have also issued $.3 million of letters of credit, which reduce the amounts available under the Revolving Credit Facility. The amount we are able to borrow with respect to the Borrowing Base is subject to compliance with the financial covenants and other provisions of the Revolving Credit Facility.

•

Borrowings under project financing arrangements in certain limited circumstances. As described above, we plan to fund a substantial portion of our costs relating to the Huntington Field from our recently established Huntington Facility.

•

Asset sales. In order to fund our capital expenditure plan, we may consider the sale of certain properties or assets, including our interest in the Huntington field development project in the U.K. North Sea, that are not part of our core business, or are no longer deemed essential to our future growth, and provided that we are able to sell such assets on terms that are acceptable to us.

•

Securities offerings. In November 2010, we sold $400 million in aggregate principal of Senior Notes in a private placement, which were guaranteed by substantially all of our wholly owned subsidiaries (other than Carrizo UK). We used the net proceeds of approximately $387.5 million after deducting initial purchasers’ discounts and our expenses, to repay in full borrowings outstanding under the Prior Credit Facility at the time and to partially fund the tender off our Convertible Senior Notes which was completed in November 2010. In April 2010, we sold 3.22 million shares of our common stock in an underwritten public offering at a price of $23.00 per share. We used the net proceeds of approximately $73.8 million to repay a portion of the outstanding borrowings under the Prior Credit Facility. In December 2010, we sold 3.98 million shares of our common stock in an underwritten public offering at a price of $28.90 per share. We used the net proceeds of $114.9 million to repay a portion of the outstanding borrowings under the Prior Credit Facility. 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.

•

Lease option agreements and land banking arrangements, such as those we have entered into in the Marcellus Shale, the Barnett Shale and other plays. Please read “—Lease Option Arrangements”.

•

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 and/or purchase a portion of interests, such as our joint ventures with Avista and Reliance in the Marcellus Shale play and our joint venture with Sumitomo in the Barnett Shale.

•

We may consider sale/leaseback transactions of certain capital assets, such as our remaining 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 data acquisition programs. As mentioned above, our 2011 capital expenditure plan has been set at $340 million and includes approximately $253 million for drilling, $34 million for leasehold and seismic costs and $53 million for the Huntington field development in the U.K. North Sea of which $31 million will be funded by our Huntington Facility with the remaining $22 million funded by the equity investment we made in our U.K. North Sea subsidiary during the first quarter of 2011. The actual amount of investment could 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, commodity prices, market conditions and other factors.

Overview of Cash Flow Activities. Cash flows provided by operating activities were $94.4 million, $133.4 million and $148.8 million for the years ended December 31, 2010, 2009, and 2008, respectively. Cash flows decreased in 2010 from 2009 due to lower realized hedge gains in 2010 as compared to 2009 partially offset by increased production and oil and gas prices. Cash flows decreased in 2009 from 2008 due to lower natural gas prices in 2009, partially offset by increased production and higher realized hedge gains in 2009 as compared to 2008.

Cash flows used in investing activities were $270.3 million for the year ended December 31, 2010 and related primarily to capital expenditures, partially offset by proceeds from the sale of an interest in our Pennsylvania properties to Reliance and cash distributions on our B Unit investment in ACP II. Cash flows used in investing activities were $162.5 million for the year ended December 31, 2009 and related primarily to capital expenditures, partially offset by the sale of our Mansfield pipeline and gathering system in the Barnett Shale and working interests in Barnett Shale drilling units for approximately $50 million. 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. The increase in investing activities in 2010 from 2009 was largely due to higher expenditures for oil and gas properties due to our growth strategy into crude oil and liquids-rich plays in the Eagle Ford Shale and the Niobrara. The decrease in investing activities from 2008 to 2009 was largely due to lower expenditures for oil and gas properties as we adjusted our drilling plans to the reduced demand for natural gas and lower natural gas prices.

Net cash provided by financing activities for the year ended December 31, 2010 was $176.2 million and related primarily to net proceeds of $188.5 million from the issuance of common stock in April and December of 2010. Proceeds from the issuance of our $400 million of Senior Notes were offset by the purchase of $300 million of Convertible Senior Notes in the tender offer and repayment of amounts outstanding under the Prior Credit Facility. Net cash provided by financing activities for the year ended December 31, 2009 was $27.7 million and related primarily to net borrowings of $32.4 million under our Prior Credit Facility. 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 the Senior Convertible Notes and $401.0 million in additional borrowings under the Prior Credit Facility. These cash proceeds were partially offset by the payoff and termination of the second lien credit facility and repayments of amounts outstanding under the Prior Credit Facility.

Liquidity/Cash Flow Outlook

The recent worldwide economic downturn may adversely affect our ability to access the capital markets in the future. We currently believe that cash provided by operating activities and borrowings under the Revolving Credit Facility and the Huntington Facility, will be sufficient to fund our immediate cash flow requirements. Cash provided by operating activities is primarily driven by production and commodity prices. While we have steadily increased production over the last few years, spot and futures prices of natural gas continue to remain depressed. To manage our exposure to commodity price risk and to provide a level of certainty in the cash flows that will support our capital expenditures program, we hedge a portion of our production and, as of March 25, 2011, we had hedged approximately 19,255,000 MMBtu (70,000 MMcf per day for the remainder of 2011) of our 2011 natural gas production at a weighted average floor or swap price of $5.65 per MMBtu relative to WAHA and Houston Ship Channel prices. We have borrowed $155 million under our Revolving Credit Facility as of March 25, 2011. Our borrowing base under our Revolving Credit Facility is currently $350 million. We have issued $0.3 million of letters of credit, which reduce the amounts available under the Revolving Credit Facility. Additionally, as described under “Sources and Uses of Cash” above, the amount we are able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Revolving Credit Facility. We are scheduled for a borrowing base redetermination as of May 1, 2011, at which time our borrowing base may change. The borrowing base is affected by our banks assumptions with respect to future oil and gas prices. Our borrowing base may decrease if our banks reduce their expectations with respect to future oil and gas prices from those assumptions used to determine our existing borrowing base.

If cash provided by operating activities, funds available under the Revolving Credit Facility and the Huntington Facility and the other sources of cash described under “Sources and Uses of Cash” are insufficient to fund our 2011 capital expenditure plan, we may need to reduce our capital expenditure plan 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 2011 capital expenditure plan, thereby adversely affecting the recoverability and ultimate value of our oil and gas properties.

Contractual Obligations

The following table sets forth estimates of our contractual obligations as of December 31, 2010:


	Total		2011		2012		2013		2014		2015		2016 and Thereafter
Long-term debt (1)	$	567,250	$	—	$	93,500	$	73,750	$	—	$	—	$	400,000
Interest on long-term debt (2)		289,182		40,517		40,052		36,113		34,500		34,500		103,500
Operating leases		1,314		1,314		—		—		3,797		—		—
Drilling contracts		51,361		22,393		15,991		9,180		10,397		—		—
Pipeline volume commitments		51,536		7,696		8,355		10,148		244		8,899		6,041
Asset retirement obligations		6,369		532		96		118		—		36		5,343
Seismic obligations		9,139		9,139		—		—		—		—		—
Other		5,367		4,467		900		—		—		—		—

Total Contractual Obligations	$	981,518	$	86,058	$	158,894	$	129,309	$	48,938	$	43,435	$	514,884

(1)	Noteholders may require us to repurchase the Convertible Senior Notes in June 2013, June 2018, or June 2023. The table assumes that the holders of the Convertible Senior Notes exercise this right on the first available date (in June 2013).

(2)	Interest on long term debt is based on the 8.625% rate on the Senior Notes, the 4.375% rate on the Convertible Senior Notes and the December 31, 2010 average 3.0% rate outstanding under the Prior Credit Facility.

The Revolving Credit Facility and the Huntington Facility were entered into, and the Prior Credit Facility was repaid and terminated, subsequent to December 31, 2010.

Off Balance Sheet Arrangements

We currently do not have any off balance sheet arrangements.

Financing Arrangements

Senior Notes

On November 2, 2010, the Company issued $400 million aggregate principal amount of 8.625% Senior Notes due 2018 (“Senior Notes”) at an offering price equal to 99.302%. The Senior Notes are guaranteed by certain of the Company’s subsidiaries: CCBM, Inc.; CLLR, Inc.; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC, Carrizo Marcellus Holding, Inc.; Hondo Pipeline, Inc.; Bandelier Pipeline Holding, LLC, Chama Pipeline Holding LLC, and Mescalero Pipeline, LLC. The Senior Notes are not guaranteed by the Carrizo UK subsidiary holding substantially all of our interests in the Huntington field. The net proceeds of $387.5 million (after deducting initial purchasers’ discount and our expenses) were used to repay in full amounts outstanding under the Prior Credit Facility and to fund in part the tender offer for $300 million of the Convertible Senior Notes as described below.

The Senior Notes mature on October 15, 2018 with interest payable semi-annually. At any time prior to October 15, 2013, the Company may, subject to certain conditions, redeem up to 35% of the aggregate principal amount of Senior Notes at a redemption price of 108.625% of the principal amount, plus accrued and unpaid interest, using the net cash proceeds of one or more equity offerings by the Company. Prior to October 15, 2014, the Company may redeem all or part of the Senior Notes at 100% of the principal amount thereof, plus accrued and unpaid interest and a make whole premium. On and after October 15, 2014, the Company may redeem all or a part of the Senior Notes, at redemption prices decreasing from 104.313% to 100% on October 15, 2017, plus accrued and unpaid interest. If a Change of Control (as defined in the Indenture governing the Senior Notes) occurs, the Company may be required by holders to repurchase Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus any accrued but unpaid interest.

The Indenture contains covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to: pay distributions on, purchase or redeem the Company’s common stock or other capital stock or redeem the Company’s subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of the Company’s assets; enter into agreements that

restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries.

The notes and indenture are subject to customary events of default, including those relating to failures to comply with the terms of the notes and indenture, certain failures to file reports with the Securities and Exchange Commission (“SEC”) and certain cross defaults of other indebtedness and mortgages and certain failures to pay final judgments.

In connection with the issuance of the Senior Notes, the Company agreed to use its commercially reasonable best efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the Senior Notes in exchange for outstanding Senior Notes. In certain circumstances, the Company may be required to use commercially reasonable efforts to file a shelf registration statement to cover resales of the Senior Notes. The Company may be required to pay additional interest to holders of the Senior Notes under certain circumstances if we fail to meet these obligations by certain dates.

Convertible Senior Notes

In May 2008, the Company issued $373.8 million aggregate principal amount of 4.375% convertible senior notes due 2028 (the “Convertible Senior Notes”). Interest is payable on June 1 and December 1 each year. The notes are convertible, using a net share settlement process, into a combination of cash and Company 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 the Company’s conversion obligation in excess of such principal amount.

In November 2010, the Company completed a tender offer for $300 million aggregate principal amount of the Convertible Senior Notes for an aggregate consideration of approximately $306.3 million, including accrued and unpaid interest on the Convertible Senior Notes. Each holder received $1,000 for each $1,000 principal amount of Convertible Senior Notes purchased in the tender offer, plus accrued and unpaid interest. The Company recognized a $31.0 million pre-tax loss on extinguishment of debt as a result of the purchase of the Convertible Senior Notes in the tender offer, substantially all of which was non-cash representing the associated unamortized discount and deferred financing costs. After the Company’s purchase of $300 million aggregate principal amount of Convertible Senior Notes, $73.8 million aggregate principal amount of Convertible Senior Notes remain outstanding as of December 31, 2010.

The notes are convertible into the Company’s 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, the Company 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 the Company’s 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 the Company’s 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 the Company 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. The Company 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 Revolving 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 of the Company and rank equal to the Senior Notes and all future senior unsecured debt of the Company but rank second in priority to the Revolving Credit Facility. On November 2, 2010, the Company and the guarantors of the Senior Notes entered into a supplement to the indenture governing the Convertible Senior Notes. Pursuant to this supplemental indenture, the guarantors of the Senior Notes also became guarantors of the Convertible Senior Notes. The guarantee of the Convertible Senior Notes was required under the indenture for the Convertible Senior Notes as a result of the issuance of their guarantees of the Senior Notes.

The Company valued the Convertible Senior Notes at May 21, 2008, as $309.6 million of debt and $64.2 million of equity representing the fair value of the conversion premium. The resulting debt discount is being amortized to interest expense through June 1, 2013, the first date on which the holders may require the Company to repurchase the Convertible Senior Notes, resulting in an effective interest rate of approximately 8% for the Convertible Senior Notes. Approximately $27.1 million of the unamortized debt discount associated with the Convertible Senior Notes purchased in the tender offer discussed above, was recognized as a component of the loss on the extinguishment of debt. Amortization of the debt discount amounted to $2.2 million and $3.1 million for the three months ended December 31, 2010 and 2009, respectively, and $11.6 million and $12.1 million for the years ended December 31, 2010 and 2009, respectively.

Prior Credit Facility

The Company had the Prior Credit Facility with Wells Fargo Bank, N.A., as administrative agent. The Prior Credit Facility provides for a revolving credit facility up to the lesser of the borrowing base or $350 million. It was secured by substantially all of the Company’s proved oil and gas assets and was guaranteed by certain of the Company’s subsidiaries: CCBM, Inc.; CLLR, Inc.; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC; Carrizo Marcellus Holding, Inc.; Hondo Pipeline, Inc.; Bandelier Pipeline Holding, LLC; Chama Pipeline Holding LLC; and Mescalero Pipeline, LLC. This facility was repaid and terminated in January 2011.

In December 2010, the borrowing base was decreased from $375 million to $350 million as a result of the net increase in debt associated with the $400 million issuance of the Senior Notes and the repurchase of $300 million of the Convertible Senior Notes.

If the outstanding principal balance of the revolving loans under the Senior Credit Facility exceeded the borrowing base at any time, the Company had 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 have been in addition to any payments that would have come due as a result of the quarterly borrowing base reductions. Otherwise, any unpaid principal or interest would have been due at maturity.

The annual interest rate on each base rate borrowing was (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 1.00% and 2.00% (depending on the then-current level of borrowing base usage), but such interest rate was never lower than the adjusted Daily LIBO rate on such day plus a margin between 2.25% to 3.25% (depending on the current level of borrowing base usage). The interest rate on each Eurodollar loan was the adjusted daily LIBO rate plus a margin between 2.25% to 3.25% (depending on the then-current level of borrowing base usage). At December 31, 2010, the average interest rate for amounts outstanding under the Prior Credit Facility was 3.0%.

The Prior Credit Facility contained certain financial covenants which we were required to maintain until the Prior Credit Facility was terminated in January 2011: a minimum current ratio, a maximum total net debt and a maximum ratio of senior debt to Consolidated EBITDA. As defined in the Prior Credit Facility, the current ratio was 2.80 to 1, the total net debt to Consolidated EBITDA ratio was 3.42 to 1 and the ratio of senior debt to Consolidated EBITDA ratio was 0.58 to 1 as of December 31, 2010.

The Prior Credit Facility also placed restrictions on indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, swap agreements, transactions with affiliates and other matters.

The Prior Credit Facility was subject to customary events of default, the occurrence and continuation of which could have resulted in the acceleration of amounts due under the facility by the agent or the lenders.

At December 31, 2010, we had $93.5 million of borrowings outstanding under the Prior Credit Facility. We had also issued $4.1 million of letters of credit which reduced the amounts available under the Prior Credit Facility. The Prior Credit Facility was used to fund ongoing working capital needs and the remainder of the Company’s capital expenditure plan only to the extent such

amounts exceeded the cash flow from operations, proceeds from the sale of oil and gas properties, proceeds from any cash distributions on our B Unit investment in ACP II and securities offerings.

On January 27, 2011, we terminated the Prior Credit Facility and entered into the Revolving Credit Facility described below.

Revolving Credit Facility

On January 27, 2011, we entered into the Revolving Credit Facility. The Revolving Credit Facility provides for a revolving credit facility up to the lesser of (i) the Borrowing Base and (ii) $750 million. The Revolving Credit Facility matures on January 27, 2016. It is secured by substantially all of our assets and is guaranteed by certain of our subsidiaries: Bandelier Pipeline Holding, LLC, Carrizo Marcellus Holding Inc., Carrizo (Marcellus) LLC, Carrizo (Marcellus) WV LLC, CLLR, Inc., Hondo Pipeline, Inc. and Mescalero Pipeline, LLC.

The initial Borrowing Base under the Revolving Credit Facility is $350 million. The Borrowing Base will be redetermined by the lenders at least semi-annually on each May 1 and November 1, beginning May 1, 2011. We and the lenders may each request one unscheduled borrowing base redetermination between each scheduled redetermination. The Borrowing Base will also be reduced in certain circumstances as a result of certain issuances of senior notes, cancellation of certain hedging positions and as a result of certain asset sales. The amount we are able to borrow with respect to the Borrowing Base is subject to compliance with the financial covenants and other provisions of the Revolving Credit Facility.

If the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the Revolving Credit Facility exceeds the Borrowing Base at any time as a result of a redetermination of the Borrowing Base, 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, deliver reserve engineering reports and mortgages covering additional oil and gas properties 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 next six-month period. Upon certain adjustments to the Borrowing Base, we are required to make a lump sum payment in an amount equal to the amount by which the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the Revolving Credit Facility exceeds the Borrowing Base. Otherwise, any unpaid principal 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 Federal Funds Effective Rate plus 0.5% and the adjusted LIBO rate for a three-month interest period on such day plus 1.00%, plus (b) a margin between 1.00% and 2.00% (depending on the then-current level of borrowing base usage). The interest rate on each Eurodollar loan will be the adjusted LIBO rate for the applicable interest period plus a margin between 2.00% to 3.00% (depending on the then-current level of borrowing base usage).

We are subject to certain covenants under the terms of the Revolving Credit Facility which include, but are not limited to, the maintenance of the following financial covenants: (1) a total net debt to Consolidated EBITDA (as defined in the Revolving Credit Facility) ratio of not more than (a) 4.75 to 1.00 for any fiscal quarter ending on or after March 31, 2011 and on or before December 31, 2011, (b) 4.25 to 1.00 for any fiscal quarter ending on or after March 31, 2012 and on or before June 30, 2012 and (c) 4.00 to 1.00 for any fiscal quarter ending on or after September 30, 2012; (2) a current ratio of not less than 1.0 to 1.0; (3) senior debt to EBITDA ratio of not more than 2.50 to 1.00; and (4) an EBITDA to interest expense ratio of not less than 2.50 to 1.00.

The Revolving Credit Facility also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of our common stock, redemptions of our senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.

The Revolving Credit Facility is subject to customary events of default, including a change in control (as defined in the Revolving Credit Facility). If an event of default occurs and is continuing, the Majority Lenders (as defined in the Revolving Credit Facility) may accelerate amounts due under the Revolving Credit Facility (except for a bankruptcy event of default, in which case such amounts will automatically become due and payable).

On January 27, 2011, we borrowed $112 million under the Revolving Credit Facility, which was used to repay in full indebtedness outstanding under the Prior Credit Facility, to pay transaction costs associated with entering into the Revolving Credit Facility and for other general business purposes.

Huntington Field Development Project Credit Facility

On January 28, 2011, the Company and Carrizo UK, as Borrower, entered into the Huntington Facility. The Huntington Facility is secured by substantially all of Carrizo UK’s assets and is limited recourse to the Company. The Huntington Facility provides financing for a substantial portion of Carrizo UK’s share of costs associated with the Huntington Field development project in the U.K. North Sea. The Huntington Facility provides for a multi-currency credit facility consisting of (1) a term loan facility to be used to fund Carrizo UK’s share of project development costs, (2) a contingent cost overrun term loan facility and (3) a post-completion revolving credit facility providing for loans and letters of credit to be used to fund certain abandonment and decommissioning costs following project completion.

The total term loan facility commitment is $55 million, with availability under the facility subject to a borrowing base, which is currently in excess of the commitment. The total cost overrun facility commitment is $6.5 million, which may be utilized only when funds under the term loan facility have been exhausted and certain other requirements are satisfied. The total post-completion revolving credit facility commitment is $22.5 million. Availability under each of the term loan facility and the cost overrun facility is subject to borrowing bases that are generally based on consolidated cash flow and debt service projections for Carrizo UK attributable to certain proved reserves in the Huntington Field project. The borrowing bases of the term loan facility and the cost overrun facility will be redetermined by the lenders at least semi-annually on each April 1 and October 1 in connection with the updating and recalculation of revenue and cash flow projections with respect to the Huntington Field project, except that the first such redetermination and recalculation will take place on May 1, 2011. If the outstanding principal balance of the term loan facility and cost overrun facility exceeds the aggregate borrowing base for such facility at any time as a result of a redetermination of such facility’s borrowing base, Carrizo UK will be obligated to make a payment to cure the deficiency within five business days.

Initial borrowings under the term loan facility and cost overrun facility are conditioned on, among other things, the Company’s having made an approximate $22 million equity contribution to Carrizo UK, which was completed during the first quarter of 2011. Prior to project completion, the Company may be responsible under the Huntington Facility for making an additional equity contribution to Carrizo UK in the event the term loan borrowing base is reduced to a level at or above the amount of borrowings then outstanding. The Company may also be responsible under the Huntington Facility for making certain additional equity contributions to Carrizo UK in the event of certain specified projected Cost Overruns (as defined in the Huntington Facility). To the extent that the cost overrun facility and any required equity contributions are insufficient, the Company is responsible for funding any Cost Overruns on a 100% basis. If after project completion, the lenders reasonably determine that Carrizo UK is required to incur additional capital expenditures that were not contemplated by the Huntington Field development plan originally approved by the U.K. Department of Energy and Climate Change, the Company responsible for funding such additional expenditures. The Company is responsible for making certain other payments under the Huntington Facility, including funding certain projected working capital shortfalls, providing cash collateral for letters of credit issued under the post-completion revolving credit facility and paying certain costs of the required hedging arrangements described below.

The annual interest rate on each borrowing is (a) LIBOR (EURIBOR for euro-denominated loans) for the applicable interest period, plus (b) a margin of (i) 3.50% until the completion of the Huntington Field development project and 3.0% thereafter for the term loan credit facility and post-completion revolving credit facility or (ii) 4.75% for the cost overrun facility. Borrowings under the term loan and cost overrun facilities are available until the earlier of December 31, 2012 or the achievement of certain project development milestones. The term loan and cost overrun facilities mature on December 31, 2014, subject to acceleration in the event that future projection estimates of remaining reserves in the project area have declined to less than 25% of the level initially projected by Carrizo UK and the lenders. Letters of credit under the post-completion revolving credit facility mature on December 31, 2016. Amounts outstanding under the term loan or cost overrun facility must be repaid according to the following schedule: (i) 45% will be due on December 31, 2012, (ii) 20% will be due on June 30, 2013, (iii) 20% will be due on December 31, 2013, (iv) 10% will be due on June 30, 2014 and (iv) the remaining 5% will be due on the final maturity date of December 31, 2014.

The Huntington Facility requires Carrizo UK to enter into certain hedging arrangements to hedge a specified portion of the Huntington Field project’s exposure to fluctuating petroleum prices. This obligation was satisfied in February 2011. In addition, Carrizo UK may, but is not required, to hedge its exposure to changes in interest rates or exchange rates, and permits Carrizo UK to enter into additional hedging arrangements. The Huntington Facility places restrictions on Carrizo UK with respect to additional indebtedness, liens, the extension of credit, dividends or other payments to the Company or its other subsidiaries, investments, acquisitions, mergers, asset dispositions, commodity transactions outside of the mandatory hedging program, transactions with affiliates and other matters.

The Huntington Facility is subject to customary events of default. If an event of default occurs and is continuing, the Majority Lenders (as defined in the Huntington Facility) may accelerate amounts due under the Huntington Facility.

Securities Offerings in 2010 and 2009

In November 2010, we issued $400 million aggregate principal amount of Senior Notes, which are guaranteed by substantially all of our wholly-owned subsidiaries. We used the net proceeds of approximately $387.5 million after deducting initial purchasers’ discounts and our estimated expenses, to repay initially in full borrowings outstanding under the Prior Credit Facility and held the remaining net proceeds in short-term investments. We subsequently purchased the $300 million of Senior Convertible Notes in the tender offer with a combination of cash on hand and borrowings under the Prior Credit Facility.

In April 2010, we sold 3.22 million shares of our common stock in an underwritten public offering at a price to the underwriter of $23.00 per share. We used the net proceeds of approximately $73.8 million to repay a portion of the outstanding borrowings under the Prior Credit Facility.

Lease Option Arrangements

From time to time, we have entered into lease purchase option arrangements with third parties. We currently have one lease purchase option arrangement described below 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.

On November 24, 2009, we entered into a Land Agreement (the “Land Agreement”) with an unrelated third party and its affiliate. Under this arrangement, we may until May 31, 2011 acquire up to $20 million of oil, gas and mineral interests/leases in certain specified areas in the Barnett Shale from the third party. In consideration of our receipt of an option to purchase the leases acquired by the third party (as described below), each time the third party purchases a lease group under the Land Agreement, if any, we will issue to the third party’s affiliate warrants to purchase a number of shares of our Common Stock equal to the quotient of (rounded up to the nearest whole number) (1) 20% of the purchase price of such lease group divided by (2) $13.00, with an exercise price of $22.09 and an expiration date of August 21, 2017. In addition, under certain circumstances where we reach surface casing point on an initial well in one of the areas covered by the Land Agreement but have not achieved a specified lease up threshold for acreage in such area, we will issue additional warrants to the third party’s affiliate, on the same terms, to purchase a number of shares of common stock equal to the quotient (rounded up to the nearest whole number) of (1) 20% of the product of (A) the number of acres below the specified lease up threshold multiplied by (B) $5,000, divided by (2) $13.00. The warrants are subject to antidilution adjustments and may be exercised on a “cashless” basis.

We have the option to purchase the lease groups acquired by the third party within 180 days after the third party’s acquisition at a cost equal to 110% of the original purchase price. We may pay the purchase price for the lease groups, at our election, by delivering cash to the third party or by delivering shares of Common Stock to the third party’s affiliate. Any shares of Common Stock delivered to the third party’s affiliate will generally be valued at the average of the daily-volume weighted average price of the Common Stock for each day in the 10-business day period beginning on the business day immediately after the date on which we notify the third party of our election to exercise the option (such amount not to exceed the daily-volume weighted average price of the Common Stock for either the first or last business day in such period).

We may twice extend the option for an additional 180 days each if we pay the third party an amount equal to five percent of the original purchase price for the applicable lease group upon each extension. If we do not exercise our option to purchase a lease group within the applicable option period, then the third party has two 30-day options, one commencing on the expiration of our option period for such lease group, and the other commencing on April 1, 2013, to exchange such lease group for certain of our acreage in the Marcellus Shale.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing oil and gas prices. The significant decline in gas prices since mid-2008 and the continued depressed price of gas has resulted in a significant decline in revenue per unit of production. Although operating costs have also declined, the rate of decline in gas 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 Adopted Accounting Pronouncements

On January 1, 2010, we adopted new accounting guidelines to improve disclosures about fair value measurements. The additional disclosures required include: (1) the different classes of assets and liabilities measured at fair value, (2) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (3) the gross presentation of purchases, sales, issuances and settlements for the rollforward of Level 3 activity and (4) the transfers in and out of Levels 1 and 2 and the reasons for such transfers.

In January 2010, the FASB issued Accounting Standards Update No. 2010-03 to align the oil and gas reserve estimation and disclosure requirements of Topic 932 (“Extractive Industries — Oil and Gas”) with the requirements of SEC Release 33-8994. This release is effective for financial statements issued on or after January 1, 2010. We adopted this guidance effective December 31, 2009. This release changes the accounting and disclosure requirements of oil and gas reserves and is intended to modernize and update the oil and gas disclosure requirements, to align them with current industry practices and to adapt to changes in technology. The new rules permit the use of new technologies to determine proved reserves, allow companies to disclose their probable and possible reserves and allow proved undeveloped reserves to be maintained beyond a five-year period only if justified by specific circumstances. The new rules require companies to report the independence and qualification of the person primarily responsible for the preparation or audit of its reserve estimates, and to file reports when a third party is relied upon to prepare or audit its reserve estimates. The new rules also require that the net present value of oil and gas reserves, which is used in the determination of the full cost center ceiling, be based upon average market prices for oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period.

Summary of Critical Accounting Policies

The following summarizes 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 disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates. We evaluate subsequent events through the date the financial statements are issued.

Significant estimates include volumes of proved oil and gas reserves which are used in calculating the amortization of proved oil and gas property costs, the present value of future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and asset retirement obligations. Other significant estimates include the, impairment of unproved properties, fair values of derivative instruments, stock-based compensation, the collectability of outstanding receivables, and contingencies. Proved oil and gas reserve estimates have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality and quantity of available data and the application of engineering and geological interpretation and judgment to available data. Subsequent drilling results, testing and production may justify revisions of such estimates. Accordingly, proved oil and gas reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. In addition, proved oil and gas reserve estimates are vulnerable to changes in market prices of oil and gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

Estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices of oil and gas, the credit worthiness of counterparties, interest rates and the market value and volatility of the Company’s common stock. Future changes in these assumptions may affect these significant estimates materially in the near term.

Oil and Gas Properties

Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to costs centers established on a country-by-country basis. Internal costs directly identified with acquisition, exploration and development activities are capitalized and totaled $5.3 million, $5.6 million, and $7.8 million for the years ended December 31, 2010, 2009, and 2008, respectively. Costs related to production, general corporate overhead or similar activities are expensed as incurred.

Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting oil and natural gas liquids to gas equivalents at the ratio of one barrel of oil or natural gas liquids to six thousand cubic feet of gas, which represents their approximate relative energy content. The equivalent unit-of-production rate is computed on a quarterly basis by dividing production by proved oil and gas reserves at the beginning of the quarter which is applied to capitalized oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average DD&A per Mcfe was $1.25, $1.55, and $2.23 for the years ended December 31, 2010, 2009 and 2008, respectively.

Costs not subject to amortization include unevaluated leasehold costs, seismic costs associated with specific unevaluated properties, related capitalized interest and the cost of exploratory wells in progress. Significant costs are assessed individually on a quarterly basis to determine whether or not and to what extent proved reserves have been assigned to the properties or if an impairment has occurred, in which case the related costs are added to the oil and gas property costs subject to amortization. Factors the Company considers in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production and drilling capital expenditure plans. We expect to complete the evaluation of the majority of our unproved properties within the next two to five years. Insignificant costs are grouped by major area and added to the oil and gas property costs subject to amortization based on the average primary lease terms of the properties. We capitalized interest costs associated with our unevaluated leasehold and seismic costs of $20.7 million, $19.7 million, and $20.5 million for the years ended December 31, 2010, 2009 and 2008, respectively. Interest is capitalized using a weighted-average interest rate based on outstanding borrowings.

Proceeds from the sale of oil and gas properties are accounted for as reductions of capitalized costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. We have not had any sales of oil and gas properties that significantly alter that relationship.

Capitalized costs, less accumulated amortization and related deferred income taxes, are limited to the “cost center ceiling” equal to (1) the sum of (A) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (B) the costs of properties not subject to amortization, and (C) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (2) related income tax effects. If the net capitalized costs exceed the cost center ceiling, the excess is recognized as an impairment of oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period.

We recognized impairments of oil and gas properties at December 31, 2008, December 31, 2009 and March 31, 2009. The December 31, 2009 impairment of oil and gas properties of $122.5 million was based on crude oil and condensate prices of $56.10 per barrel, natural gas liquids prices of $23.18 per barrel and natural gas prices of $3.30 per Mcf, which represent the unweighted average market prices of crude oil and condensate, natural gas liquids and natural gas prices on the first calendar day of each month during the 12-month period ended December 31, 2009, as required by the oil and gas reserve estimation and disclosure requirements adopted effective December 31, 2009.

The March 31, 2009 impairment of oil and gas properties of $216.4 million was based on crude oil and condensate prices of $45.13 per barrel, natural gas liquids prices of $18.92 per barrel and natural gas prices of $2.73 per Mcf, which represent the market prices as of May 6, 2009. The oil and gas reserve estimation and disclosure requirements in effect at the time allowed the use of market prices subsequent to the balance sheet date for purposes of calculating the impairment of oil and gas properties. The December 31, 2008 impairment of oil and gas properties of $178.5 million was based on crude oil and condensate prices of $40.12 per barrel, natural gas liquids prices of $19.62 per barrel and natural gas prices of $4.99 per Mcf, which represent market prices on December 31, 2008. The requirement to use market prices in effect on the balance sheet date with the option to use market prices subsequent to the balance sheet date was superseded by the new requirements that the Company adopted effective December 31, 2009, as discussed above.

The cost center ceiling exceeded our net capitalized costs for the U.S. cost center at December 31, 2010 by approximately $208.0 million and was based on crude oil and condensate prices of $72.13 per barrel, natural gas liquids prices of $35.18 per barrel and natural gas prices of $3.47 per Mcf (or a volume weighted average price of $4.37 per Mcfe), representing the unweighted average market prices on the first calendar day of each month during the 12-month period ended December 31, 2010. A ten percent increase in average market prices at December 31, 2010 would have increased the cost center ceiling by approximately $108 million and a ten percent decrease in average market prices would have decreased the cost center ceiling by approximately $172 million. This sensitivity analysis is as of December 31, 2010 and, accordingly, does not consider drilling results, production and prices subsequent to December 31, 2010 that may require revisions of proved reserve estimates.

We have a significant amount of proved undeveloped reserves. We had 437.8 Bcfe, 267.8 Bcfe and 239.1 Bcfe of proved undeveloped reserves, representing 52%, 44% and 48% of our total proved reserves at December 31, 2010, 2009 and 2008, respectively. Approximately 311.4 Bcfe, or 71%, and 84.5 Bcfe, or 19%, of our proved undeveloped reserves at December 31, 2010, are attributable to the Barnett Shale and Eagle Ford Shale, respectively. We currently expect to drill wells associated with these undeveloped reserves within the next five years.

Because our depletion rate is based on the ratio of production to total proved reserves, we expect our relatively low historical depletion rate to continue until the level of undeveloped reserves in relation to total proved reserves is reduced through the development of existing undeveloped reserves and/or the significant addition of proved developed reserves through acquisition and/or exploration. If our level of total proved reserves and future development costs were to remain constant and average market prices were to decline, a lower depletion rate would result in an impairment of oil and gas properties earlier or to a larger extent than would a higher depletion rate.

Oil and Gas Reserve Estimates

The proved oil and gas reserve estimates as of December 31, 2010 included in this document have been prepared by Ryder Scott Company Petroleum Engineers, LaRoche Petroleum Consultants, Ltd., and Fairchild and Wells, Inc., independent third party reserve 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 assumptions regarding drilling and operating costs, taxes and availability of funds. The oil and gas reserve estimation and disclosure requirements mandate certain of these assumptions such as existing economic and operating conditions, average oil and gas prices and the discount rate.

Proved oil and gas reserve estimates prepared by others may be substantially higher or lower than our estimates. Significant assumptions used by the independent third party reserve engineers are assessed by our internal reserve team. All reserve reports prepared by the independent third party reserve engineers are reviewed by our senior management team, including the Chief Executive Officer and Chief Operating Officer. 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 production.

You should not assume that the present value of future net cash flows is the current market value of our estimated proved oil and gas reserves. In accordance with the oil and gas reserve estimation and disclosure requirements, the discounted future net cash flows from proved reserves are based on the unweighted average of the first day of the month price for each month in the previous twelve-month period, using current costs and a 10% discount rate.

Our depletion rate depends on our estimate of total proved reserves. If our estimates of total proved reserves increased or decreased, the depletion rate and therefore DD&A expense would decrease or increase, respectively. A 10% increase or decrease in our estimates of total proved reserves at December 31, 2010, would have decreased or increased our DD&A expense by approximately 9% or 11%, respectively, for the fourth quarter of 2010.

Derivative Instruments

We use derivative instruments, typically fixed-rate swaps, costless collars, puts, calls and basis differential swaps, to manage commodity price risk associated with a portion of our forecasted oil and gas production. Derivative instruments are recognized at their current fair value as assets or liabilities in the consolidated balance sheets. Although the derivative instruments provide an economic hedge of our exposure to commodity price risk associated with oil and gas production, because we elect not to meet the criteria to qualify our derivative instruments for hedge accounting treatment, unrealized gains and losses as a result of changes in the fair value

of derivative instruments are recognized as gain (loss) on derivative instruments, net in the consolidated statements of operations. Realized gains and losses as a result of cash settlements with counterparties to our derivative instruments are also recorded as gain (loss) on derivative instruments, net in the consolidated statements of operations. We offset fair value amounts recognized for derivative instruments executed with the same counterparty.

Our Board of Directors establishes risk management policies and reviews derivative instruments, including volumes, types of instruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with approved counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades.

Income Taxes

Deferred income taxes are recognized at each reporting period 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 and consider our estimate of future taxable income based on production of proved reserves at estimated future pricing 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, the deferred tax assets are reduced by a valuation allowance. We classify interest and penalties associated with income taxes as interest expense.

Commitments and Contingencies

Liabilities are recognized for contingencies when 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 Gas Prices

Our revenues, future growth rate, results of operations, financial position and ability to borrow funds or obtain additional capital, as well as the carrying value of our oil and gas properties, are substantially dependent upon prevailing prices of oil and gas.

We review the carrying value of our oil and gas properties on a quarterly basis using the full cost method of accounting. See “ —Summary of Critical Accounting Policies—Oil and Gas Properties.”

We rely on various types of derivative instruments to manage our exposure to commodity price risk and to provide a level of certainty in our forward cash flows supporting our capital expenditure program. The derivative instruments we typically use include fixed-rate swaps, costless collars, puts, calls and basis differential swaps. Under these derivative instruments, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at termination, expiration or exchanged for physical delivery contracts. Our current long-term strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to 36 months. The derivative instruments are carried at fair value in the consolidated balance sheets, with the changes in fair value included in the consolidated statements of operations for the period in which the changes occur.

The fair value of derivative instruments at December 31, 2010 was a net asset of $24.1 million, 74% with Credit Suisse, 14% with Shell Energy North America (US) LP, 9% with Credit Agricole, and the remaining 3% with BNP Paribas and master netting agreements are in place with these counterparties. Because the counterparties are either investment grade financial institutions or an investment grade international oil and gas company, we believe we have minimal credit risk and accordingly do not currently require our counterparties to post collateral to support the asset positions of our derivative instruments. As such, we are exposed to credit risk to the extent of nonperformance by the counterparties to our derivative instruments. Although we do not currently anticipate such nonperformance, we continue to monitor the financial viability of our counterparties. Three of the four counterparties to our derivative instruments are lenders in the Revolving Credit Facility, and accordingly, we are not required to post collateral under these contracts as they are secured by the Revolving Credit Facility.

The following sets forth a summary of our natural gas derivative positions at average delivery location (Waha and Houston Ship Channel) prices as of December 31, 2010. Our crude oil derivative positions at December 31, 2010 were not significant.


Period	Volume (in MMbtu)		Weighted Average Floor Price ($/MMbtu)		Weighted Average Ceiling Price ($/MMbtu)
2011		21,340,000	$	5.96	$	6.34
2012		7,963,000	$	6.49	$	7.13

In connection with the derivative instruments above, we have entered into protective put spreads. When the market price declines below the short put price as reflected below, we will effectively receive the market price plus a put spread. For example, for 2011, if market prices fall below the short put price of $4.55, the floor price becomes the market price plus the put spread of $1.46 on 16,799,000 of the 21,340,000 MMBtus and the remaining 4,541,000 MMBtus have a long put price of $5.96.


Period	Volume (in MMbtu)		Weighted Average Short Put Price ($/MMbtu)		Weighted Average Long Put Price ($/MMbtu)		Weighted Average Put Spread ($/MMbtu)
2011		16,799,000	$	4.55	$	6.01	$	1.46
2012		6,404,000	$	5.20	$	6.41	$	1.21

For the years ended 2010, 2009 and 2008, we recorded the following related to our derivative instruments:


	Year Ended December 31,
	2010		2009			2008
	(In thousands)

Realized gain (loss)
Natural gas and oil derivatives	$	33,218	$	74,866		$	(1,819	)
Interest rate swaps		—		—			(1,201	)
Loss on interest swap termination		—		—			(3,340	)

		33,218		74,866			(6,360	)

Unrealized gain (loss)
Natural gas and oil derivatives		14,564		(33,401	)		41,104
Interest rate swaps		—		—			2,755

		14,564		(33,401	)		43,859

Gain on derivative instruments, net	$	47,782	$	41,465		$	37,499

We deferred the payment and receipt of premiums associated with certain derivative instruments totaling a net liability of $3.9 million and $4.8 million at December 31, 2010 and December 31, 2009, respectively. We classified $3.9 million and $1.8 million as other current liabilities at December 31, 2010 and December 31, 2009, respectively, and $3.0 million as other non-current liabilities at December 31, 2009. The deferred premiums will be paid to the counterparty with each monthly settlement (January 2011 – December 2011) and recognized as a reduction of realized gain on derivative instruments.

Item 7A.

Qualitative and Quantitative Disclosures about Market Risk

Commodity Risk. Our primary market risk exposure is the commodity pricing applicable to our oil and gas production. The prices we realize on the sale of such production are primarily driven by the prevailing worldwide price for oil and spot prices of natural gas. The effects of such pricing volatility have been discussed above, and such volatility is expected to continue. A 10% fluctuation in the price received for oil and gas production would have an approximate $13.8 million impact on our revenues for the year ended December 31, 2010.

We rely on various types of derivative instruments to manage the Company’s exposure to commodity price risk and to provide a level of certainty in our forward cash flows supporting our capital expenditure program. The derivative instruments we typically use include fixed-rate swaps, costless collars, puts, calls and basis differential swaps. Our current long-term strategy is to manage

exposure for a substantial, but varying, portion of forecasted production up to 36 months. We do not hold or issue derivative instruments for trading purposes. We realized gains on derivative instruments of $47.8 million, $41.5 million and $37.5 million for the years ended December 31, 2010, 2009, and 2008, respectively.

Financial Instruments and Debt Maturities. In addition to our derivative instruments, our other financial instruments include cash and cash equivalents, receivables, payables and current and long-term debt. The carrying amounts of cash and cash equivalents, receivables, payables and short-term debt approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of borrowings under the Prior Credit Facility approximate the carrying amounts as of December 31, 2010, and were based upon interest rates currently available to the Company for borrowings with similar terms. The fair values of the Convertible Senior Notes and Senior Notes at December 31, 2010 were estimated at approximately $71.9 million and $412 million, respectively and were based on quoted market prices. As of December 31, 2010, scheduled maturities of long-term debt are $93.5 million in 2012, $73.8 million in 2013 and $400 million in 2018.

Item 8.

Financial Statements and Supplementary Data

The response to this item is included elsewhere in this Annual Report on Form 10-K.

Item 9.

Changes In and Disagreements With Accountants on Accounting and Financial Disclosures

None.

Item 9A.

Controls and Procedures

(a) Disclosure Controls and Procedures. We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission (the “Commission”) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

In accordance with Exchange Act Rules 13a-15(b) and 15d-15(b), we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined by Exchange Act Rules 13a-15(e) and 15d-15(e)) as of the end of the period covered by this Annual Report on Form 10-K. As described below under paragraph (b) within Management’s Annual Report on Internal Control over Financial Reporting, our Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit to the Commission under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

The audit report of KPMG, LLP, which is included in this 2010 Form 10-K, expressed an unqualified opinion on our consolidated financial statements.

(b) Management’s Annual Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:

•

pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of our assets;

•

provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

•

provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.

While “reasonable assurance” is a high level of assurance, it does not mean absolute assurance. Because of its inherent limitations, internal control over financial reporting may not prevent or detect every misstatement and instance of fraud. Controls are susceptible to manipulation, especially in instances of fraud caused by collusion of two or more people, including our senior management. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2010. In making this evaluation, management used the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of our evaluation, our management concluded that our internal control over financial reporting was effective as of December 31, 2010.

KPMG LLP, our independent registered public accounting firm that audited our consolidated financial statements, has also issued its own report on the effectiveness of our internal control over financial reporting as of December 31, 2010, which is filed with this Annual Report on Form 10-K.

(c) Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting during the fiscal quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.

Other Information

None.

PART III

Item 10.

Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated by reference to our definitive Proxy Statement (the “2011 Proxy Statement”) for our 2011 annual meeting of shareholders. The 2011 Proxy Statement will be filed with the Commission not later than 120 days subsequent to December 31, 2010.

Pursuant to Item 401(b) of Regulation S-K, the information required by this item with respect to our executive officers is set forth in Part I of this Annual Report on Form 10-K.

Item 11.

Executive Compensation

The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2010.

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

Information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2010.

Item 13.

Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated herein by reference to the 2011 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2010.

Item 14.

Principal Accountant Fees and Services

The information required by this item is incorporated by reference to the 2011 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 2010.

PART IV

Item 15.

Exhibits and Financial Statement Schedules

(a)(1) Financial Statements

The response to this item is submitted in a separate section of this Annual Report on Form 10-K.

(a)(2) Financial Statement Schedules

None.

(a)(3) Exhibits

EXHIBIT INDEX


Exhibit Number		Description

†3.1	–	Amended and Restated Articles of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1997).

†3.2	–	Articles of Amendment to Amended and Restated Articles of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 25, 2008).

†3.3	–	Amended and Restated Bylaws of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on January 3, 2008).

†4.1	–	Indenture among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National Association, as trustee, dated May 28, 2008 (incorporated herein by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed on May 28, 2008).

†4.2	–	First Supplemental Indenture dated May 28, 2008 between Carrizo Oil & Gas, Inc. and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on May 28, 2008).

†4.3	–	Second Supplemental Indenture dated May 14, 2009 among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.21 to the Company’s Registration Statement on Form S-3 (Registration No. 333-159237)).

†4.4	–	Fourth Supplemental Indenture dated November 2, 2010 among Carrizo Oil & Gas, Inc. the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on November 2, 2010).

†4.5	–	Fifth Supplemental Indenture dated November 2, 2010 among Carrizo Oil & Gas, Inc. the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on November 2, 2010).

*†10.1	–	Amended and Restated Incentive Plan of the Company effective as of April 30, 2009 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 6, 2009).

*†10.2	–	Amended and Restated Employment Agreement between the Company and S.P. Johnson IV (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on June 9, 2009).

*†10.3	–	Amended and Restated Employment Agreement between the Company and Paul F. Boling (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on June 9, 2009).



*†10.4	–	Amended and Restated Employment Agreement between the Company and J. Bradley Fisher (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on June 9, 2009).

*†10.5	–	Amended and Restated Employment Agreement between the Company and Gregory E. Evans (incorporated herein by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on June 9, 2009).

*†10.6	–	Amended and Restated Employment Agreement between the Company and Richard H. Smith (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on June 9, 2009).

*†10.7	–	Employment Agreement between the Company and David L. Pitts (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 20, 2010).

*†10.8	–	Form of Stock Option Award Agreement (incorporated herein by reference to Exhibit 10.43 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004).

*†10.9	–	Form of Director Restricted Stock Award Agreement under the Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 22, 2005).

*†10.10	–	Form of Director Restricted Stock Award Agreement under the Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on April 22, 2005).

*†10.11	–	Form of Employee Restricted Stock Award Agreement under the Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on April 22, 2005).

*10.12	–	Form of 2010 Employee Restricted Stock Unit Award Agreement (with performance-based vesting and time-based vesting).

*†10.13	–	Form of 2009 Employee Restricted Stock Unit Award Agreement (with performance-based vesting only) (incorporated herein by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K filed on June 9, 2009).

*10.14	–	Form of 2010 Employee Cash Settled Stock Appreciation Rights Award Agreement under the Carrizo Oil & Gas, Inc. Incentive Plan.

*†10.15	–	Form of 2009 Employee Cash or Stock Settled Stock Appreciation Rights Award Agreement under the Carrizo Oil & Gas, Inc. Incentive Plan (incorporated herein by reference to Exhibit 10.9 to the Company’s Current Report on Form 8-K filed on June 9, 2009).

*†10.16	–	Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (incorporated herein by reference to Exhibit 10.10 to the Company’s Current Report on Form 8-K filed on June 9, 2009).

*†10.17	–	Form of 2009 Employee Cash-Settled Stock Appreciation Rights Award Agreement pursuant to the Carrizo Oil & Gas, Inc. Stock Appreciation Rights Plan (incorporated herein by reference to Exhibit 10.11 to the Company’s Current Report on Form 8-K filed on June 9, 2009).

*†10.18	–	Form of Independent Contractor Restricted Stock Award Agreement (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on May 30, 2006).

*†10.19	–	Form of Employee Restricted Stock Award Agreement (with performance-based vesting) (incorporated herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on December 23, 2008).

†10.20	–	S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (incorporated herein by reference to Exhibit 10.8 to the Company’s Registration Statement on Form S-1 (Registration No. 333-29187)).

†10.21	–	S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo Production, Inc. and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (incorporated herein by reference to Exhibit 10.9 to the Company’s Registration Statement on Form S-1 (Registration No. 333-29187)).



†10.22	–	Amended and Restated Registration Rights Agreement dated December 15, 1999 among the Company, Paul B. Loyd Jr., Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and DAPHAM Partnership, L.P. (incorporated herein by reference to Exhibit 99.5 to the Company’s Current Report on Form 8-K dated December 15, 1999).

†10.23	–	Registration Rights Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. and Steven A. Webster (incorporated herein by reference to Exhibit 99.5 to the Company’s Current Report on Form 8-K dated February 20, 2002).

†10.24	–	Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, the Lenders party thereto, JPMorgan Chase Bank, National Association, as Administrative Agent, and J.P. Morgan Securities Inc., as Sole Book runner and Lead Arranger (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 30, 2006).

†10.25	–	First Lien Stock Pledge and Security Agreement dated as of May 25, 2006, by Carrizo Oil & Gas, Inc., in favor of JPMorgan Chase Bank, National Association, as Administrative Agent (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 30, 2006).

†10.26	–	Second Amendment effective as of September 11, 2007 to Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, JPMorgan Chase Bank, National Association, as Administrative Agent and Lender, and Guaranty Bank as Lender (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 11, 2007).

†10.27	–	Third Amendment effective as of December 20, 2007 to Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, JPMorgan Chase Bank, National Association, as Administrative Agent and Lender, and Guaranty Bank as Lender (incorporated by reference to Exhibit 10.48 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2009).

†10.28	–	Fourth Amendment to Credit Agreement, dated as of May 20, 2008, by and among Carrizo Oil & Gas, Inc. and certain subsidiaries thereof, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 22, 2008).

†10.29	–	Fifth Amendment to Credit Agreement dated as of June 11, 2008 to Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 11, 2008).

†10.30	–	Sixth Amendment dated as of July 7, 2008 to Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, JPMorgan Chase Bank, N.A., as Administrative Agent, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 11, 2008).

†10.31	–	Seventh Amendment dated as of October 29, 2008 to Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, the Lenders party thereto, JPMorgan Chase Bank, N.A., as resigning administrative agent and as resigning issuing bank, and Guaranty Bank, as successor administrative agent and as successor issuing bank (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 4, 2008).

†10.32	–	Lender Certificate dated December 16, 2008 of Union Bank of California, N.A. regarding joinder as Lender to Credit Agreement, as amended, dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, Guaranty Bank, as Administrative Agent and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on December 22, 2008).

†10.33	–	Eighth Amendment dated as of April 22, 2009 to Credit Agreement dated May 25, 2006 by and among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, the Lenders party thereto, and Guaranty Bank, as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 28, 2009).



†10.34	–	Ninth Amendment dated as of April 30, 2009 to Credit Agreement dated May 25, 2006 by and among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, the Lenders party thereto, and Guaranty Bank, as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 6, 2009).

†10.35	–	Tenth Amendment to Credit Agreement dated as of May 20, 2009 among Carrizo Oil & Gas, Inc., as Borrower, certain Subsidiaries of Borrower, as Guarantors, the Lenders party thereto, Guaranty Bank, as resigning administrative agent and as resigning issuing bank, and Wells Fargo Bank, N.A., as successor administrative agent and as successor issuing bank (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 27, 2009).

†10.36	–	Lender Certificate dated June 5, 2009 of Calyon New York Branch regarding joinder as Lender to Credit Agreement, as amended, dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, Guaranty Bank, as Administrative Agent and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 9, 2009).

†10.37	–	Eleventh Amendment to Credit Agreement dated as of December 16, 2009 among Carrizo Oil & Gas, Inc., as Borrower, certain Subsidiaries of the Borrower, as Guarantors, the Lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent and issuing bank (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on December 17, 2009).

†10.38	–	Twelfth Amendment to Credit Agreement dated as of May 5, 2010, among Carrizo Oil & Gas, Inc., as Borrower, certain Subsidiaries of the Borrower, as Guarantors, the Lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent and issuing bank (incorporated by reference to Exhibit 10.40 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 30, 2010).

†10.39	–	Thirteenth Amendment to Credit Agreement, dated as of August 23, 2010 and effective as of September 10, 2010, among Carrizo Oil & Gas, Inc., as Borrower, certain Subsidiaries of the Borrower, as Guarantors, the Lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent and issuing bank (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 16, 2010).

†10.40	–	Fourteenth Amendment to Credit Agreement, dated as of October 21, 2010, among Carrizo Oil & Gas, Inc., as Borrower, certain Subsidiaries of the Borrower, as Guarantors, the Lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent and issuing bank (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 25, 2010).

†10.41	–	Credit Agreement dated as of January 27, 2011 among Carrizo Oil & Gas, Inc., as Borrower, BNP Paribas, as Administrative Agent, Credit Agricole Corporate and Investment Bank and Royal Bank of Canada, as Co-Syndication Agents, Capital One, N.A. and Compass Bank, as Co-Documentation Agents, BNP Paribas Securities Corp. as Sole Lead Arranger and Sole Bookrunner, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on February 2, 2011).

†10.42	–	Senior Secured Multicurrency Credit Facility Agreement dated as of January 28, 2011 among Carrizo UK Huntington Ltd., as Borrower, Carrizo Oil & Gas, Inc., as Parent, and BNP Paribas and Societe Generale as Lead Arrangers, Bookrunners and Original Lenders (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 2, 2011).

†10.43	–	Form of Indemnification Agreement between the Company and each of its directors and executive officers (incorporated herein by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10-K for the year ended December 31, 1998).

†10.44	–	Form of Amendment to Director Indemnification Agreement (incorporated herein by reference to Exhibit 99.8 to the Company’s Current Report a Form 8-K dated February 20, 2002).

†10.45	–	Omnibus Amendment among Carrizo (Marcellus) LLC, Carrizo Oil & Gas, Inc., Avista Capital Partners II, L.P. and ACP II Marcellus LLC, dated as of September 10, 2010 (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on September 16, 2010).



†10.46	–	Amended and Restated Participation Agreement, dated as of November 16, 2010, and effective as of October 1, 2010, among Carrizo (Marcellus) WV LLC, Carrizo Oil & Gas, Inc., Avista Capital Partners II, L.P. and ACP II Marcellus LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 19, 2010).

†16.1	–	Letter dated June 3, 2009 from Pannell Kerr Forster of Texas, P.C. to the Securities and Exchange Commission regarding a change in certifying accountant (incorporated herein by reference to Exhibit 16.1 to the Company’s Current Report on Form 8-K filed on June 4, 2009).

21.1	–	Subsidiaries of the Company.

23.1	–	Consent of KPMG LLP.

23.2	–	Consent of Pannell Kerr Forster of Texas, P.C.

23.3	–	Consent of Ryder Scott Company Petroleum Engineers.

23.4	–	Consent of Fairchild and Wells, Inc.

23.5	–	Consent of LaRoche Petroleum Consultants, Ltd.

31.1	–	CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	–	CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	–	CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2	–	CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1	–	Summary of Reserve Report and Report of Ryder Scott Company Petroleum Engineers as of December 31, 2010.

99.2	–	Summary of Reserve Report and Report of Fairchild and Wells, Inc. as of December 31, 2010.

99.3	–	Summary of Reserve Report and Report of LaRoche Petroleum Consultants, Ltd. as of December 31, 2010.

†	Incorporated by reference as indicated.

*	Management contract or compensatory plan or arrangement.

CARRIZO OIL & GAS, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


	PAGE
Reports of Independent Registered Public Accounting Firms		F-2
Consolidated Balance Sheets, December 31, 2010 and 2009		F-5
Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008		F-6
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008		F-7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008		F-8
Notes to Consolidated Financial Statements		F-9

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Carrizo Oil & Gas, Inc.:

We have audited the accompanying consolidated balance sheets of Carrizo Oil & Gas, Inc. and subsidiaries (the Company) as of December 31, 2010 and 2009, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Carrizo Oil & Gas, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Carrizo Oil & Gas, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 31, 2011, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

March 31, 2011

F-2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Carrizo Oil & Gas, Inc.:

We have audited Carrizo Oil & Gas, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Carrizo Oil & Gas, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting as presented within Item 9A. Controls and Procedures. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Carrizo Oil & Gas, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Carrizo Oil & Gas, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the years then ended, and our report dated March 31, 2011, expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, Texas

March 31, 2011

F-3

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

Carrizo Oil & Gas, Inc.

We have audited the accompanying consolidated statements of operations, shareholders’ equity and cash flows of Carrizo Oil & Gas, Inc. for the year ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated statements of operations, shareholders’ equity and cash flows of Carrizo Oil & Gas, Inc. for the year ended December 31, 2008 are presented fairly in all material respects in conformity with U.S. generally accepted accounting principles.

/s/ Pannell Kerr Forster of Texas, P.C.

Houston, Texas

March 12, 2009

(Except for Notes 4, 5 and 6 for which

the date is August 17, 2009)

F-4

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS


	December 31,
	2010			2009
	(In thousands, except per share amount)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,128		$	3,837
Accounts receivable, net
Oil and gas sales		16,027			13,202
Joint interest billing		14,309			4,901
Related party		—			445
Other		560			2,793
Advances to operators		487			540
Fair value of derivative instruments		17,698			8,404
Other current assets		7,123			1,278

Total current assets		60,332			35,400

PROPERTY AND EQUIPMENT, NET
Oil and gas properties using the full cost method of accounting:
Proved oil and gas properties, net		626,665			399,182
Costs not subject to amortization		352,479			330,607
Other property and equipment, net		3,913			3,911

TOTAL PROPERTY AND EQUIPMENT, NET		983,057			733,700

DEFERRED FINANCING COSTS, NET		14,670			9,738
INVESTMENTS		3,392			3,358
FAIR VALUE OF DERIVATIVE INSTRUMENTS		7,257			6,477
DEFERRED INCOME TAXES		72,587			70,217
INVENTORY		1,646			3,292
OTHER ASSETS		1,193			925

TOTAL ASSETS	$	1,144,134		$	863,107

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable, trade	$	33,653		$	19,907
Revenue and royalties payable		23,864			27,390
Current state tax payable		4,052			107
Accrued drilling costs		26,884			17,251
Accrued interest		5,953			1,922
Other accrued liabilities		11,838			11,013
Advances for joint operations		3,407			1,739
Current maturities of long-term debt		160			148
Deferred income taxes		5,286			1,474
Other current liabilities		3,907			1,777

Total current liabilities		119,004			82,728

LONG-TERM DEBT, net of current maturities and debt discount		558,094			520,188
ASSET RETIREMENT OBLIGATIONS		6,369			5,410
FAIR VALUE OF DERIVATIVE INSTRUMENTS		715			2,818
OTHER LIABILITIES		3,316			4,354
COMMITMENTS AND CONTINGENCIES SHAREHOLDERS’ EQUITY:
Common stock, $0.01 par value, 90,000 shares authorized, 38,906 and 31,100 shares issued and outstanding at December 31, 2010 and 2009, respectively)		389			311
Additional paid-in capital		630,845			431,757
Accumulated deficit		(174,598	)		(184,548	)
Accumulated other comprehensive income, net of income taxes		—			89

Total shareholders’ equity		456,636			247,609

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	1,144,134		$	863,107

The accompanying notes are an integral part of these consolidated financial statements.

F-5

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Years Ended December 31,
	2010			2009			2008
	(In thousands, except per share amounts)
REVENUES:
Oil and gas revenues	$	138,123		$	112,699		$	209,829
Other revenues		1,339			1,380			6,848

TOTAL REVENUES		139,462			114,079			216,677
COSTS AND EXPENSES:
Lease operating		23,662			25,050			28,666
Production tax		3,648			132			5,141
Ad valorem tax		3,707			5,022			4,078
Gas purchases		1,336			1,497			6,570
Depreciation, depletion and amortization		47,030			52,005			58,311
Impairment of oil and gas properties		2,731			338,914			178,470
General and administrative (inclusive of stock-based compensation expense of $16,608, $11,297 and $5,958 for the years ended December 31, 2010, 2009 and 2008, respectively)		35,906			30,136			23,425
Accretion expense related to asset retirement obligations		216			308			154

TOTAL COSTS AND EXPENSES:		118,236			453,064			304,815

OPERATING INCOME (LOSS)		21,226			(338,985	)		(88,138	)
OTHER INCOME AND EXPENSES:
Gain (loss) on derivative instruments, net		47,782			41,465			37,499
Loss on extinguishment of debt		(31,023	)		—			(5,689	)
(Impairment) recovery of investment in Pinnacle Gas Resources, Inc.		165			(2,091	)		—
Interest expense		(43,264	)		(38,286	)		(30,257	)
Capitalized interest		20,746			19,696			20,527
Other income, net		47			49			286

INCOME (LOSS) BEFORE INCOME TAXES		15,679			(318,152	)		(65,772	)
INCOME TAX (EXPENSE) BENEFIT		(5,729	)		113,307			20,725

NET INCOME (LOSS)	$	9,950		$	(204,845	)	$	(45,047	)

OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAXES:
Increase (decrease) in fair value of investment in Pinnacle Gas Resources, Inc., net of income taxes		17			55			(6,724	)
Reclassification of cumulative (increase) decrease in market value of investment in Pinnacle Gas Resources, Inc., net of income taxes		(106	)		1,333			—

COMPREHENSIVE INCOME (LOSS)	$	9,861		$	(203,457	)	$	(51,771	)


BASIC INCOME (LOSS) PER COMMON SHARE	$	0.29		$	(6.61	)	$	(1.49	)

DILUTED INCOME (LOSS) PER COMMON SHARE	$	0.29		$	(6.61	)	$	(1.49	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC		33,861			31,006			30,326
DILUTED		34,305			31,006			30,326

The accompanying notes are an integral part of these consolidated financial statements.

F-6

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY


	Common Stock					Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Shareholders’ Equity
	Shares			Amount		Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Shareholders’ Equity
	(In thousands, except share amounts)
BALANCE, January 1, 2008		28,009,152		$	280	$	239,672		$	65,344		$	5,425		$	310,721
Common stock issued, net of offering costs		2,587,500			26		135,049			—			—			135,075
Conversion premium related to Senior Convertible Notes		—			—		40,207			—			—			40,207
Stock options exercised for cash		65,400			1		261			—			—			262
Stock-based compensation		—			—		6,013			—			—			6,013
Restricted stock awards, net of forfeitures		203,306			2		(63	)		—			—			(61	)
Stock repurchased to settle tax withholding obligations		(5,711	)		—		(361	)		—			—			(361	)
Other Comprehensive loss, net of income taxes:
Fair value adjustment to Investment in Pinnacle, net of income tax benefit of $3,621		—			—		—			—			(6,724	)		(6,724	)
Net loss		—			—		—			(45,047	)		—			(45,047	)

Total comprehensive loss		—			—		—			—			—			(51,771	)

BALANCE, December 31, 2008		30,859,647		$	309	$	420,778		$	20,297		$	(1,299	)	$	440,085
Stock options exercised for cash		5,000			—		9			—			—			9
Stock-based compensation		—			—		10,543			—			—			10,543
Restricted stock awards and units, net of forfeitures		226,286			2		304			—			—			306
Other		9,500			—		123			—			—			123
Other Comprehensive loss, net of income taxes:
Fair value adjustment to Investment in Pinnacle, net of income tax expense of $31		—			—		—			—			55			55
Reclassification of cumulative decrease in fair of Investment in Pinnacle, net of income tax benefit of $758		—			—		—			—			1,333			1,333
Net loss		—			—		—			(204,845	)		—			(204,845	)

Total comprehensive loss		—			—		—			—			—			(203,457	)

BALANCE, December 31, 2009		31,100,433		$	311	$	431,757		$	(184,548	)	$	89		$	247,609
Stock options exercised for cash		266,433			3		687			—			—			690
Stock-based compensation							10,290			—			—			10,290
Restricted stock awards and units, net of forfeitures		344,311			3		(1,101	)		—			—			(1,098	)
Common stock issued, net of offering costs		7,195,000			72		188,462			—			—			188,534
Other		—			—		750			—			—			750
Other Comprehensive loss, net of income taxes:
Fair value adjustment to Investment in Pinnacle, net of income tax expense of $9		—			—		—			—			17			17
Reclassification of cumulative increase in fair of Investment in Pinnacle, net of income tax expense of $59		—			—		—			—			(106	)		(106	)
Net income		—			—		—			9,950			—			9,950

Total comprehensive income		—			—		—			—			—			9,861

BALANCE, December 31, 2010		38,906,177		$	389	$	630,845		$	(174,598	)	$	—		$	456,636

The accompanying notes are an integral part of these consolidated financial statements.

F-7

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS


	For the Years Ended December 31,
	2010			2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	9,950		$	(204,845	)	$	(45,047	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities-
Depreciation, depletion and amortization		47,030			52,005			58,311
Impairment of oil and gas properties		2,731			338,914			178,470
Unrealized (gain) loss on derivative instruments		(14,564	)		33,401			(43,859	)
Allowance for doubtful accounts		485			772			(166	)
Accretion of discount on asset retirement obligations		216			308			154
Loss on extinguishment of debt		31,023			—			4,601
Stock-based compensation		16,608			11,297			5,952
Deferred income taxes		1,493			(113,374	)		(20,920	)
Amortization of discount and deferred financing costs, net of amounts capitalized		7,716			5,898			1,825
Impairment (recovery) of investment in Pinnacle Gas Resources, Inc.		(165	)		2,091			—
Other		3,262			5,865			5,272
Changes in operating assets and liabilities-
Accounts receivable		(10,040	)		(656	)		5,119
Other, net		(2,173	)		(876	)		(3,661	)
Accounts payable		913			558			(1,476	)
Accrued liabilities		(69	)		2,014			4,179

Net cash provided by operating activities		94,416			133,372			148,754

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(347,808	)		(182,907	)		(571,291	)
Change in capital expenditure payables and accruals		22,540			(25,685	)		11,808
Proceeds from sales of oil and gas properties		54,217			48,524			3,259
Advances to operators		53			(204	)		776
Advances for joint operations		1,668			(2,076	)		2,943
Other		(966	)		(105	)		(2,840	)

Net cash used in investing activities		(270,296	)		(162,453	)		(555,345	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from common stock offerings, net of offering costs		188,534			—			135,075
Proceeds from stock options exercised		690			9			262
Proceeds from borrowings and issuances		916,308			128,113			778,182
Debt repayments		(917,148	)		(96,461	)		(498,923	)
Payments of debt issuance and retirement costs		(12,213	)		(3,927	)		(10,847	)

Net cash provided by financing activities		176,171			27,734			403,749

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		291			(1,347	)		(2,842	)
CASH AND CASH EQUIVALENTS, beginning of year		3,837			5,184			8,026

CASH AND CASH EQUIVALENTS, end of year	$	4,128		$	3,837		$	5,184

SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest, net of amounts capitalized	$	24,218		$	16,347		$	4,160

Cash paid for income taxes	$	95		$	67		$	30

The accompanying notes are an integral part of these consolidated financial statements.

F-8

CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. NATURE OF OPERATIONS

Carrizo Oil & Gas, Inc. is an independent energy company which, together with its subsidiaries (collectively referred to herein as the “Company”), is engaged in the exploration, development and production of oil and gas in the United States and the U.K. North Sea. The Company’s current operations are principally focused in proven, producing oil and gas plays in the Barnett Shale in North Texas, the Marcellus Shale in Pennsylvania, New York and West Virginia, the Eagle Ford Shale in South Texas, the Niobrara formation in Colorado and the Huntington Field located in the U.K. North Sea.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and LLCs where the Company, as a partner or member, has undivided interests in the oil and gas properties.

Investments

The Company accounts for its investment in Pinnacle Gas Resources, Inc. as available-for-sale and adjusts the book value to fair value through other comprehensive income (loss), net of income taxes. This fair value is assessed quarterly for other than temporary impairment based on publicly available information. If the impairment is deemed other than temporary, it is recognized in earnings. Subsequent recoveries in fair value are reflected as increases to investments and other comprehensive income (loss), net of income taxes.

The Company accounts for its investment in Oxane Materials, Inc. using the cost method of accounting and adjusts the carrying amount of its investment for contributions to and distributions from the entity.

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications had no effect on total assets, total liabilities, shareholders’ equity, net income (loss), comprehensive income (loss) or net cash provided by or used in operating, investing or financing activities.

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 disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these estimates. The Company evaluates subsequent events through the date the financial statements are issued.

F-9

Oil and Gas Properties

Costs not subject to amortization include unevaluated leasehold costs, seismic costs associated with specific unevaluated properties, related capitalized interest and the cost of exploratory wells in progress. Significant costs are assessed individually on a quarterly basis to determine whether or not and to what extent proved reserves have been assigned to the properties or if an impairment has occurred, in which case the related costs are added to the oil and gas property costs subject to amortization. Factors the Company considers in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production and drilling capital expenditure plans. The Company expects to complete its evaluation of the majority of its unproved properties within the next two to five years. Insignificant costs are grouped by major area and added to the oil and gas property costs subject to amortization based on the average primary lease terms of the properties. The Company capitalized interest costs associated with its unevaluated leasehold and seismic costs of $20.7 million, $19.7 million, and $20.5 million for the years ended December 31, 2010, 2009 and 2008, respectively. Interest is capitalized using a weighted-average interest rate based on outstanding borrowings.

Proceeds from the sale of oil and gas properties are recognized as a reduction of capitalized oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company has not had any sales of oil and gas properties that significantly alter that relationship.

In connection with the formation of ACP II Marcellus LLC (“ACP II”), the Company’s partner in one of its joint ventures in the Marcellus Shale, Carrizo (Marcellus) LLC (“Carrizo Marcellus”), a wholly-owned subsidiary of the Company, was issued a class of interests (“B Units”) in ACP II. The B Units entitle the Company to certain percentages of cash distributions to affiliates of Avista Capital Partners, LP, (together with its affiliates, “Avista”), if, when and only to the extent that those cash distributions exceed certain internal rates-of-return and return-on-investment thresholds with respect to Avista’s investment in ACP II as set forth in the limited liability company agreement of ACP II. Because the B Units do not provide the Company with an ownership interest in the oil and gas properties of ACP II, the Company is not required to pay for property acquisition, exploration or development costs associated with ACP II’s ownership interest in oil and gas properties, nor do the B Units entitle the Company to recognize oil and gas production and therefore, proved reserves associated with ACP II’s ownership interest in oil and gas properties. However, under the full cost method of accounting, cash distributions received on the B Units are considered proceeds from the sale of oil and gas properties which are recognized as a reduction of capitalized oil and gas property costs. See Note 10. Related Party Transactions.

The estimated future net revenues used in the ceiling test are calculated using average quoted market prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period. Prior to December 31, 2009, prices and costs used to calculate future net revenues were those as of the end of the appropriate quarterly period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable

F-10

contracts for the remaining term of those contracts. Prices used in the ceiling test computation do not include the impact of derivative instruments because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment.

Depreciation of other property and equipment is provided using the straight-line method based on estimated useful lives ranging from five to ten years.

Asset Retirement Obligations

The Company’s oil and gas properties require expenditures to plug and abandon wells after the reserves have been depleted. The asset retirement obligation is recognized when the well is drilled with an associated increase in oil and gas property costs. The asset retirement obligation is recorded at fair value and requires estimates of the costs to plug and abandon wells, the costs to restore the surface, the remaining lives of wells based on oil and gas reserve estimates and future inflation rates. The obligation is discounted using a credit-adjusted risk-free interest rate which is accreted over time to its expected settlement value. Estimated costs consider historical experience, third party estimates and state regulatory requirements and do not consider salvage values. At least annually, the Company reassesses its asset retirement obligations to determine whether a change in the estimated obligation is necessary. On a quarterly basis, the Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed and updates its estimated obligation if necessary.

Cash and Cash Equivalents

Cash and cash equivalents include highly liquid investments with maturities of three months or less when purchased.

Revenue Recognition

Oil and gas sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company follows the sales method of accounting for oil and gas revenues whereby revenue is recognized for all oil and gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as an asset or liability to the extent that the Company has an imbalance on a specific property that is in excess of its remaining proved oil and gas reserves. Oil and gas sales volumes are not significantly different from the Company’s share of production and as of December 31, 2010 and 2009, the Company did not have any material production imbalances.

The Company purchases natural gas at the wellhead from a third-party operator under a purchase and sales agreement whereby the Company recognizes revenue when title to the natural gas transfers to a third party purchaser. The Company remits the sales proceeds to the third-party operator which is recorded at the cost of the natural gas purchased. These purchases and sales are recorded in gas purchases and other revenues in the statements of operations and totaled $1.3 million, $1.5 million and $6.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Deferred Financing Costs

Deferred financing costs were $14.7 million (net of $6.3 million of accumulated amortization) and $9.7 million (net of $3.9 million of accumulated amortization) as of December 31, 2010 and 2009, respectively and include legal fees, accounting fees, underwriting fees, printing costs, and other direct costs associated with the issuance of the debt instruments and costs associated with revolving credit facilities. The capitalized costs are amortized to interest expense using the effective interest method over the terms of the debt instruments or credit facilities, which is through October 2018 for the Senior Notes due 2018 (“Senior Notes”), May 2013 for the Convertible Senior Notes and October 2012 for the Prior Credit Facility as defined in Note 6. Debt.

Supplemental Cash Flow Information

The consolidated statements of cash flows for the years ended December 31, 2010, 2009 and 2008 do not include the non-cash fair value adjustments to the carrying amount of the Company’s investment in Pinnacle Gas Resources, Inc. recognized in other comprehensive income, net of income taxes of $0, $0.1 million, and $(6.7) million, respectively, net of income taxes.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivative instruments and current and long-term debt. The carrying amounts of cash and cash equivalents, receivables, payables and short-term debt approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying amount of long-term debt under the Prior Credit Facility approximates fair value as these borrowings bear interest at variable rates of interest. The carrying amounts of the Senior Notes and Convertible Senior Notes do not approximate fair value because the notes bear interest at fixed rates of interest. See Note 12. Fair Value Measurements.

F-11

Stock-Based Compensation

The Company grants stock options, stock appreciation rights (“SARs”) that may be settled in cash or common stock (“Stock SARs”), SARs that may only be settled in cash (“Cash SARs”), restricted stock awards and restricted stock units to directors, employees and independent contractors. The Company recognized the following stock-based compensation expenses for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:


	Years Ended December 31,
	2010		2009		2008
	(In millions)
Stock Options and SARs	$	6.7	$	1.2	$	0.1
Restricted Stock Awards and Units		9.9		10.1		5.9

Total Stock-Based Compensation Expense	$	16.6	$	11.3	$	6.0

Tax Benefit	$	6.2	$	4.1	$	2.1

Stock Options and SARs. For stock options and Stock SARs that the Company expects to settle in common stock, stock-based compensation expense is based on the grant-date fair value and recognized over the vesting period (generally three years). For Cash SARs and any Stock SARs that the Company expects to settle in cash, stock-based compensation expense is based on the fair value remeasured at each reporting period, recognized over the vesting period (generally three years) and classified as other accrued liabilities for the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as other long-term liabilities. The Company recognizes stock-based compensation expense over the vesting period for stock options and SARs using the straight-line method, except for awards with performance conditions, in which case the Company uses the graded vesting method. Stock options typically expire ten years after the date of grant. SARs typically expire seven years after the date of grant.

The Company uses the Black-Scholes-Merton option pricing model to compute the fair value of stock options and SARs, which requires the Company to make the following assumptions:

•

The risk-free interest rate is based on the zero-coupon United States Treasury yield for the expected term at date of grant.

•

The dividend yield on the Company’s common stock is assumed to be zero since the Company does not pay dividends and has no current plans to do so in the future.

•

The volatility of the Company’s common stock is based on daily, historical volatility of the market price of the Company’s common stock over a period of time equal to the expected term and ending on the grant date.

•

The expected term is based on historical exercise experience for various groups of employees and directors.

Restricted Stock Awards and Units. For restricted stock awards and units, stock-based compensation expense is based on the grant-date fair value and recognized over the vesting period (generally one to three years) using the straight-line method, except for award or units with performance conditions, in which case the Company uses the graded vesting method. The fair value of restricted stock awards and units is based on the average of the high and low price of the Company’s common stock on the grant date. For restricted stock awards and units granted to independent contractors, stock-based compensation expense is based on fair value remeasured at each reporting period and recognized over the vesting period (generally three years) using the straight-line method.

Derivative Instruments

The Company uses derivative instruments, typically fixed-rate swaps, costless collars, puts, calls and basis differential swaps, to manage commodity price risk associated with a portion of its forecasted oil and gas production. Derivative instruments are recognized at their current fair value as assets or liabilities in the consolidated balance sheets. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price risk associated with oil and gas production, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, unrealized gains and losses as a result of changes in the fair value of derivative instruments are recognized as gain (loss) on derivative instruments, net in the consolidated statements of operations. Realized gains and losses as a result of cash settlements with counterparties to the Company’s derivative instruments are also recorded as gain (loss) on derivative instruments, net in the consolidated statements of operations. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty.

F-12

The Company’s Board of Directors establishes risk management policies and reviews derivative instruments, including volumes, types of instruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with approved counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. See Note 11, Derivative Instruments for further discussion of the Company’s derivative instruments.

Income Taxes

Deferred income taxes are recognized at each reporting period 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. The Company routinely assesses the realizability of its deferred tax assets and considers its estimate of future taxable income based on production of proved reserves at estimated future pricing in making such assessments. If the Company concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the deferred tax assets are reduced by a valuation allowance. The Company classifies interest and penalties associated with income taxes as interest expense.

Concentration of Credit Risk

Substantially all of the Company’s accounts receivable result from oil and gas sales, joint interest billings to third parties in the oil and gas industry or drilling and completion advances to third-party operators for development costs of wells in progress. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not require collateral from its customers. The Company generally has the right to offset revenue against related billings to joint interest owners.

Derivative instruments subject the Company to a concentration of credit risk. See Note 11. Derivative Instruments for further discussion of concentration of credit risk related to the Company’s derivative instruments.

Accounts Receivable and Allowance for Doubtful Accounts

The Company establishes an allowance for doubtful accounts when it determines that it will not collect all or a part of an accounts receivable balance. The Company assesses the collectability of its accounts receivable on a quarterly basis and adjusts the allowance as necessary using the specific identification method. A roll forward of the allowance for doubtful accounts is as follows (in thousands):


January 1, 2008	$	1,430
Charged to general and administrative expense		(166	)

December 31, 2008		1,264
Charged to general and administrative expense		772

December 31, 2009		2,036
Charged to general and administrative expense		485
Amounts written off		(51	)

December 31, 2010	$	2,470

Major Customers

Sales to individual customers constituting 10% or more of total revenues were as follows:


	Year Ended December 31,
	2010			2009			2008
DTE Energy Trading, Inc.		63	%		54	%		39	%
Cokinos Natural Gas Company		*			*			11	%
Crosstex Energy		*			*			10	%

(*)	Revenues were below 10%.

Net Income (Loss) Per Share

F-13

Supplemental net income (loss) per share information is provided below:


	Year Ended December 31,
	2010		2009			2008
	(In thousands, except per share amounts)
Net income (loss)	$	9,950	$	(204,845	)	$	(45,047	)

Weighted average common shares outstanding		33,861		31,006			30,326
Effect of dilutive instruments		444		—			—

Diluted weighted average shares outstanding		34,305		31,006			30,326

Net income (loss) per share
Basic	$	0.29	$	(6.61	)	$	(1.49	)
Diluted	$	0.29	$	(6.61	)	$	(1.49	)

Basic net income (loss) per common share is based on the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the period which include restricted stock units, stock options, Stock SARs expected to be settled in common stock, warrants and convertible debt. The Company excluded 23,688 shares related to restricted stock units, stock options and Stock SARs expected to be settled in common stock from the calculation of dilutive shares for the year-ended December 31, 2010, because the grant prices were greater than the average market prices of the common shares for the period and would be antidilutive to the computation. The Company excluded 1,205,770 and 685,854 shares related to stock options and Stock SARs expected to be settled in common stock from the calculation of dilutive shares for the years ended December 31, 2009 and 2008 due to the net losses reported in those periods. Shares of common stock subject to issuance upon the conversion of the Convertible Senior Notes did not have an effect on the calculation of dilutive shares for the years ended December 31, 2010, 2009 or 2008 because the conversion price was in excess of the market price of the common stock for those periods.

Commitments and Contingencies

Liabilities are recognized for contingencies when 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.

Foreign Currency

The U.S. dollar is the functional currency for the Company’s operations in the U.K. North Sea. Transaction gains or losses that occur due to the realization of assets and the settlement of liabilities using a currency denominated in other than the functional currency are recorded as other income, net in the consolidated statements of operations.

Recently Adopted Accounting Pronouncements

A standard to improve disclosures about fair value measurements was issued by the Financial Accounting Standards Board (the “FASB”) in January 2010. The additional disclosures required include: (1) the different classes of assets and liabilities measured at fair value, (2) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (3) the gross presentation of purchases, sales, issuances and settlements for the roll forward of Level 3 activity and (4) the transfers in and out of Levels 1 and 2 and the reasons for such transfers. The Company adopted the new disclosures in the first quarter of 2010.

In January 2010, the FASB issued Accounting Standards Update No. 2010-03 to align the oil and gas reserve estimation and disclosure requirements of Topic 932 (“Extractive Industries — Oil and Gas”) with the requirements of the Securities and Exchange Commission (“SEC”) Release 33-8994. This release is effective for financial statements issued on or after January 1, 2010. The Company adopted this guidance effective December 31, 2009. This release changes the accounting and disclosure requirements of oil and gas reserves and is intended to modernize and update the oil and gas disclosure requirements, to align them with current industry practices and to adapt to changes in technology. The new rules permit the use of new technologies to determine proved reserves, allow companies to disclose their probable and possible reserves and allow proved undeveloped reserves to be maintained beyond a five-year period only if justified by specific circumstances. The new rules require companies to report the independence and qualification of the person primarily responsible for the preparation or audit of its reserve estimates, and to file reports when a third party is relied upon to prepare or audit its reserve estimates. The new rules also require that the net present value of oil and gas reserves reported and used in the full cost ceiling test calculation be based upon average market prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period.

F-14

3. INVESTMENTS

Investments consisted of the following at December 31, 2010 and 2009:


	December 31,
	2010		2009
	(In thousands)
Pinnacle Gas Resources, Inc.	$	869	$	835
Oxane Materials, Inc.		2,523		2,523

	$	3,392	$	3,358

Pinnacle Gas Resources, Inc.

In 2003, the Company and its wholly-owned subsidiary CCBM, Inc. contributed their interests in certain oil and gas leases in Wyoming and Montana in areas prospective for coalbed methane to a newly formed entity, Pinnacle Gas Resources, Inc. (“Pinnacle”).

At March 31, 2009, the market value of the Company’s investment in Pinnacle had consistently remained below its book value since October 2008. The Company determined that the impairment was other than temporary, and accordingly, recognized an impairment of $2.1 million at March 31, 2009. At December 31, 2010, the Company reported the fair value of its investment in Pinnacle at $0.9 million (based on the closing price of Pinnacle’s common stock on December 31, 2010).

On January 25, 2011, Pinnacle announced that it had been acquired by Powder Holdings, LLC, an entity controlled by SW Energy Capital LP. Under the terms of the merger agreement, Pinnacle stockholders are entitled to receive $0.34 per share in cash for each share of Pinnacle common stock. As of December 31, 2010, the Company owned 2,555,825 shares of Pinnacle common stock.

Oxane Materials, Inc.

In May 2008, the Company entered into a strategic alliance agreement with Oxane Materials, Inc. (“Oxane”) in connection with the development of a proppant product to be used in the Company’s exploration and production program. The Company contributed approximately $2.0 million to Oxane in exchange for warrants to purchase Oxane common stock and for certain exclusive use and preferential purchase rights with respect to the proppant. The Company simultaneously invested an additional $500,000 in a convertible promissory note from Oxane. The convertible promissory note accrued interest at a rate of 6% per annum. During the fourth quarter of 2008, the Company converted the promissory note into 630,371 shares of Oxane preferred stock.

4. PROPERTY AND EQUIPMENT, NET

At December 31, 2010 and 2009, property and equipment, net consisted of the following:

F-15


	December 31,
	2010			2009
	(In thousands)
Proved oil and gas properties	$	941,267		$	667,907
Accumulated depreciation, depletion and amortization		(314,602	)		(268,725	)

Proved oil and gas properties, net	$	626,665		$	399,182


Costs not subject to amortization:
Unevaluated leaseholds and seismic costs		258,139			258,300
Capitalized interest		38,782			34,563
Exploratory wells in progress		55,558			37,744

Total costs not subject to amortization		352,479			330,607


Other property and equipment		7,314			6,475
Accumulated depreciation		(3,401	)		(2,564	)

Other property and equipment, net		3,913			3,911

Total property and equipment, net	$	983,057		$	733,700

Costs not subject to amortization totaling $352.5 million at December 31, 2010 include the cost of unevaluated leaseholds and seismic costs associated with specific unevaluated properties of $258.1 million, exploratory wells in progress of $55.6 million and capitalized interest of $38.8 million and such costs were incurred in the following periods: $184.2 million in 2010, $40.9 million in 2009, $124.2 million in 2008 and $3.2 million in 2007 and prior years.

The net capitalized costs of the Company’s United States and U.K. North Sea oil and gas properties did not exceed their respective cost center ceilings and accordingly, did not result in impairments at December 31, 2010. In June 2010, the Company concluded that it was uneconomical to pursue development on the license covering the Monterey field in the U.K. North Sea and terminated further development efforts. Because the U.K. cost center had no proved reserves at that time, the $2.7 million ($1.7 million net of income taxes) of costs associated with the license covering the Monterey field resulted in an impairment for the year ended December 31, 2010.

The net capitalized costs of the Company’s United States oil and gas properties exceeded the cost center ceiling at March 31, 2009 resulting in an impairment of $216.4 million ($140.6 million net of income taxes), at December 31, 2009, resulting in an impairment of $122.5 million ($78.1 million net of income taxes) and at December 31, 2008, resulting in an impairment of $178.5 million ($116.0 million net of income taxes). To measure the cost ceiling for the first quarter of 2009, the Company elected to use a pricing date subsequent to the balance sheet date, as allowed by the accounting requirements in effect at the time. Had the Company used prices in effect as of March 31, 2009, the Company would have recognized an impairment of $323.2 million ($206.1 million net of tax) for the first quarter of 2009. The option to use a pricing date subsequent to the balance sheet date is no longer available under the oil and gas reserve estimation and disclosure requirements which the Company adopted effective December 31, 2009.

Decreases in oil and gas prices as well as changes in production rates, levels of reserves, evaluation of costs not subject to amortization, future development and production costs could result in future impairments of oil and gas properties.

During the fourth quarter of 2009, the Company sold its Mansfield pipeline and gathering system in the Barnett Shale to Delphi Midstream Partners, LLC for $34.7 million and a 12.5% working interest in 16 drilling units in the Barnett Shale to a subsidiary of Sumitomo Corporation (“Sumitomo”) for $15.7 million for certain costs previously incurred by the Company with respect to these drilling units, including Sumitomo’s proportionate share of certain land, seismic and drilling costs.

As discussed further in Note 10. Related Party Transactions, in September 2010, the Company completed the sale of 20% of its interests in substantially all of its oil and gas properties in Pennsylvania that had been subject to the Avista joint venture to Reliance for $13.1 million in cash and a commitment by Reliance to pay 75% of certain of the Company’s future development costs up to approximately $52.0 million. The proceeds were recognized as a reduction of proved oil and gas properties, net and 20% of the unevaluated leasehold and seismic costs associated with these properties (approximately $16.0 million) was also transferred to proved oil and gas properties, net.

During the third and fourth quarters of 2010, ACP II declared and paid cash distributions to affiliates of Avista. Because these distributions exceeded Avista’s internal rates-of-return and return-on-investment thresholds, the Company received cash distributions

F-16

of approximately $38.8 million on its B Units during the third and fourth quarters of 2010, which were recognized as reductions of capitalized oil and gas property costs.

5. INCOME TAXES

The components of income tax (expense) benefit were as follows:


	Year Ended December 31,
	2010			2009			2008
	(In thousands)
Current income tax (expense) benefit:
Federal	$	—		$	(6	)	$	(29	)
State		(4,236	)		(65	)		(195	)

Total current tax (expense) benefit		(4,236	)		(71	)		(224	)

Deferred income tax (expense) benefit:
Federal		(4,937	)		111,325			20,949
State		3,444			2,053			—

Total deferred tax (expense) benefit		(1,493	)		113,378			20,949

Total income tax (expense) benefit	$	(5,729	)	$	113,307		$	20,725

For the years ended December 31, 2010, 2009 and 2008, all of the Company’s income is derived from domestic activities. Actual income tax expense (benefit) differs from income tax expense (benefit) computed by applying the U.S. federal statutory corporate rate of 35% to pretax income as follows:


	Year Ended December 31,
	2010			2009			2008
	(In thousands)
(Expense) Benefit at the statutory rate	$	(5,488	)	$	111,353		$	23,020
State income taxes, net of federal benefit		(792	)		2,270			(123	)
Nondeductible expenses		(46	)		(35	)		(1,930	)
Other		597			(281	)		(242	)

Total income tax (expense) benefit	$	(5,729	)	$	113,307		$	20,725

Deferred income taxes result from temporary differences between the recognition of income and expenses for financial reporting purposes and for tax purposes. At December 31, 2010 and 2009, the tax effects of these temporary differences resulted principally from the following:

F-17


	December 31,
	2010		2009
	(In thousands)
Deferred income tax assets:
Net operating loss carryforward	$	52,683	$	29,629
Property and equipment		57,201		84,919
Stock-based compensation		4,855		1,963
Allowance for doubtful accounts		915		738
Equity in loss of Pinnacle		422		399
Valuation allowance		—		(399	)
Adjustment to fair value of investment in Pinnacle		713		707
Other		590		224

		117,379		118,180

Deferred income tax liabilities:
Unamortized discount on Convertible Senior Notes		2,372		16,352
Capitalized interest		38,812		30,455
Fair value of derivatives		8,894		2,630

		50,078		49,437

Net deferred income tax asset	$	67,301	$	68,743

At December 31, 2010 and 2009, the net deferred income tax asset is classified as follows:


	December 31,
	2010			2009
	(In thousands)
Noncurrent deferred tax asset	$	72,587		$	70,217
Current deferred tax liability		(5,286	)		(1,474	)

Net deferred income tax asset	$	67,301		$	68,743

As of December 31, 2010, the Company had income tax net operating loss (“NOL”) carryforwards of approximately $160.2 million which expire between 2019 and 2030 if not utilized in earlier periods. The realization of the deferred tax assets related to the NOL carryforward is dependent on the Company’s ability to generate taxable income in the future. The Company believes it will be able to generate sufficient taxable income in the NOL carryforward period. As such, the Company believes that it is more likely than not that its deferred tax assets will be fully realized.

The ability of the Company to utilize the NOL to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of a Company’s taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (a) the fair market value of the equity of the company multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. As of December 31, 2010, the Company believes an ownership change occurred in February 2005 with an annual limitation of $12.6 million. Because the Company’s pre-change NOL is $9.8 million, the Company does not believe it has a Section 382 limitation on the ability to utilize its NOL as of December 31, 2010. Future equity transactions involving the Company or 5% shareholders of the Company (including, potentially, relatively small transactions and transactions beyond the Company’s control) could cause further ownership changes and therefore a limitation on the annual utilization of NOLs.

The Company receives a tax deduction during the period stock options are exercised, generally for the excess of the price at which the stock is sold over the exercise price of the option. The Company also receives a tax deduction during the period restricted stock awards and restricted stock units vest, generally for the excess of the value at which the awards or units vest over the grant-date fair value used to recognize stock-based compensation expense. Because these stock-based compensation tax deductions did not reduce current taxes payable as a result of NOL carryforwards, the benefit of these tax deductions has not been reflected in the NOL carryforward deferred tax asset. Stock-based compensation deductions included in NOL carryforwards of $160.2 million but not reflected in deferred tax assets were $17.8 million at December 31, 2010. The Company plans to recognize the $6.6 million deferred tax asset associated with these stock-based compensation tax deductions when all other components of the NOL tax asset have been

F-18

fully utilized. If and when the stock-based compensation deduction related NOL tax asset is realized, the tax benefit of reducing current taxes payable will be credited directly to additional paid-in capital.

At December 31, 2010, the Company had no material uncertain tax positions and the tax years since 1999 remain open to review by federal and various state tax jurisdictions.

6. DEBT

At December 31, 2010 and 2009, debt consisted of the following:


	December 31,
	2010			2009
	(In thousands)
Senior Notes	$	400,000		$	—
Unamortized Discount for Senior Notes		(2,751	)		—
Convertible Senior Notes		73,750			373,750
Unamortized Discount for Convertible Senior Notes		(6,405	)		(45,122	)
Senior Secured Revolving Credit Facility		93,500			191,400
Other		160			308

		558,254			520,336
Less: current maturities		(160	)		(148	)

	$	558,094		$	520,188

Senior Notes

On November 2, 2010, the Company issued $400 million aggregate principal amount of 8.625% Senior Notes due 2018 (“Senior Notes”) at a price to the initial purchasers of 99.302% of the principal amount in a private placement. The Senior Notes are guaranteed by certain of the Company’s subsidiaries: CCBM, Inc.; CLLR, Inc.; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC; Carrizo Marcellus Holding, Inc.; Hondo Pipeline, Inc.; Bandelier Pipeline Holding, LLC; Chama Pipeline Holding LLC; and Mescalero Pipeline, LLC. The net proceeds of $387.5 million (after deducting the initial purchasers’ discount and the Company’s expenses) were used to repay in full borrowings outstanding under the Prior Credit Facility (defined below) and to fund in part the tender offer for $300 million of the Convertible Senior Notes as described below.

The Senior Notes bear interest at 8.625% per annum which is payable semi-annually on each October 15 and April 15. The Senior Notes mature on October 15, 2018 with interest payable semi-annually. At any time prior to October 15, 2013, the Company may, subject to certain conditions, on one or more occasions, redeem up to 35% of the aggregate principal amount of Senior Notes at a redemption price of 108.625%, of the principal amount, plus accrued and unpaid interest, if any, to the redemption date using the net cash proceeds of one or more equity offerings by the Company. Prior to October 15, 2014, the Company may redeem all or part of the Senior Notes at 100% of the principal amount thereof, plus accrued and unpaid interest and a make whole premium. On and after October 15, 2014, the Company may redeem all or a part of the Senior Notes, at redemption prices decreasing from 104.313% of the principal amount to 100% of the principal amount on October 15, 2017, plus accrued and unpaid interest. If a Change of Control (as defined in the Indenture governing the Senior Notes) occurs, the Company may be required by holders to repurchase Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus any accrued but unpaid interest.

The notes and indenture are subject to customary events of default, including those relating to failures to comply with the terms of the notes and indenture, certain failures to file reports with the SEC, certain cross defaults of other indebtedness and mortgages and certain failures to pay final judgments.

F-19

substantially identical to the Senior Notes for outstanding Senior Notes. In certain circumstances, the Company may be required to use commercially reasonable efforts to file a shelf registration statement to cover resales of the Senior Notes. The Company may be required to pay additional interest to holders of the Senior Notes under certain circumstances if it fails to meet these obligations by certain dates.

Convertible Senior Notes

In November 2010, the Company completed a tender offer for $300 million aggregate principal amount outstanding of the Convertible Senior Notes for an aggregate consideration of approximately $306.3 million, including accrued and unpaid interest on the Convertible Senior Notes. Each holder received $1,000 for each $1,000 principal amount of Convertible Senior Notes purchased in the tender offer, plus accrued and unpaid interest. The Company recognized a $31.0 million pre-tax loss on extinguishment of debt as a result of the purchase of the Convertible Senior Notes in the tender offer, substantially all of which was non-cash representing the associated unamortized discount and deferred financing costs. After the Company’s purchase of $300 million aggregate principal amount of Convertible Senior Notes, $73.8 million aggregate principal amount of Convertible Senior Notes remained outstanding as of December 31, 2010.

The Convertible Senior Notes are subject to customary non-financial covenants and events of default, including a cross default under the Revolving Credit Facility (defined below), 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 of the Company and rank equal to all future senior unsecured debt but rank second in priority to the Revolving Credit Facility.

On November 2, 2010, in connection with the issuance of the Senior Notes, the Company and the guarantors of the Senior Notes entered into a supplement to the indenture governing the Convertible Senior Notes. Pursuant to this supplemental indenture, the guarantors of the Senior Notes also became guarantors of the Convertible Senior Notes. The guarantee of the Convertible Senior Notes was required under the indenture for the Convertible Senior Notes as a result of the issuance of the guarantees of the Senior Notes.

F-20

discount associated with the Convertible Senior Notes purchased in the tender offer discussed above, was recognized as a component of the loss on the extinguishment of debt. Amortization of the debt discount amounted to $2.2 million and $3.1 million for the three months ended December 31, 2010 and 2009, respectively, and $11.6 million and $12.1 million for the years ended December 31, 2010 and 2009, respectively.

Prior Senior Secured Revolving Credit Facility

As of December 31, 2010, the Company had a senior secured revolving credit facility (the “Prior Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent. The Prior Credit Facility provided for a revolving credit facility up to the lesser of the borrowing base or $350 million. It was secured by substantially all of the Company’s proved oil and gas assets and was guaranteed by certain of the Company’s subsidiaries: CCBM, Inc.; CLLR, Inc.; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC; Carrizo Marcellus Holding, Inc.; Hondo Pipeline, Inc.; Bandelier Pipeline Holding, LLC; Chama Pipeline Holding LLC; and Mescalero Pipeline, LLC. In January 2011, the Company replaced this facility with a new secured revolving credit facility. See Note 13. Subsequent Events for further discussion.

In December 2010, the borrowing base was decreased from $375 million to $350 million as a result of the net increase in debt associated with the $400 million issuance of the Senior Notes and the $300 million tender for the Convertible Senior Notes.

If the outstanding principal balance of the revolving loans under the Prior Credit Facility exceeded the borrowing base at any time, the Company had 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 have been in addition to any payments that would have come due as a result of the quarterly borrowing base reductions. Otherwise, any unpaid principal or interest would have been due at maturity.

The Prior Credit Facility contained covenants in which the Company was required to maintain until the Prior Credit Facility was terminated in January 2011: (1) a minimum current ratio of 1.00 to 1.00 (as defined in the Prior Credit Facility); and (2) a maximum total net debt (which excludes certain amounts attributable to the Convertible Senior Notes) to Consolidated EBITDA (as defined in the Prior Credit Facility) of (a) 4.25 to 1.00 for the fiscal quarters ending on or after December 31, 2010 and on or before June 30, 2011, (b) 4.50 to 1.00 for the fiscal quarters ending on or after September 30, 2011 and on or before December 31, 2011, and (c) 4.00 to 1.00 for each fiscal quarter ending on or after March 31, 2012; and (3) a maximum ratio of senior debt (which excludes the aggregate principal amount of the senior notes and the Convertible Senior Notes) to Consolidated EBITDA of (a) 2.25 to 1.00 for the fiscal quarters ending on or after December 31, 2010 and on or before June 30, 2011, (b) 2.50 to 1.00 for the fiscal quarters ending on or after September 30, 2011 and on or before December 31, 2011 and (c) 2.25 to 1.00 for each fiscal quarter ending on or after March 31, 2012. As defined in the Prior Credit Facility, the current ratio was 2.80 to 1, the total net debt to Consolidated EBITDA ratio was 3.42 to 1 and the ratio of senior debt to Consolidated EBITDA ratio was 0.58 to 1 as of December 31, 2010. Because the calculation of the financial ratios are made as of a certain date, the financial ratios could have fluctuated significantly period to period as the amounts outstanding under the Prior Credit Facility were dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings.

The Prior Credit Facility also placed restrictions on indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of the Company’s common stock, swap agreements, transactions with affiliates and other matters.

At December 31, 2010, the Company had $93.5 million of borrowings outstanding under the Prior Credit Facility. The Company also issued $4.1 million of letters of credit which reduced the amounts available under the Prior Credit Facility. Availability under the $350 million borrowing base was subject to the terms and covenants of the Prior Credit Facility. The Prior Credit Facility was used to fund ongoing working capital needs and the remainder of the Company’s capital expenditure plan only to the extent such amounts exceeded the cash flow from operations, proceeds from the sale of oil and gas properties and securities offerings.

7. ASSET RETIREMENT OBLIGATIONS

F-21

The following is a roll forward of asset retirement obligations:


	Year Ended December 31, 2010			Year Ended December 31, 2009
	(In thousands)
Asset retirement obligations at beginning of period	$	5,410		$	6,503
Liabilities incurred		181			444
Liabilities settled		(288	)		(36	)
Accretion expense		216			308
Revisions of previous estimates		850			(1,809	)

Asset retirement obligations at end of period	$	6,369		$	5,410

The revisions of previous estimates for the year ended December 31, 2010, related primarily to increases in estimates of abandonment costs of wells in the Gulf Coast. The revisions of previous estimates for the year ended December 31, 2009, related primarily to increases in the estimated life of wells in the Barnett Shale.

8. COMMITMENTS AND CONTINGENCIES

From time to time, the Company is 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, the Company does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.

The operations and financial position of the Company continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and natural gas production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable.

The Company has an operating lease agreement for its corporate offices that expires in December 2011. Under the terms of the lease agreement, the Company received rent abatements equal to six months of lease payments and a build out allowance that is being amortized to expense over the term of the lease. In 2006 and 2010, the Company amended its lease agreement to expand the leased office space. The lease term for the additional space also expires in December 2011. Rent expense included in general and administrative expense for the years ended December 31, 2010, 2009 and 2008 was $1.0 million, $0.9 million and $0.9 million, respectively, and includes rent expense for the Company’s corporate office and a field office.

At December 31, 2010, total minimum commitments from long-term non-cancelable operating leases, drilling rig, seismic and pipeline volume commitments as follows:


	Amount
	(In thousands)
2011	$	40,542
2012		24,346
2013		19,328
2014		14,194
2015		8,899
2016 and Thereafter		6,041

	$	113,350

9. SHAREHOLDERS’ EQUITY AND STOCK INCENTIVE PLAN

Shareholders’ Equity

Common Stock. In December 2010, the Company sold 3.975 million shares of its common stock in an underwritten public offering at a price to the underwriter of $28.90 per share. The Company used the net proceeds of approximately $114.9 million to repay a portion of the outstanding borrowings under the Prior Credit Facility.

F-22

In April 2010, the Company sold 3.22 million shares of its common stock in an underwritten public offering at a price to the underwriter of $23.00 per share. The Company used the net proceeds of approximately $73.8 million to repay a portion of the outstanding borrowings under the Prior Credit Facility.

In February 2008, the Company sold 2.59 million shares of its 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 the Company repaid $85.0 million of outstanding borrowings under the Prior Credit Facility. The Company used the remaining proceeds to fund a portion of its 2008 capital expenditure program.

Warrants. On November 24, 2009, the Company entered into a Land Agreement, as amended (the “Land Agreement”), with an unrelated third party and its affiliate. Under this arrangement, the Company may until May 31, 2011 acquire up to $20 million of oil, gas and mineral interests/leases in certain specified areas in the Barnett Shale from the third party. In consideration of the Company’s receipt of an option to purchase the leases acquired by the third party, each time the third party purchases a lease group under the Land Agreement, if any, the Company will issue to the third party’s affiliate warrants to purchase a number of shares of the Company’s common stock equal to the quotient of (rounded up to the nearest whole number) (1) 20% of the purchase price of such lease group divided by (2) $13.00, with an exercise price of $22.09 and an expiration date of August 21, 2017. In addition, under certain circumstances where the Company reaches surface casing point on an initial well in one of the areas covered by the Land Agreement but has not achieved a specified lease up threshold for acreage in such area, the Company will issue additional warrants to the third party’s affiliate, on the same terms, to purchase a number of shares of the Company’s stock equal to the quotient (rounded up to the nearest whole number) of (1) 20% of the product of (A) the number of acres below the specified lease up threshold multiplied by (B) $5,000, divided by (2) $13.00. The warrants are subject to antidilution adjustments and may be exercised on a “cashless” basis.

During 2010, the Company issued warrants to purchase 57,641 shares of the Company’s common stock to the third party’s affiliate in connection with purchases of leases by the third party under the Land Agreement.

Stock Incentive Plans

In 1997, the Company established the Incentive Plan of Carrizo Oil & Gas, Inc. (the “Incentive Plan”), which authorizes the granting of stock options, SARs that may be settled in cash or common stock (“Stock SARs”), restricted stock awards and restricted stock units to directors, employees and independent contractors. The Company may grant awards of up to 4,395,000 shares under the Incentive Plan and through December 31, 2010, has granted stock options, restricted stock awards and restricted stock units covering 3,700,672 shares through December 31, 2010, net of forfeitures and excludes Stock SARs the Company has elected to settle in cash.

Stock Options and Stock SARs. The table below summarizes the activity for stock options and Stock SARs the Company expects to settle in common stock for the three years ended December 31, 2010, 2009 and 2008:

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	Shares			Weighted- Average Exercise Prices		Weighted- Average Remaining Life (In years)		Aggregate Intrinsic Value (In millions)
For the Year Ended December 31, 2008
Oustanding, beginning of period		761,921		$	4.67
Granted		—			—
Exercised		(65,400	)		4.01
Forfeited		(10,667	)		6.72

Oustanding, end of period		685,854		$	4.71

Exercisable, end of period		685,854		$	4.71

For the Year Ended December 31, 2009
Oustanding, beginning of period		685,854		$	4.71
Granted		214,609			20.18
Exercised		(5,000	)		1.81
Forfeited		—			—

Oustanding, end of period		895,463		$	8.43

Exercisable, end of period		680,854		$	4.73

For the Year Ended December 31, 2010
Oustanding, beginning of period		895,463		$	8.43
Granted		—			—
Exercised		(266,433	)		2.59
Forfeited		(2,493	)		18.56
Other		(211,683	)		20.22

Oustanding, end of period		414,854		$	6.10		2.16	$	11.75

Exercisable, end of period		414,854		$	6.10		2.16	$	11.75

During 2009, the Company granted 211,683 Stock SARs which the Company expected to settle in common stock. During July 2010, the Company elected to settle those Stock SARs in cash. Accordingly, during the third quarter of 2010, the Company recognized a fair value liability for the vested portion of the Stock SARs using assumptions in effect at the date the awards were modified and additional stock-based compensation expense of $0.3 million. The following table summarizes the weighted-average assumptions used in the Black-Scholes-Merton option pricing model to calculate the grant date and modification date fair values of the Stock SARs:


	2010			2009
Grant-date fair value	$	—		$	10.14
Modification date fair value	$	12.48		$	—
Volatility factor		60.7	%		61.3	%
Dividend yield		—			—
Risk-free interest rate		1.1	%		2.0	%
Expected term (in years)		4.3			4.1

No stock options or Stock SARs were granted during 2010 or 2008. The Stock SARs contain performance and service conditions. The performance conditions have been met for all awards.

At December 31, 2010, the liability for Stock SARs to be settled in cash was $3.5 million of which, $2.7 million is classified as other accrued liabilities representing the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder of $0.8 million, classified as other long-term liabilities. As of December 31, 2010, unrecognized compensation costs related to unvested Stock SARs to be settled in cash was $1.0 million and will be recognized as stock-based compensation expense over a weighted-average period of 1.4 years.

At December 31, 2010, all stock options were vested and accordingly, the Company had no unrecognized compensation costs related to outstanding stock options. The total intrinsic value (current market price less the stock option exercise price) of stock options exercised during the years ended December 31, 2010, 2009 and 2008 was $6.0 million, $0.1 million, and $2.5 million, respectively, and the Company received $0.7 million, $9,000, and $0.3 million in cash in connection with stock option exercises for the years ended December 31, 2010, 2009 and 2008, respectively.

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Restricted Stock Awards and Units. The Company began issuing restricted stock awards in 2005 and restricted stock units in 2009. Although shares of common stock are not released to the employee until vesting, restricted stock awards have the right to vote and accordingly, restricted stock awards are considered issued and outstanding at the date of grant. Restricted stock units are not considered issued and outstanding until converted into common shares and released to the employee upon vesting. The table below summarizes restricted stock award and unit activity for the years ended December 31, 2010, 2009 and 2008:


	Shares/ Units			Grant-date Fair Value
Unvested restricted stock awards and units at December 31, 2007		351,849		$	31.15
Granted		215,469			35.43
Vested		(217,113	)		28.65
Forfeited		(8,507	)		42.00

Unvested restricted stock awards and units at December 31, 2008		341,698			34.93
Granted		529,062			18.76
Vested		(390,655	)		25.49
Forfeited		(8,862	)		28.81

Unvested restricted stock awards and units at December 31, 2009		471,243			25.01
Granted		640,207			18.60
Vested		(380,668	)		23.42
Forfeited		(19,827	)		25.23

Unvested restricted stock awards and units at December 31, 2010		710,955		$	20.26

As of December 31, 2010, unrecognized compensation costs related to unvested restricted stock awards and units was $9.6 million and will be recognized as stock-based compensation expense over a weighted-average period of two years. The 2009 and 2010 grants of restricted stock awards and units contained performance and service conditions. The performance conditions have been met for all awards.

Cash- Settled Stock Appreciation Rights Plan

In June 2009, the Company established the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SARs Plan”). The Cash SARs Plan enables employees and independent contractors to share in the appreciation of Carrizo’s common stock, but does not require the issuance of shares. During 2010, the Company issued 408,804 Cash SARs. At December 31, 2010, the liability for Cash SARs was $4.3 million of which, $2.7 million is classified as other accrued liabilities representing the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder of $1.6 million, classified as other long-term liabilities. The following table summarizes the weighted-average assumptions used in the Black-Scholes-Merton option pricing model to calculate the fair value of the Cash SARs at December 31, 2010:


	Cash SARs Granted in 2010			Cash SARs Granted in 2009
December 31, 2010 fair value	$	23.06		$	21.57
Volatility factor		60.3	%		60.7	%
Dividend yield		—			—
Risk-free interest rate		1.8	%		1.7	%
Expected term (in years)		4.5			4.3

As of December 31, 2010, unrecognized compensation costs related to unvested Cash SARs was $6.8 million and will be recognized as stock-based compensation expense over a weighted-average period of 2.4 years. The 2010 grants of Cash SARs contained performance and service conditions. The performance conditions have been met for all awards.

10. RELATED PARTY TRANSACTIONS

Marcellus Shale Joint Ventures. Effective August 1, 2008, Carrizo Marcellus, a wholly-owned subsidiary of the Company, entered into a joint venture arrangement with ACP II, an affiliate of Avista. In September 2010, the Company completed the sale of 20% of its interests in substantially all of its oil and gas properties in Pennsylvania that had been subject to the Avista joint venture to Reliance Marcellus II, LLC (“Reliance”), a wholly-owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited for $13.1 million in cash and a commitment by Reliance to pay 75% of certain of the Company’s future development costs up to approximately $52.0 million. The proceeds were recognized as a reduction of proved oil and gas properties, net and 20% of the unevaluated leasehold and seismic costs associated with these properties (approximately $16.0 million) was also transferred to proved

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oil and gas properties, net. Simultaneously with the closing of this transaction, ACP II closed the sale of its entire interest in the same properties to Reliance for a purchase price of approximately $327 million. At the time of entering into the agreements for these transactions, the Company and Avista agreed that B Unit distributions to the Company with respect to Avista’s sale of properties to Reliance would be principally based upon Avista’s return on investment and internal rates of return associated with such properties, subject to amounts withheld from distribution by ACP II’s board. During the third and fourth quarters of 2010, the Company received cash distributions of approximately $38.8 million from ACP II in respect of these B Units. In connection with these sales transactions, the Company and Avista amended the participation agreement and other joint venture agreements with Avista to provide that the properties that the Company and Avista sold to Reliance, as well as the properties the Company committed to the new joint venture with Reliance, are not subject to the terms of the Avista joint venture, and that the Avista joint venture’s area of mutual interest will generally not include Pennsylvania, the state in which those properties are located. The Company’s joint venture with Avista continues and now covers approximately 175,000 net acres, primarily in West Virginia and New York pursuant to the terms of the Avista area of mutual interest, effective December 31, 2010, the initial area of mutual interest was reduced to specified halos in which the Avista joint venture was active.

In December 2010 the Company entered into a settlement agreement with Reliance providing for the resolution of defects in title that Reliance alleged with respect to the properties it acquired from the Company and Avista in September 2010. In the agreement, the Company agreed to undertake specified curative measures with respect to the properties it and Avista sold to Reliance, and to indemnify Reliance on its own behalf and on behalf of Avista with respect to specified third party claims (in addition to existing customary indemnification obligations under the purchase agreement). In connection with entering into the settlement agreement, the Company entered into an agreement with Avista by which Avista agreed to indemnify the Company for amounts paid on Avista’s behalf by the Company under the settlement agreement, if any.

On November 16, 2010, Carrizo Marcellus assigned, via distribution and subsequent contribution, its interests in the joint venture with Avista to Carrizo (Marcellus) WV LLC (“Carrizo WV”), also a wholly-owned subsidiary of the Company. In connection with the assignment, Carrizo Marcellus assigned to Carrizo WV its rights and obligations under the participation agreement, as well as the related joint operating agreement, pursuant to which operatorship of the joint venture was assumed by Carrizo WV. In addition, Carrizo WV and the other parties thereto amended and restated the participation agreement on November 16, 2010, effective as of October 1, 2010. This amended and restated participation agreement amends the participation agreement by, among other things, (i) providing fixed percentages and thresholds for sharing net cash flow from hydrocarbon production and proceeds from the sales of underlying joint venture properties and (ii) eliminating provisions that have been performed and are inapplicable going forward.

The Company serves as operator of the properties covered by the joint venture with Avista under a joint operating agreement with Avista and also performs specified management services for the Avista affiliate that is the Company’s partner in the joint venture. An operating committee composed of one representative of each party provides overall supervision and direction of joint operations. 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 the Company defaults under the terms of any pledge of its interest in the properties.

The Company has agreed to jointly market Avista’s share of the production from the properties with its own until the cash flows and sale proceeds are allocated in accordance with the parties’ participating interests under the joint operating agreement. In connection with the formation of ACP II, Carrizo (Marcellus) was issued B Units in ACP II which entitle the Company to increasing percentages of cash distributions to affiliates of Avista Capital Partners, LP, if, when, and only to the extent that those cash distributions exceed certain internal rates-of-return and return-on-investment thresholds with respect to Avista’s investment as set forth in the limited liability company agreement of ACP II. The business and affairs of ACP II are managed under the direction of a three-member board of managers, consisting of employees and principals of Avista. The B Units have limited rights with respect to the actions of ACP II and no voting rights with respect to the election of managers.

During 2010, each party satisfied the Initial Cash Contribution and now has ability to transfer its interest in the joint venture to third parties 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.

Steven A. Webster, Chairman of the Company’s Board of Directors, serves as Co-Managing Partner and President of Avista Capital Holdings, LP, which has the ability to control Avista. ACP II’s Board of Managers have the sole authority for determining whether, when and to what extent any cash distributions will be declared and paid to members of ACP II. Mr. Webster is not a member of ACP II’s Board of Managers. As previously disclosed, the Company has been a party to prior arrangements with affiliates of Avista Capital Holdings, LP in respect of the Company’s investment in Pinnacle Gas Resources, Inc.

ACP II Distributions. During the third and fourth quarters of 2010, the Company received cash distributions of $38.8 million on its B Unit investment in ACP II, which were recognized as a reduction of capitalized oil and gas property costs.

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Avista Land Bank Agreement. In order to expand the Company’s lease acquisition efforts in the Marcellus Shale, the Company elected to enter into a lease option agreement effective August 1, 2008 with Avista. The terms and conditions of the lease purchase option arrangement with Avista were generally consistent with lease option arrangements that the Company has 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 to the Company’s Marcellus joint venture with Avista, effective August 1, 2008.

Other Transactions. The Company’s Chairman of the Board, Mr. Steven A. Webster, serves on the Board of Directors of Basic Energy Services, Inc., Hercules Offshore, Inc., and Geokinetics, Inc., the parent of Geokinetics USA (formally Quantum Geophysical, Inc.), and previously served on the Board of Directors of each of Goodrich Petroleum, Brigham Exploration, Pinnacle Gas Resources, Inc. and Grey Wolf Inc. The Company’s Chief Executive Officer, Mr. S.P. Johnson, serves on the Board of Directors of Basic Energy Services, Inc. and Pinnacle Gas Resources, Inc. until the time of its sale in January 2011. Mr. Thomas L. Carter, Jr., a member of the Company’s Board of Directors, is the Chief Executive Officer and owner of a significant interest in Black Stone Minerals Company, L.P. (“Black Stone Minerals”). Mr. F. Gardner Parker serves on the Board of Directors for Hercules Offshore, Inc. Due to these relationships, the Company has deemed these companies to be related parties. The Company incurred the following costs with these related parties:


	Year Ended December 31,
	2010		2009		2008
	(In millions)
Basic Energy Services	$	0.3	$	0.1	$	0.4
Geokinetics, Inc.		—		0.4		—
Grey Wolf Inc.⁽¹⁾		—		—		7.1
Hercules Offshore, Inc.		—		—		3.2

⁽¹⁾	During 2009, Grey Wolf Inc. merged with another company and is no longer considered a related party at January 1, 2009.

It is the Company’s opinion that the transactions with these entities were executed at prevailing market rates. At December 31, 2010, 2009 and 2008, the Company had outstanding related-party net payable balances of approximately $58,000, $66,000 and $66,000, respectively.

In January 2006, the Company acquired certain oil and gas leases for approximately $1.1 million from Black Stone Acquisitions Partners I L.P., the general partner of which is Black Stone Minerals. Black Stone Acquisition Partners also retains a royalty interest in the acquired leases, which are located in Mississippi. During 2008, the Company acquired additional acreage located in Texas from Black Stone Minerals for approximately $0.2 million. During 2010 and 2009, the Company did not acquire any additional acreage from Black Stone Minerals. The terms and conditions of the lease agreement with Black Stone Acquisitions Partners I L.P. and Black Stone are generally consistent with the lease agreements that the Company has entered into with other third parties. Additionally, the Company operates four producing wells in which affiliates of Black Stone Minerals hold a royalty interest for which the Company paid approximately $0.1 million, $0.2 million and $0.6 million in 2010, 2009 and 2008, respectively.

The Company paid Mr. Webster less than $1,000 in each of 2010, 2009 and 2008 in overriding royalties that were incurred under a lease purchase option arrangement that expired in 2006.

11. DERIVATIVE INSTRUMENTS

The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in its forward cash flows supporting its capital expenditure program. The derivative instruments typically used are fixed-rate swaps, costless collars, puts, calls and basis differential swaps. Under these derivative instruments, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at termination, expiration or exchanged for physical delivery contracts. The Company’s current long-term strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to 36 months. The derivative instruments are carried at fair value in the consolidated balance sheets, with the changes in fair value included in the consolidated statements of operations for the period in which the changes occur.

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is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments. Although the Company does not currently anticipate such nonperformance, it continues to monitor the financial viability of its counterparties. Three of the four counterparties to the Company’s derivative instruments are lenders in the Company’s Revolving Credit Facility, and accordingly, the Company is not required to post collateral under these contracts as they are secured by the Revolving Credit Facility.

The following sets forth a summary of the Company’s natural gas derivative positions at average delivery location (Waha and Houston Ship Channel) prices as of December 31, 2010. Our crude oil derivative positions at December 31, 2010, were not significant.


Period	Volume (in MMbtu)		Weighted Average Floor Price ($/MMbtu)		Weighted Average Ceiling Price ($/MMbtu)
2011		21,340,000	$	5.96	$	6.34
2012		7,963,000	$	6.49	$	7.13

In connection with the derivative instruments above, the Company has entered into protective put spreads. When the market price declines below the short put price as reflected below, the Company will effectively receive the market price plus a put spread. For example, for 2011, if market prices fall below the short put price of $4.55, the floor price becomes the market price plus the put spread of $1.46 on 16,799,000 of the 21,340,000 MMBtus and the remaining 4,541,000 MMBtus have a long put price of $5.96.


Period	Volume (in MMbtu)		Weighted Average Short Put Price ($/MMbtu)		Weighted Average Long Put Price ($/MMbtu)		Weighted Average Put Spread ($/MMbtu)
2011		16,799,000	$	4.55	$	6.01	$	1.46
2012		6,404,000	$	5.20	$	6.41	$	1.21

For the years ended December 31, 2010, 2009 and 2008, the Company recorded the following related to its derivative instruments:


	Year Ended December 31,
	2010		2009			2008
	(In thousands)
Realized gain (loss)
Derivative instruments	$	33,218	$	74,866		$	(1,819	)
Interest rate swaps		—		—			(1,201	)
Loss on interest swap termination		—		—			(3,340	)

		33,218		74,866			(6,360	)

Unrealized gain (loss)
Derivative instruments		14,564		(33,401	)		41,104
Interest rate swaps		—		—			2,755

		14,564		(33,401	)		43,859

Gain on derivative instruments, net	$	47,782	$	41,465		$	37,499

The Company deferred the payment and receipt of premiums associated with certain of its derivative instruments totaling a net liability of $3.9 million and $4.8 million at December 31, 2010 and December 31, 2009, respectively. The Company classified $3.9 million and $1.8 million as other current liabilities at December 31, 2010 and December 31, 2009, respectively, and $3.0 million as other non-current liabilities at December 31, 2009. These deferred premiums will be paid to the counterparty with each monthly settlement (January 2011 – December 2011) and recognized as a reduction of realized gain on derivative instruments.

12. FAIR VALUE MEASUREMENTS

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

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Level 1 — Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2 — Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 — Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2010 and 2009, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:


December 31, 2010	Level 1		Level 2			Level 3		Total
	(In thousands)
Assets:
Investment in Pinnacle Gas Resources, Inc.	$	869	$	—		$	—	$	869
Derivative instruments		—		48,140			—		48,140
Liabilities:
Derivative instruments		—		(24,062	)		—		(24,062	)

Total	$	869	$	24,078		$	—	$	24,947


December 31, 2009	Level 1		Level 2			Level 3		Total
	(In thousands)
Assets:
Investment in Pinnacle Gas Resources, Inc.	$	835	$	—		$	—	$	835
Derivative instruments		—		14,881			—		14,881
Liabilities:
Derivative instruments		—		(2,818	)		—		(2,818	)

Total	$	835	$	12,063		$	—	$	12,898

The fair values of derivative instruments are based on a third-party pricing model which utilizes inputs that include (a) quoted forward prices for oil and gas, (b) discount rates, (c) volatility factors and (d) current market and contractual prices, as well as other relevant economic measures. The estimates of fair value are compared to the values provided by the counterparty for reasonableness. Derivative instruments are subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of the Company’s derivative instruments, but to date has not had a material impact on estimates of fair values. The fair values reported in the consolidated balance sheets are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. The assets and liabilities for derivative instruments included in the tables above are presented on a gross basis. The assets and liabilities for derivative instruments included in the consolidated balance sheets are presented on a net basis when such amounts are with the same counterparty and subject to master netting agreements. The fair values of the investment in Pinnacle are based on the closing price of Pinnacle’s common stock on December 31, 2010 and December 31, 2009. The Company had no transfers in or out of Levels 1 or 2 for the year ended December 31, 2010.

Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables and current and long-term debt. The carrying amounts of cash and cash equivalents, receivables, payables and short-term debt approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the borrowings under the Prior Credit Facility approximate the carrying amounts as of December 31, 2010, and were based upon interest rates currently available to the Company for borrowings with similar terms. The fair values of the Convertible Senior Notes and Senior Notes at December 31, 2010 were estimated at approximately $71.9 million and $412.0 million based on quoted market prices.

Other Fair Value Measurements

The initial measurement of asset retirement obligations at fair value is calculated using discounted future cash flows of internally estimated costs. Significant Level 3 inputs used in the calculation of asset retirement obligations include the costs of plugging and

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abandoning wells, the costs of surface restoration and reserve lives. See Note 7. Asset Retirement Obligations for a roll forward of the Company’s asset retirement obligations.

13. SUBSEQUENT EVENTS

Senior Secured Revolving Credit Facility

On January 27, 2011, the Company entered into a new $750 million secured revolving credit facility with a five-year term (“Revolving Credit Facility”) with BNP Paribas as the administrative agent, sole book runner and lead arranger in the nine-bank syndication. The Revolving Credit Facility provides for a revolving credit facility up to the lesser of (i) the Borrowing Base and (ii) $750 million. The Revolving Credit Facility matures on January 27, 2016. It is secured by substantially all of the Company’s assets and is guaranteed by certain of the Company’s subsidiaries: Bandelier Pipeline Holding, LLC, Carrizo Marcellus Holding Inc., Carrizo (Marcellus) LLC, Carrizo (Marcellus) WV LLC, CLLR, Inc., Hondo Pipeline, Inc. and Mescalero Pipeline, LLC.

The initial Borrowing Base under the Revolving Credit Facility is $350 million. The Borrowing Base will be redetermined by the lenders at least semi-annually on each May 1 and November 1, beginning May 1, 2011. The Company and the lenders may each request one unscheduled borrowing base redetermination between each scheduled redetermination. The Borrowing Base will also be reduced in certain circumstances as a result of certain issuances of senior notes, cancellation of certain hedging positions and as a result of certain asset sales. The amount the Company is able to borrow with respect to the Borrowing Base is subject to compliance with the financial covenants and other provisions of the Revolving Credit Facility.

If the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the Revolving Credit Facility exceeds the Borrowing Base at any time as a result of a redetermination of the Borrowing Base, the Company has 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, deliver reserve engineering reports and mortgages covering additional oil and gas properties 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 next six-month period. Upon certain adjustments to the Borrowing Base, the Company is required to make a lump sum payment in an amount equal to the amount by which the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the Revolving Credit Facility exceeds the Borrowing Base. Otherwise, any unpaid principal will be due at maturity.

The Company is subject to certain covenants under the terms of the Revolving Credit Facility which include, but are not limited to, the maintenance of the following financial covenants: (1) a total net debt to Consolidated EBITDA (as defined in the Revolving Credit Facility) ratio of not more than (a) 4.75 to 1.00 for any fiscal quarter ending on or after March 31, 2011 and on or before December 31, 2011, (b) 4.25 to 1.00 for any fiscal quarter ending on or after March 31, 2012 and on or before June 30, 2012 and (c) 4.00 to 1.00 for any fiscal quarter ending on or after September 30, 2012; (2) a current ratio of not less than 1.0 to 1.0; (3) a senior debt to EBITDA ratio of not more than 2.50 to 1.00; and (4) an EBITDA to interest expense ratio of not less than 2.50 to 1.00.

The Revolving Credit Facility also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.

On January 27, 2011, the Company borrowed $112 million under the Revolving Credit Facility, which was used to repay in full indebtedness outstanding under the Senior Credit Agreement governing the Prior Credit Facility, to pay transaction costs associated with entrance into the Revolving Credit Facility and for other general business purposes. Future availability under the new Revolving Credit Facility, which currently has a $350 million borrowing base, is subject to the terms and covenants of the Revolving Credit Facility.

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UK North Sea Credit Agreement

On January 28, 2011, the Company and Carrizo UK Huntington Ltd., a wholly-owned subsidiary of the Company incorporated in England and Wales (“Carrizo UK”), as Borrower, entered into a Senior Secured Multicurrency Credit Facility Agreement with BNP Paribas and Societe Generale, as lead arrangers and original lenders (the “Huntington Facility”). The Huntington Facility is secured by substantially all of Carrizo UK’s assets and is limited recourse to the Company. The Huntington Facility provides financing for a substantial portion of Carrizo UK’s share of costs associated with the Huntington Field development project in the U.K. North Sea. The Huntington Facility provides for a multi-currency credit facility consisting of (1) a term loan facility to be used to fund Carrizo UK’s share of project development costs, (2) a contingent cost overrun term loan facility and (3) a post-completion revolving credit facility providing for loans and letters of credit to be used to fund certain abandonment and decommissioning costs following project completion.

Initial borrowings under the term loan facility and cost overrun facility are conditioned on, among other things, the Company’s having made an approximately $22 million equity contribution to Carrizo UK, which has been completed. Prior to project completion, the Company may be required under the Huntington Facility to make an additional equity contribution to Carrizo UK in the event the term loan borrowing base is reduced to a level at or above the amount of borrowings then outstanding. The Company may be required under the Huntington Facility to make certain additional equity contributions to Carrizo UK in the event of certain specified projected Cost Overruns (as defined in the Huntington Facility). To the extent that the cost overrun facility and any required equity contribution are insufficient, the Company is required to fund any Cost Overruns on a 100% basis. If after project completion, the lenders reasonably determine that Carrizo UK is required to incur additional capital expenditures that were not contemplated by the Huntington Field development plan originally approved by the U.K. Department of Energy and Climate Change, the Company is required to fund such additional expenditures. The Company is responsible for making certain other payments under the Huntington Facility, including funding certain projected working capital shortfalls, providing cash collateral for letters of credit issued under the post-completion revolving credit facility and paying certain costs of the required hedging arrangements described below.

The Huntington Facility requires Carrizo UK to enter into certain hedging arrangements to hedge a specified portion of the Huntington Field project’s exposure to fluctuating petroleum prices as well as changes in interest rates or exchange rates, and permits Carrizo UK to enter into additional hedging arrangements. The Huntington Facility places restrictions on Carrizo UK with respect to additional indebtedness, liens, the extension of credit, dividends or other payments to the Company or its other subsidiaries, investments, acquisitions, mergers, asset dispositions, commodity transactions outside of the mandatory hedging program, transactions with affiliates and other matters.

14. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

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The Company’s oil and gas properties are located in the U.S. and U.K.

Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below:


	Year Ended December 31,
	2010		2009			2008
	(In thousands)
U.S.
Property acquisition costs
Unproved	$	126,783	$	35,248		$	271,618
Proved		—		—			—
Exploration costs		134,487		77,255			235,382
Development costs		62,952		55,270			49,626
Asset retirement obligations		1,031		(1,390	)		630

Total costs incurred	$	325,253	$	166,383		$	557,256


U.K.
Property acquisition costs
Unproved	$	806	$	—		$	—
Proved		—		—			—
Exploration costs		5,375		—			—
Development costs		—		—			—
Asset retirement obligations		—		—			—

Total costs incurred	$	6,181	$	—		$	—


Total Worldwide
Property acquisition costs
Unproved	$	127,589	$	35,248		$	271,618
Proved		—		—			—
Exploration costs		139,862		77,255			235,382
Development costs		62,952		55,270			49,626
Asset retirement obligations		1,031		(1,390	)		630

Total costs incurred	$	331,434	$	166,383		$	557,256

Costs incurred excludes capitalized interest on unproved properties of $20.8 million, $19.7 million, and $20.5 million for the years ended December 31, 2010, 2009 and 2008, respectively, and includes capitalized overhead of $5.3 million, $5.6 million, and $7.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Proved Oil and Gas Reserve Quantities

Proved reserves are generally those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves include proved reserves that can be expected to be produced through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are generally 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.

Proved oil and gas reserve quantities at December 31, 2010, 2009 and 2008, and the related discounted future net cash flows before income taxes are based on estimates prepared by LaRoche Petroleum Consultants, Ltd., Ryder Scott Company Petroleum Engineers, and Fairchild and Wells, Inc. Such estimates have been prepared in accordance with guidelines established by the SEC.

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The Company’s net proved oil and gas reserves and changes in net proved oil and gas reserves, which are located in the U.S. and U.K., are summarized below:


	Millions of Cubic Feet of Natural Gas at December 31,
	U.S.			U.K.		Worldwide

Proved developed and undeveloped reserves —
January 1, 2008		248,433			—		248,433
Extensions and discoveries		146,189			—		146,189
Revisions of previous estimates		21,661			—		21,661
Production		(23,547	)		—		(23,547	)

End of year - December 31, 2008		392,736			—		392,736

Proved developed reserves at beginning of year		122,598			—		122,598

Proved developed reserves at end of year		216,229			—		216,229

Proved undeveloped reserves at beginning of year		125,835			—		125,835

Proved undeveloped reserves at end of year		176,507			—		176,507


January 1, 2009		392,736			—		392,736
Extensions and discoveries		196,400			—		196,400
Revisions of previous estimates		(42,867	)		—		(42,867	)
Sales of reserves in place		(3,195	)		—		(3,195	)
Production		(30,027	)		—		(30,027	)

End of year - December 31, 2009		513,047			—		513,047

Proved developed reserves at beginning of year		216,229			—		216,229

Proved developed reserves at end of year		292,695			—		292,695

Proved undeveloped reserves at beginning of year		176,507			—		176,507

Proved undeveloped reserves at end of year		220,352			—		220,352


January 1, 2010		513,047			—		513,047
Extensions and discoveries		240,347			4,684		245,031
Revisions of previous estimates		(54,132	)		—		(54,132	)
Production		(34,095	)		—		(34,095	)

End of year - December 31, 2010		665,167			4,684		669,851

Proved developed reserves at beginning of year		292,695			—		292,695

Proved developed reserves at end of year		358,543			—		358,543

Proved undeveloped reserves at beginning of year		220,352			—		220,352

Proved undeveloped reserves at end of year		306,624			4,684		311,308

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	Crude Oil, Condensate and Natural Gas Liquids at December 31,
	U.S.			U.K.		Worldwide
Proved developed and undeveloped reserves —
January 1, 2008		16,531			—		16,531
Extensions and discoveries		2,088			—		2,088
Revisions of previous estimates		36			—		36
Production		(347	)		—		(347	)

End of year - December 31, 2008		18,308			—		18,308

Proved developed reserves at beginning of year		6,536			—		6,536

Proved developed reserves at end of year		7,869			—		7,869

Proved undeveloped reserves at beginning of year		9,995			—		9,995

Proved undeveloped reserves at end of year		10,439			—		10,439


January 1, 2009		18,308			—		18,308
Extensions and discoveries		2,373			—		2,373
Revisions of previous estimates		(5,375	)		—		(5,375	)
Production		(503	)		—		(503	)

End of year - December 31, 2009		14,803			—		14,803

Proved developed reserves at beginning of year		7,869			—		7,869

Proved developed reserves at end of year		6,898			—		6,898

Proved undeveloped reserves at beginning of year		10,439			—		10,439

Proved undeveloped reserves at end of year		7,905			—		7,905


January 1, 2010		14,803			—		14,803
Extensions and discoveries		10,961			5,263		16,224
Revisions of previous estimates		(2,102	)		—		(2,102	)
Production		(452	)		—		(452	)

End of year - December 31, 2010		23,210			5,263		28,473

Proved developed reserves at beginning of year		6,898			—		6,898

Proved developed reserves at end of year		7,387			—		7,387

Proved undeveloped reserves at beginning of year		7,905			—		7,905

Proved undeveloped reserves at end of year		15,823			5,263		21,086

Natural gas extensions and discoveries are primarily attributable to the following:


2010		Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett Shale and Eagle Ford Shale, as well as an increase in previously estimated proved undeveloped reserves based on operational performance; Additions of U.K. proved undeveloped reserves as a result of the approval of the Huntington Field Development Plan by the Company and its joint venture partners and the U.K. Department of Energy and Climate Change in November 2010.
2009		Additions to proved developed and undeveloped reserves as a result of drilling and additional offset locations in the Barnett Shale recognized under the oil and gas reserve estimation and disclosure requirements which the Company adopted effective December 31, 2009.
2008		Additions to proved developed and undeveloped reserves as a result of drilling in the Barnett Shale.

Natural gas revisions of previous estimates are primarily attributable to the following:


2010		Positive price revisions offset by negative quantity revisions due to a planned shift in future drilling priorities focusing more on drilling in the core of the Barnett Shale, which resulted in removing natural gas reserves previously classified as proved undeveloped in the Barnett Shale.
2009		Negative price revisions primarily in the Barnett Shale and Gulf Coast.
2008		Positive performance revisions primarily in the Barnett Shale.

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Crude oil, condensate and natural gas liquids and extensions and discoveries are primarily attributable to the following:


2010		Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale; Additions of U.K. proved undeveloped reserves as a result of the approval of the Huntington Field Development Plan by the Company and its joint venture partners and the U.K. Department of Energy and Climate Change in November 2010.

Crude oil, condensate and natural gas liquids revisions of previous estimates are primarily attributable to the following:


2009		The oil and gas reserve estimation and disclosure requirements, which the Company adopted effective December 31, 2009, resulted in the removal of 5.4 MMBls of crude oil reserves previously classified as proved undeveloped in the Camp Hill Field that were not associated with wells that were expected to be both drilled prior to December 31, 2014 and into which the Company then planned to inject steam prior to December 31, 2014.

Standardized Measure

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:


	Crude Oil, Condensate and Natural Gas Liquids at December 31,
	U.S.			U.K.			Worldwide
2010
Future cash inflows	$	3,514,978		$	432,231		$	3,947,209
Future production costs		(952,148	)		(96,782	)		(1,048,930	)
Future development costs		(597,444	)		(78,439	)		(675,883	)
Future income taxes		(415,021	)		(128,619	)		(543,639	)

Future net cash flows		1,550,365			128,391			1,678,756
Less 10% annual discount to reflect timing of cash flows		(895,681	)		(34,289	)		(929,970	)

Standard measure of discounted future net cash flows	$	654,684		$	94,102		$	748,786


2009
Future cash inflows	$	2,150,293		$	—		$	2,150,293
Future production costs		(943,774	)		—			(943,774	)
Future development costs		(297,023	)		—			(297,023	)
Future income taxes		(73,656	)		—			(73,656	)

Future net cash flows		835,840			—			835,840
Less 10% annual discount to reflect timing of cash flows		(453,747	)		—			(453,747	)

Standard measure of discounted future net cash flows	$	382,093		$	—		$	382,093


2008
Future cash inflows	$	2,501,460		$	—		$	2,501,460
Future production costs		(868,027	)		—			(868,027	)
Future development costs		(315,837	)		—			(315,837	)
Future income taxes		(223,828	)		—			(223,828	)

Future net cash flows		1,093,768			—			1,093,768
Less 10% annual discount to reflect timing of cash flows		(582,819	)		—			(582,819	)

Standard measure of discounted future net cash flows	$	510,949		$	—		$	510,949

Effective December 31, 2009, the Company adopted the new requirements for oil and gas reserve estimation and disclosure which require that reserve estimates and future cash flows be based on the average market prices for sales of oil and gas on the first calendar day of each month during the year. The average prices used for 2010 and 2009 under these rules were $74.39 and $56.10 per barrel, respectively, for crude oil and condensate, $35.18 and $23.18 per barrel, respectively, for natural gas liquids, and $3.50 and $3.30 per

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Mcf, respectively, for natural gas. Future cash inflows for 2008 were computed by applying year-end prices to year-end quantities of proved oil and gas reserves under the oil and gas reserve estimation and disclosure requirements in effect at that time. The price used in computing the December 31, 2008 reserve estimates and future cash flows was $40.12 per barrel for oil and condensate, $19.62 per barrel for natural gas liquids, and $4.99 per Mcf for natural gas.

Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved oil and gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income taxes are based on year-end statutory rates, adjusted for the tax basis of oil and gas properties and available applicable tax assets. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s oil and gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil and gas reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are summarized below:


	Year Ended December 31,
	2010			2009			2008
Changes in Standardized Measure:
Standardized measure — beginning of year	$	382,093		$	510,949		$	662,370

Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production		263,663			(254,511	)		(371,924	)
Net change in estimated future development costs		83			108,831			(80,780	)
Net change due to revisions in quantity estimates		(25,451	)		(71,840	)		44,643
Accretion of discount		39,833			59,589			83,931
Changes in production rates (timing) and other		49,806			(70,616	)		(67,218	)

Total revisions		327,934			(228,547	)		(391,348	)
Net change due to extensions and discoveries, net of estimated future development and production costs		351,831			76,419			228,037
Net change due to sales of minerals in place		—			748			—
Sales of oil and gas produced, net of production costs		(115,800	)		(80,997	)		(171,944	)
Previously estimated development costs incurred		43,940			34,816			91,832
Net change in income taxes		(241,212	)		68,705			92,002

Net change in standardized measure of discounted future net cash flows		366,693			(128,856	)		(151,421	)

Standardized measure — end of year	$	748,786		$	382,093		$	510,949

15. SELECTED QUARTERLY FINANCIAL DATA AND RESTATEMENT OF PREVIOUSLY ISSUED INTERIM FINANCIAL STATEMENTS (UNAUDITED)

The following table presents summarized quarterly financial information for the years ended December 31, 2010 and 2009:


2010	First			Second			Restated Third			Fourth
	(In thousands, except per share amounts)
Revenues	$	39,424		$	33,191		$	30,812		$	36,035
Costs and expenses, net		(19,688	)		(31,406	)		(17,978	)		(60,440	)(1)

Net income (loss)	$	19,736		$	1,785		$	12,834		$	(24,405	)

Basic net income (loss) per share	$	0.64		$	0.05		$	0.37		$	(0.69	)
Diluted net income (loss) per share	$	0.63		$	0.05		$	0.37		$	(0.69	)

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2009	First			Second			Third			Fourth
	(In thousands, except per share amounts)
Revenues	$	31,203		$	26,171		$	23,847		$	32,858
Costs and expenses, net		(156,748	)(2)		(32,187	)		(28,642	)		(101,347	)(2)

Net loss	$	(125,545	)	$	(6,016	)	$	(4,795	)	$	(68,489	)

Basic net loss per share	$	(4.07	)	$	(0.19	)	$	(0.15	)	$	(2.20	)
Diluted net loss per share	$	(4.07	)	$	(0.19	)	$	(0.15	)	$	(2.20	)

(1)	The fourth quarter of 2010 includes a pre-tax loss on extinguishment of debt of $31.0 million.

(2)	The first and fourth quarters of 2009 include pre-tax impairments of oil and gas properties of $216.4 million and $122.5 million, respectively.

The sum of the individual quarterly basic and diluted income (loss) per share amounts may not agree with year-to-date basic and diluted income (loss) per share as each quarterly computation is based on the weighted average number of common shares outstanding during that period.

During the third quarter of 2010, the Company received cash distributions of $20.8 million on its B Unit investment in ACP II. The Company followed the cost method of accounting for the B Units and recognized cash distributions received with respect to the B Units as Distribution Income-Related Party in the consolidated statements of operations included in the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010. However, the Company subsequently concluded that under the full cost method of accounting, the cash distributions should be considered proceeds from the sale of oil and gas properties and accordingly, should be recognized as a reduction of capitalized oil and gas property costs.

The effect of restating the Company’s financial statements for the three-month and nine-month periods ended September 30, 2010 to recognize the cash distributions received on the B Units as a reduction of capitalized oil and gas property costs rather than distribution income-related party and related income tax effects, resulted in a decrease in net income and total shareholders’ equity of $11.5 million from the previously reported amounts for the three months and nine months ended September 30, 2010 which represents a decrease in diluted income per common share of $0.32 and $0.34 from the previously reported amounts for the three-months and nine months ended September 30, 2010, respectively, with a corresponding decrease in proved oil and gas properties of $20.5 million and an increase in income tax assets and liabilities of $9.0 million from the previously reported amounts as of September 30, 2010. The restatement also resulted in a decrease in cash flows from operating activities and a corresponding increase in cash flows from investing activities of $20.8 million from the previously reported amounts for the nine months ended September 30, 2010.

The restatement did not affect the Company’s balance of cash and cash equivalents as of September 30, 2010 nor did it effect net income or loss for any of the Company’s previously issued financial statements for periods prior to the three-month period ended September 30, 2010. EBITDA, as defined in both the Company’s Prior Credit Facility and Revolving Credit Facility, includes cash distributions received on the Company’s B Unit investment in ACP II and, accordingly, the restatement had no and will have no impact on the Company’s compliance with the financial covenants under the terms of the Prior Credit Facility or Revolving Credit Facility and will have no impact on the Company’s ability to draw on the Revolving Credit Facility’s available borrowing base.

The following tables report the full effect of the restatement on the Company’s consolidated balance sheet as of September 30, 2010, the consolidated statements of operations for the three-month and nine-month periods then ended and the consolidated statement of cash flows for the nine-month period then ended:

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CONSOLIDATED BALANCE SHEET


	September 30, 2010 As Previously Reported			September 30, 2010 Restated
	(In thousands) (Unaudited)
ASSETS
PROPERTY AND EQUIPMENT, NET
Oil and gas properties using the full-cost method of accounting:
Proved oil and gas properties, net	$	502,506		$	481,988

TOTAL PROPERTY AND EQUIPMENT, NET		949,568			929,050

DEFERRED INCOME TAXES		49,441			60,370

TOTAL ASSETS	$	1,080,495		$	1,070,906


LIABILITIES AND SHAREHOLDERS’ EQUITY

CURRENT LIABILITIES:
Current state tax payable	$	1,989		$	2,311
Deferred income taxes		6,405			8,015

Total current liabilities		112,328			114,260


SHAREHOLDERS’ EQUITY:
Accumulated deficit		(138,672	)		(150,193	)

Total shareholders’ equity		375,356			363,835

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY	$	1,080,495		$	1,070,906

CONSOLIDATED STATEMENTS OF OPERATIONS


	For the Three Months Ended September 30, 2010						For the Nine Months Ended September 30, 2010
	As Previously Reported			Restated			As Previously Reported			Restated
	(In thousands, except per share amounts) (Unaudited)
COSTS AND EXPENSES:
Depreciation, depletion and amortization	$	10,369		$	10,094		$	31,289		$	31,014

TOTAL COSTS AND EXPENSES		29,173			28,898			83,056			82,781


OPERATING INCOME		1,639			1,914			20,371			20,646

OTHER INCOME AND EXPENSES:
Distribution income - related party		20,793			—			20,793			—

INCOME BEFORE INCOME TAXES		39,156			18,638			73,689			53,171
INCOME TAX EXPENSE		(14,801	)		(5,804	)		(27,813	)		(18,816	)


NET INCOME	$	24,355		$	12,834		$	45,876		$	34,355


COMPREHENSIVE INCOME	$	24,339		$	12,818		$	45,860		$	34,339


BASIC INCOME PER COMMON SHARE	$	0.70		$	0.37		$	1.38		$	1.03


DILUTED INCOME PER COMMON SHARE	$	0.69		$	0.37		$	1.36		$	1.02

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CONSOLIDATED STATEMENT OF CASH FLOWS


	For the Nine Months Ended September 30, 2010
	As Previously Reported			Restated
	(In thousands) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	45,876		$	34,355
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation, depletion and amortization		31,289			31,014
Deferred income taxes		25,716			16,719

Net cash provided by operating activities	$	99,632		$	78,739


CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of oil and gas properties	$	15,042		$	35,835

Net cash used in investing activities	$	(229,258	)	$	(208,465	)

F-39

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.


CARRIZO OIL & GAS, INC.

By:		/s/ Paul F. Boling
		Paul F. Boling
		Chief Financial Officer, Vice President, Secretary and Treasurer

Date: March 31, 2011

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


Name	Capacity	Date

/s/ S. P. Johnson IV	President, Chief Executive Officer and Director	March 31, 2011
S. P. Johnson IV	(Principal Executive Officer)

/s/ Paul F. Boling	Chief Financial Officer, Vice President,	March 31, 2011
Paul F. Boling	Secretary and Treasurer
	(Principal Financial Officer)

/s/ David L. Pitts	Vice President and Chief Accounting Officer	March 31, 2011
David L. Pitts	(Principal Accounting Officer)

/s/ Steven A. Webster	Chairman of the Board	March 31, 2011
Steven A. Webster

/s/ Thomas L. Carter, Jr.	Director	March 31, 2011
Thomas L. Carter, Jr.

/s/ F. Gardner Parker	Director	March 31, 2011
F. Gardner Parker

/s/ Roger A. Ramsey	Director	March 31, 2011
Roger A. Ramsey

/s/ Frank A. Wojtek	Director	March 31, 2011
Frank A. Wojtek

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