Form 10-K

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES þ NO ¨

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 þ

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 þ

At June 30, 2011, the aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $1,504 million based on the closing price of such stock on such date of $41.75.

At February 27, 2012, the number of shares outstanding of the registrant’s Common Stock was 39,578,464.

Portions of the definitive proxy statement for the Registrant’s 2012 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, 2011.

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:

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 credit facilities, evaluations of us by lenders under our credit facilities, the potential impact of government regulations, including current and proposed legislation and regulations related to hydraulic fracturing, oil and natural gas drilling, 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 and crews, 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 and resolution of title defects, new taxes and impact fees, delays, costs and difficulties relating to our joint ventures, actions by joint venture partners, results of exploration activities, the availability and completion of land acquisitions, completion and connection of wells, 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 or revise any forward-looking statement.

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

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 Eagle Ford Shale in South Texas, the Niobrara Formation in Colorado, the Barnett Shale in North Texas, the Marcellus Shale in Pennsylvania, New York and West Virginia, the Utica Shale in Ohio and Pennsylvania, and the U.K. North Sea where our Huntington Field development project is currently under development.

Since we began focusing a significant portion of our efforts in shale plays, particularly in the Barnett Shale and Eagle Ford Shale, we have grown our reserves at a compounded annual growth rate (“CAGR”) of 38%, while simultaneously maintaining a CAGR on our production of 25%. During 2011, we added, net of production, 140 Bcfe to proved reserves, for a reserve replacement ratio of 311%. 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 2011 of 45.1 Bcfe, a 22% increase from 2010. At year-end 2011, our proved reserves of 936 Bcfe were approximately 22% crude oil, condensate and natural gas liquids and approximately 78% natural gas, as compared to 20% and 80% at year-end 2010, respectively.

Our Board of Directors has approved a U.S. capital expenditure plan of $465 million for 2012. This plan reflects our strategy of controlling capital costs and maintaining financial flexibility in light of current economic conditions and is comparable to our $492 million capital expenditures in 2011. We currently expect to commit the majority of our 2012 U.S. capital expenditure plan to the continued development of our properties in the Eagle Ford Shale, Niobrara Formation, and the Marcellus Shale . The level of our expected Marcellus Shale and Eagle Ford Shale capital expenditures has been decreased by the obligation of our joint venture partner to carry a portion of our costs. In the U.K., we have entered into a limited recourse project financing arrangement which we expect to fund all of our $35.0 million capital expenditures plan for our Huntington Field development project in the U.K. North Sea in 2012. We intend to finance our 2012 U.S. capital expenditure plan primarily from cash flow from operations, our senior secured credit facility in the U.S., and our secured limited recourse 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.

At December 31, 2011, our crude oil and liquids proved reserves were 34.7 MMBOE, a 22% increase from 28.5 MMBOE at December 31, 2010. 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 in the Eagle Ford Shale and the Niobrara Formation, collectively adding 14.4 MMBOE of crude oil and liquids to our proved reserves (14.2 MMBOE including associated gas) during 2011, which was partially offset by the sale of a substantial portion of the non-core area Barnett Shale properties (8 MMBOE of crude oil and liquids reserves as of December 31, 2010).

Following the April 2010 announcement of our growth strategy to increase crude oil and liquids production, we commenced a leasing program targeting the gas condensate window of the Eagle Ford Shale. As of December 31, 2011, we held interests in approximately 98,127 gross (41,044 net) acres, 23 gross (19.5 net) producing wells and 12 gross (9.2 net) wells that were drilled but waiting on completion and/or pipeline connection. Of these wells, we operated 23 gross (19.5 net) producing wells and 12 gross (9.2 net) wells drilled and waiting on completion and/or pipeline connection. During 2011, we drilled 30 gross wells (23 net), all of which we operated, and completed and brought on production 18 gross wells (13.9 net). Approximately 16% of our 98,127 gross acres in the Eagle Ford 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 2011 production in the Eagle Ford Shale was 644 MBOE (1,764 Bbls/d), 1,533% above 2010 production of 39 MBOE (108 Bbls/d). Total proved reserves for the Eagle Ford Shale were 28 MMBOE at December 31, 2011, approximately 86%, or 24 MBOE, of which was crude oil and liquids.

As of December 31, 2011, we were operating four rigs in the Eagle Ford Shale and expect to release one rig in March 2012 and then operate the remaining rigs in the Eagle Ford Shale throughout 2012. We currently expect our 2012 Eagle Ford Shale drilling efforts to require an investment of approximately $320 million for drilling and completion costs, which will be spent primarily in our core area within the Eagle Ford Shale in LaSalle county and, to a lesser extent, in McMullen and Atascosa counties.

Although we experienced an increase in completion costs due to increased demand for hydraulic fracturing crews during 2011, we have seen moderation in these costs in early 2012 as a result of the availability of new pressure pumping equipment and the reduced completion activity in resource plays producing primarily natural gas.

In September 2011, we completed the sale of 20% of our interests in certain oil and gas properties in the Eagle Ford Shale (comprising approximately 4,040 net acres, including 5.9 net wells that were producing on these properties at the effective time of the sale) to GAIL GLOBAL (USA) INC. (“GAIL”), a wholly-owned subsidiary of GAIL (India) Limited, for $63.7 million in cash and a commitment by GAIL to pay a “development carry” of 50% of certain of our future development costs up to approximately $31.3 million net to our interest as further described below. In connection with this sale transaction, we and GAIL also entered into agreements to form a new joint venture with respect to the interests purchased by GAIL. Under the terms of the agreement, we generally retained a 80% working interest in the acreage and GAIL owns a 20% working interest. The GAIL development carry lasts until June 30, 2013, unless earlier utilized. We currently expect the GAIL development carry to be exhausted in the first quarter of 2012.

We have also granted an option in favor of GAIL to purchase a 20% share of acreage acquired by us after the closing located in specified areas adjacent to the initially purchased areas. This option 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. Through December 31, 2011, GAIL had exercised option to increase its acreage position by approximately 208 net acres.

As part of our growth strategy in crude oil and liquids, starting in 2010, we also acquired working interests in the Niobrara Formation located in the Denver-Julesberg Basin in Weld and Morgan counties, Colorado. During 2011, we drilled 8 gross wells (4.7 net), of which we operated 7 gross wells (4.4 net), and completed and brought on production 7 gross wells (4.1 net). As of December 31, 2011, we held interests in approximately 107,552 gross (58,255 net) acres, 9 gross (7.6 net) producing wells and 1 gross (0.6 net) wells that were drilled but waiting on completion and/or pipeline connection. Of these wells, we operated 8 gross (6.82 net) producing wells and 1 gross (0.6 net) wells drilled and waiting on completion and/or pipeline connection. Our 2011 production in the Niobrara was 154 MBOE (423 Bbls/d), compared to 2010 production, which was insignificant given we completed our first well in late 2010. Total proved reserves for the Niobrara were 1 MMBOE at December 31, 2011, approximately 88%, or 884 MBOE, of which was crude oil and liquids. We are seeking a joint venture partner for our Niobrara properties in an effort to accelerate value realization from such assets, although there can be no assurance that we will be able to enter into a joint venture for such assets on terms that are acceptable to us or at all.

In 2011, we commenced acquiring acreage in the Utica Shale located in eastern Ohio and northwestern Pennsylvania. Our activities in the Utica Shale are currently conducted through a joint venture described below.

Effective September 2011, our wholly-owned subsidiary, Carrizo (Utica) LLC, entered into a joint venture with ACP II Marcellus LLC, which is also our joint venture partner in the Marcellus Shale (“ACP II”) and ACP III Utica LLC (“ACP III”), affiliates of Avista Capital Holdings, LP, a private equity firm (collectively with ACP II and ACP III, “Avista”). Under the terms of this joint venture, we and Avista have the right to contribute cash and properties to acquire and develop acreage in the Utica Shale play.

The properties initially dedicated to this joint venture consist of approximately 15,000 net acres in eastern Ohio and northwestern Pennsylvania, as well as any future properties acquired by either party within Ohio, and at the contributing party’s option, elsewhere in the Utica Shale play. Under the terms of the joint venture agreement, our participating interest in the joint venture properties is initially 10% and Avista’s initial participating interest is 90%. Avista has the right to contribute aggregate funds of up to $130.0 million to the joint venture initially, with the ability to raise this amount by an incremental $70.0 million. As of December 31, 2011, our Utica joint venture with Avista held approximately 20,406 net acres in Ohio and Pennsylvania.

We have been granted a 12-month option (expiring in September 2012) to increase our participating interest in the 15,000 net acres initially dedicated to the joint venture and certain other related acreage acquisitions to 50%, and an 18-month option (expiring in March 2013) to increase our participating interest in other properties that may be acquired by the joint venture to 50%. Our purchase options may be exercised at specified increments above acreage cost and associated improvements at any time during the applicable option period. The exercise deadlines for both options are accelerated in connection with a sale by Avista of substantially all of its interests in the Utica joint venture properties.

We will initially serve as operator of the Utica joint venture properties and will provide certain management services to Avista related to the Utica joint venture. Avista or its designee has the right to become a co-operator of the joint venture properties if we exercise our 18-month option and (i) Avista sells substantially all of its interests in the Utica joint venture properties or (ii) we default under the terms of any pledge of our interest in the Utica joint venture properties. Avista has the ability to cause us to resign as

operator and appoint Avista or Avista’s designee as operator of the properties if we do not exercise our 18-month option by such option’s deadline (or, in such case, Avista may request that we continue as contract operator), or if we default under the terms of any pledge of our interest in the Utica joint venture properties at any time when we have not exercised our 18-month option.

In addition to our share in the production and sale proceeds from the Utica joint venture properties, we also acquired in the transaction interests in ACP III (“B Units”) that entitle us to increasing percentages of ACP III’s distributions of proceeds from properties subsequently acquired by this joint venture to ACP III’s members if specified internal rates-of-return and return-on-investment thresholds with respect to Avista’s investments in ACP III are achieved. Our B Units interest in ACP III provide consent rights only in limited circumstances and generally do not entitle us to vote or participate in the management of ACP III, which is controlled by its members who are Avista affiliates. Our B Units in ACP III will terminate upon (i) the exercise and closing of our 18-month option to increase our interest in the properties subsequently acquired by the joint venture or (ii) the sale of substantially all of our interest in the joint venture properties other than in connection with a sale by Avista of substantially all of its interest in the Utica joint venture. In addition, our existing B Units interest in ACP II pursuant to the Avista Marcellus joint venture (described below under “Natural Gas Plays—Avista Marcellus Joint Venture”) was amended to entitle us to a portion of ACP II’s distributions of proceeds from the properties initially dedicated to the Avista Utica joint venture to its members, provided that specified internal rates-of-return and return-on-investment thresholds are achieved, unless and until we increase our interest in such properties through our 12-month option or sell substantially all of our interest in such properties. Termination of the ACP III management services agreement under certain circumstances will also result in the termination of our rights to distributions under the B Units described in this paragraph.

The area of mutual interest for the Utica joint venture, consisting of the portions of the State of Ohio that are prospective for Utica Shale exploration, will remain in place until the earliest to occur of the following events, at which time the area of mutual interest will only continue to apply to those areas where the joint venture is active: (i) September 1, 2014, (ii) ACP III’s investment reaches $100.0 million, (iii) upon ACP II’s or ACP III’s request to be designated (or have its designee designated) as a co-operator of the properties following exercise of our 18-month option, (iv) upon our required designation of ACP II or ACP III (or either’s designee) as a co-operator of the applicable properties in connection with a default by us under the terms of any pledge of our interest in the Utica joint venture properties, (v) the sale by Avista of substantially all of its interest in the Utica joint venture properties or (vi) termination of the ACP III management services agreement.

Each party’s ability to transfer its interest in the Utica joint venture to third parties is generally subject to “tag along” rights. Avista’s tag along rights do not apply upon a change of control of Carrizo. Our interests are subject to “drag along” rights in connection with sales by Avista of all of its Utica joint venture interests unless we exercise our 18-month option, with respect to properties subsequently acquired by the Utica joint venture, and our 12-month option, with respect to properties initially dedicated to the Utica joint venture and certain related properties. Prior to the exercise of our 18-month option, we generally may not transfer less than substantially all of our interest in the Utica joint venture properties without Avista’s consent.

Steven A. Webster, Chairman of our Board of Directors, serves as Co-Managing Partner and President of Avista Capital Holdings, LP, which entity has the ability to control Avista and its affiliates. ACP II’s and ACP III’s Boards 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 or ACP III, respectively. Mr. Webster is not a member of either entity’s Board of Managers. As previously disclosed, we have been a party to prior arrangements with affiliates of Avista Capital Holdings LP, including in respect of our existing joint venture with Avista in the Marcellus Shale. The terms of the joint ventures with Avista in the Utica Shale and the Marcellus Shale were approved by a special committee of Carrizo’s disinterested directors. See also “Natural Gas Plays—Avista Marcellus Joint Venture” and Note 10 to our Consolidated Financial Statements.

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 acquisition of our interest in 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 fourth quarter of 2012. The field is being developed with horizontal producer wells and two vertical water injection wells. As of February 27, 2012, three of the four producer wells and one of the injector wells had been successfully drilled and completed. The other injection well and the other producer well are expected to be completed by mid-August, well in advance of first production. We currently anticipate that our share of production, once the initial production plateau is reached after field startup, will be approximately 4,500 BOE per day. As of December 31, 2011, our proved reserves in the Huntington Forties reservoir were approximately 6 MMBOE, approximately 87% of which was crude oil.

In January 2011, we and our Carrizo UK Huntington Ltd. (“Carrizo UK”) subsidiary, as borrower, entered into a senior secured multicurrency credit facility agreement secured by substantially all of Carrizo UK’s assets with limited recourse to us (the “Huntington Facility”). 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 project through a term loan facility, a cost overrun facility and a letter of credit facility. We currently believe that amounts available under the Huntington Facility will be sufficient to meet Carrizo UK’s share of capital expenditures through field start-up. We also 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 the license containing our Huntington Field development, as of February 27, 2012, we held interests in four other licenses. By virtue of our bid exploration strategy, each of these licenses is within ten miles of established facilities, allowing the use of existing infrastructure. We currently have satisfied or believe that we can satisfy all remaining committed work obligations on these four licenses at no material additional cost to the Company.

At December 31, 2011, our natural gas proved reserves were 728 Bcf, a 9% increase from 670 Bcf at December 31, 2010, approximately 90% of which was located in the Barnett Shale. Our natural gas production increased to 38.9 Bcf (107 MMcf/d) in 2011, a 14% increase from the 34.1 Bcf (93 MMcf/d) in 2010.

In 2003, we began active participation in the Barnett Shale through acquisition of acreage. As of December 31, 2011, we held interests in approximately 34,313 gross (24,666 net) acres, 270 gross (171.1 net) producing wells and 23 gross (6.1 net) wells that were drilled but waiting on completion and/or pipeline connection. Of these wells, we operated 186 gross (156.1 net) producing wells and 7 gross (2.5 net) wells drilled and waiting on completion and/or pipeline connection. During 2011, we drilled 48 gross wells (15.3 net), of which we operated 17 gross wells (9.1 net), and completed and brought on production 60 gross wells (28.0 net). Approximately 82% of our 34,313 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 2011 production in the Barnett Shale was a record 36 Bcfe, 12% above 2010 production of 32 Bcfe. Total proved reserves for the Barnett Shale were 658 Bcfe at December 31, 2011, approximately 99%, or 654 Bcfe, of which was natural gas.

As of December 31, 2011, we were not operating any drilling rigs in the Barnett Shale and expect (i) to participate in drilling only one or two wells in the Barnett Shale through 2012 and (ii) to complete hydraulic fracturing of the 8.7 net wells remaining in our wells inventory of drilled but not yet completed. We currently expect our 2012 Barnett Shale drilling efforts to require an investment of approximately $15 million for drilling and completion costs.

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, 2011, we owned interests in 291,167 gross (109,782 net) acres in the Marcellus Shale, principally in Pennsylvania, West Virginia and New York. During 2011, we drilled 34 gross wells (10.5 net), of which we operated 31 gross wells (10.4 net), and completed and brought on production 5 gross wells (1.9 net). We commenced producing from our first operated Marcellus well in late October 2011 when the Laser pipeline was completed and brought on line. As of December 31, 2011, we had a backlog of 28 gross (8.6 net) wells in Northeastern Pennsylvania that were drilled and waiting on completion or pipeline connection, or both. Total proved reserves for the Marcellus Shale were 37 Bcfe at December 31, 2011, all of which was natural gas.

In 2012, we plan to spend approximately $62.0 million in the Marcellus Shale, all of which we expect to use for drilling, completion, seismic and other infrastructure development in Pennsylvania. These amounts do not include an estimated $18.6 million of our share of costs that will be carried by our Pennsylvania joint venture partner, Reliance Marcellus II, LLC. As a result of the material decline in natural gas prices, we and our joint venture partners are carefully reviewing our drilling program and have significantly reduced our planned spending in the Marcellus shale during 2012. We will continue to monitor prices and, consistent with our existing contractual commitments, may decrease our activity level and capital expenditures further, or may increase such activity, if natural gas prices so warrant. In New York, we are currently evaluating a portion of our prospective Marcellus Shale acreage for Trenton-Black River prospects. We currently have four rigs that we operate or under agreement to begin operating in the Marcellus Shale in the early part of 2012.

Effective as of August 2008, our wholly-owned subsidiary, Carrizo (Marcellus) LLC, entered into a joint venture with ACP II, an affiliate of Avista with which we also have a joint venture in the Utica Shale. See also “Crude Oil and Liquids Plays—Avista Utica Joint Venture” and 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 ACP II. 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 Marcellus joint venture 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 Marcellus joint venture properties.

Subject to specified exceptions (including the Reliance transactions described below), net cash flow from hydrocarbon production from the Marcellus joint venture properties and related sales proceeds, if such 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 Marcellus joint venture properties with our own until the cash flows and sale proceeds are allocated in accordance with the parties’ participating interests under this joint operating agreement. In addition to our share in the production and sale proceeds from the Marcellus joint venture properties, we were issued “B Units” in 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 ACP II provides consent rights only in limited, specified circumstances and generally does not entitle us to vote or participate in the management of ACP II, which is controlled by its members and affiliates. During 2011 and 2010, we received cash distributions of $3.3 million and $38.8 million, respectively, on our B Unit investment in ACP II as a result of ACP II’s distribution to Avista of proceeds from its sale of oil and gas properties to an affiliate of Reliance described below. We do not expect to receive any additional distributions on our B Unit investment in ACP II’s as a result of distributions to Avista in connection with its sale to an affiliate of Reliance, but we retain the right to receive distributions on account of future distributions from ACP II to Avista from its sale of oil and gas properties in New York and West Virginia in certain circumstances, although we retain the right to receive distributions on our B Unit investment in ACP II as a result of distributions to Avista associated with properties initially dedicated to the Avista Utica joint venture described above in “Crude Oil and Liquids Plays and Projects—Avista Utica Joint Venture.”

Each party’s ability to transfer its interest in the Marcellus joint venture properties to third parties is subject in most instances to preferential purchase rights for transfers of less than 10% of its interest in such 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 then-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 our Marcellus joint venture with Avista, and that the area of mutual interest of our Marcellus joint venture with Avista will generally not include Pennsylvania, in which those properties are located. Our Marcellus joint venture with Avista will otherwise continue and, as of December 31, 2011, included approximately 142,653 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 Marcellus joint venture with Avista was active.

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 Marcellus 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, 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 $327.0 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 included approximately 108,105 net acres in northern and central Pennsylvania as of December 31, 2011. 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 2013 or until the earlier full utilization of the up to $52.0 million development carry, subject to certain conditions and extensions. As of December 31, 2011, there was $30.7 million in development carry yet to be utilized.

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 Reliance development carry, 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 period through September 2014 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.

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 26 Bcfe, or less than 3% of our total proved reserves.

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:

We believe we have the following competitive strengths that will support our efforts to successfully execute our business strategy:

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 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 Niobrara, Marcellus Shale and 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 hydraulic fracturing 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 2011, we sold 20% of our interests in certain of our Eagle Ford Shale properties to GAIL who agreed to pay 50% of certain of our drilling and completion costs up to approximately $31.3 million, which we currently expect to fully utilize by the end of the first quarter of 2012. 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 $52.0 million, of which we also currently expect to utilize a substantial portion this year. 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 many of the future wells in these units to earn the 12.5% working interest. In certain instances we also seek to maximize the acreage that we can hold by drilling and producing 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 hydraulic fracturing, 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, or a limited number of horizontal wells, because they allow us to evaluate thermal maturity and rock property data, while also permitting us to test various hydraulic fracturing and completion techniques without incurring the cost of drilling a substantial number of horizontal wells. As discussed above, we have also shifted our focus toward crude oil and 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. 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 highly populated or environmentally sensitive areas, are dictated by available leases.

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 hydraulic fracturing and horizontal drilling technologies and the experience of our management in the development, processing and analysis of 3-D projects and data in the 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, 2011, we operated 349 gross (288.8 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 fracturing. During 2011, we operated all 30 of the gross wells drilled in the Eagle Ford Shale, 7 of the 8 gross wells drilled in the Niobrara, 19 of the 48 gross wells drilled in the Barnett Shale, and 31 of the 34 gross wells drilled in the Marcellus Shale.

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 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 hydraulic fracturing 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.”

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, 2011. The reserve data and the present value as of December 31, 2011 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, 2011, 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, 2011, 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 Note 2. Summary of Significant Accounting Policies and Note 14. Supplemental Disclosures About Oil and Gas Producing Activities (Unaudited) in the Notes to our Consolidated Financial Statements.

United States. At December 31, 2011 and 2010, we had 460.4 Bcfe and 401.6 Bcfe of proved undeveloped reserves, respectively. In 2011, we (a) added 209.6 Bcfe, which included 102.0 Bcfe, 80.8 Bcfe, and 26.3 Bcfe of proved undeveloped reserves as a result of drilling and additional offset locations in the Eagle Ford, Barnett, and Marcellus Shales, respectively, (b) converted a net of 39.8 Bcfe of reserves from proved undeveloped to proved developed, primarily in the Eagle Ford Shale and Barnett Shale, (c) sold 74.6 Bcfe of proved undeveloped reserves in the Barnett Shale and (d) removed 20.0 Bcfe of proved undeveloped reserves in the Barnett Shale due to a shift in future drilling priorities focusing more on crude oil and liquids-rich plays.

Costs incurred relating to the development of proved undeveloped reserves were approximately $57.0 million in 2011, as compared to $35.9 million in 2010. Costs incurred relating to the development of proved undeveloped reserves are currently projected to be approximately $461.6 million in 2012, $423.4 million in 2013, and $191.1 million in 2014. All proved undeveloped reserves drilling locations are scheduled to be drilled prior to the end of 2016.

U.K. North Sea. At December 31, 2011 and 2010, we had 18.7 Bcfe and 36.3 Bcfe of proved undeveloped reserves, respectively. In 2011, we converted 18.7 Bcfe of reserves from proved undeveloped to proved developed and added 1 Bcfe due to revisions for price.

Costs incurred relating to the development of proved undeveloped reserves were approximately $38.8 million in 2011, as compared to $5.4 in 2010. Costs incurred relating to the development of proved undeveloped reserves are currently projected to be approximately $25.4 million in 2012. All proved undeveloped reserves drilling locations are scheduled to be drilled prior to the end of 2012.

Reserve Matters. No estimates of proved reserves comparable to those included herein have been included in reports to any federal agency other than the Securities and Exchange Commission (“SEC”). 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 SEC 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, 2011, 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, 2011. 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 658 Bcfe, or 70% of our proved reserves (all of which were located in the Barnett Shale), for the year ended December 31, 2011. Ryder Scott Company Petroleum Engineers determined 261 Bcfe, or 28% of our proved reserves (everywhere other than the Barnett Shale and the Camp Hill Field), for the year ended December 31, 2011. Fairchild and Wells, Inc. determined 17 Bcfe, or 2% of our proved reserves (all of which were located in the Camp Hill Field), for the year ended December 31, 2011.

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.

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 our 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.

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 41% in 2011, 45% in 2010 and 45% in 2009. The reduction in the percentage of proved producing reserves in 2011, compared to 2010 and 2009, was largely attributable to the inclusion of proved non-producing reserves in the North Sea as a consequence of the Huntington Field development drilling and facility construction that occurred in 2011. We currently expect all of these reserves to be producing by year-end 2012. Set forth below is our reserve replacement ratio for the years ended December 31, 2011, 2010 and 2009. We have no reserves that are producing in the U.K. North Sea.

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.

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

Our finding and development costs for the years ended December 31, 2011, 2010 and 2009 are reflected in the table below.

For the three-year period ended December 31, 2011, our total cost for exploration, development and acquisition activities was approximately $1,046 million. Total exploration, development and acquisition activities for the three-year period ended December 31, 2011 have added approximately 547.8 Bcfe of net proved reserves at an all-sources finding cost of $1.91 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 $531.3 million, $379.0 million and $(12.3) million at December 31, 2011, 2010 and 2009, respectively, and includes

net additions to proved developed non-producing and proved undeveloped reserves of 86.5 Bcfe, 132.5 Bcfe and 38.6 Bcfe for the years ended December 31, 2011, 2010 and 2009, respectively. Accordingly, had we included future development costs in our computations, the average all-sources finding costs would have been $7.65 ($3.80 excluding divestitures), $2.44 and $1.16 per Mcfe for the years ended December 31, 2011, 2010 and 2009, respectively. Year on year, future development costs increased in 2011 by approximately $531.3 million net, largely comprised of (1) a $555.6 million increase in the Eagle Ford Shale for the development costs attributable to an 9.9 MMBOE ($56/BOE) increase in proved developed non-producing and proved undeveloped reserves, (2) a $1.6 million increase in the Niobrara for the development costs attributable to an 0.1 MMBOE ($16/BOE) increase in proved developed non-producing and proved undeveloped reserves, (3) a $30.2 million increase in the Marcellus future development costs attributable to a 25.3 Bcfe ($1.19/Mcfe) increase in proved developed non-producing and proved undeveloped reserves, and (4) a $22.0 million net decrease in the Barnett Shale future development costs comprised of (a) an approximate $70.4 million increase in future development costs associated with the net additions of 94.7 Bcfe ($0.74/Mcfe) to proved developed non-producing and proved undeveloped reserves, (b) a net $92.4 million reduction associated with a decrease of 92.3 Bcfe ($1.00/Mcfe) to proved developed non-producing and proved undeveloped wells, primarily from wells sold during the year or that are currently not in the drilling plan as we shift our drilling efforts to crude oil and liquids-rich plays.

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.

The following table sets forth our drilling activity for the years ended December 31, 2011, 2010 and 2009 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.

As of December 31, 2011, we are in the process of drilling 12 gross (6.8 net) wells in the United States. We are also in the process of drilling 1 gross (0.2 net) well in the U.K. These wells are not included in the table above.

The following table sets forth the number of productive oil and gas wells in which we owned an interest as of December 31, 2011.

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2011. 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.

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 15% of our acreage will expire in 2012, 34% will expire in 2013 and 8% will expire in 2014. Substantially all of any acreage allowed to expire in 2012 is expected to relate to non-core acreage where we have limited remaining amounts of unproved property costs.

Our production is marketed to third parties consistent with industry practices. Typically, our oil and gas is sold at the wellhead to unaffiliated third parties. 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 have made the strategic decision to sell as much of our natural gas production at the wellhead as possible, so that we can 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 sell the majority of our natural gas at the wellhead to Enterprise Products Operating LLC in the Barnett Shale and to DTE Energy in the Marcellus Shale. In each case we sell at competitive market prices based on a differential to several sales points. 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 Eagle Ford Shale, 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:

See “Item 1A. Risk Factors—Oil and gas prices are highly volatile, and lower oil and gas prices will negatively affect our financial results,” “—We are subject to various governmental regulations and environmental risks,” and “—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 procure and 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 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.”

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.

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.

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

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.

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 ( “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 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 $1.0 million per day for each violation.

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 December 2010, to implement the third 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 2.65 percent (PPI plus 2.65 percent) should be the oil pricing index for the five-year period beginning July 1, 2011. 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, or what the ultimate effect on our sales of oil, gas and other petroleum products will be.

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 and comparable state and local requirements. In 1990 Congress adopted amendments to the Clean Air Act 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 has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 23 counties in the Barnett Shale production area. 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 has issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. For more information, 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 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 $10.0 million in specified state waters to $35.0 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 $150.0 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 has considered legislation to subject hydraulic fracturing operations to federal regulation 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 foreign 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.

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 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. Based on these findings, the EPA adopted two sets of regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that requires a reduction in emissions of GHGs from motor vehicles and another that regulates GHG emissions from certain large stationary sources under the Clean Air Act Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The stationary source 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. The EPA also expanded its existing GHG emissions reporting rule to apply to the oil and gas source category, including oil and natural gas production facilities and natural gas processing, transmission, distribution and storage facilities, beginning in 2012 for emissions occurring in 2011. In addition, the U.S. Congress has considered 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 ongoing to develop an international scheme for the regulation and reduction of GHGs, such as the

United Nations Climate Change Conference in Durban, South Africa in 2011. 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.

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.

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 U.S. senior secured revolving credit facility, or 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.”

We sold oil and gas production to the following customer representing at least 10% of our oil and gas revenues as follows:

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.”

At December 31, 2011, we had 169 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.

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 our website, through a direct link to the SEC’s website at www.sec.gov, free of charge, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file such materials with, or furnish them to, the SEC. You may read and copy any materials we file with the SEC at the SEC’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 SEC 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:

We intend to satisfy the requirement under Item 5.05 of Form 8-K to disclose any amendments to our Code of Ethics and Business Conduct 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.”

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 multiple or power of ten.

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.

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 oil or natural gas, 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 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 an oil or natural gas 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 oil or natural gas in sufficient quantities to justify completion as an oil or natural gas 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 oil or natural gas in another reservoir.

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

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. 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 gas reserves which are capitalized by us pursuant to U.S. generally accepted accounting principles, or GAAP, 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.

Hydraulic fracturing. Hydraulic fracturing is the process of stimulation using a liquid (usually water with an amount of chemicals mixed in) 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. Hydraulic fracturing is an essential technology in shale reservoirs and other unconventional resource plays where nearly all wells are fractured in order to enable commercial hydrocarbon production.

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.

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 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 SEC 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 oil or gas in sufficient quantities to justify completion as an oil or gas well.

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.

PV-10 Value. When used with respect to oil and gas reserves, present value, or PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices calculated as the average oil and gas price during the preceding 12-month period prior to the end of the current reporting period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) and costs in effect at the determination date, without giving effect to non-property 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%.

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 gas property entitling the owner to a share of oil or 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.

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. More recently, further decreases in natural gas prices led us to suspend or curtail drilling and other exploration activities for natural gas in the Barnett Shale, and subsequent price declines to multi-year lows may extend the period for which such exploration activities are suspended or curtailed. 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:

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:

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.

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

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. In addition, our ability to produce oil and gas may be significantly affected by the availability and prices of hydraulic fracturing equipment and crews.

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, 2011, approximately 59% 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, 2011 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:

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, our Huntington 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 the credit agreement governing our revolving credit facility, the Huntington Facility, and the indentures governing our 4.375% convertible senior notes due 2028 (“Convertible Senior Notes”) and our 8.625% Senior Notes due 2018 (“Senior Notes”) may have adverse consequences on our operations and financial results, including:

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 oil and natural gas prices at economically sustainable levels. If the price that we receive for our oil and 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 credit agreement governing our revolving credit facility, we are subject to financial ratio covenants which include, but are not limited to, the maintenance of the following financial covenants: (i) a Total Debt to EBITDA (each as defined in the credit agreement governing the revolving credit facility) ratio of not more than (a) 4.75 to 1.00 for the fiscal quarter ending December 31, 2011 (b) 4.25 to 1.00 for fiscal quarters ending March 31, 2012 and June 30, 2012 and (c) 4.00 to 1.00 for fiscal quarters ending September 30, 2012 and thereafter; (ii) a current ratio of not less than 1.0 to 1.0; (iii) a Senior Debt (as defined in the credit agreement governing our revolving credit facility) to EBITDA ratio of not more than 2.50 to 1.00; and (iv) an EBITDA to Interest Expense (as defined in the credit agreement governing our revolving credit facility) ratio of not less than 2.50 to 1.00. Because the calculations of the financial ratios are made as of certain dates, the financial ratios can fluctuate significantly from period to period as the amounts

outstanding under our revolving credit facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings. 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 facility if a precipitous decline in oil or 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 2012. In addition, 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 facility 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 April 2012. 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 in recent 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, NASDAQ and our various debt arrangements.

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

We have limited exploration and development experience in the Niobrara Formation and in the Eagle Ford Shale. We have participated in the drilling of 11 horizontal gross (7.6 net) wells in the Niobrara Formation and have participated in 35 horizontal gross (28 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 Formation and the Eagle Ford Shale than we have in some other areas in which we operate.

We have limited experience drilling wells in the Marcellus Shale and less information regarding reserves and decline rates in the Marcellus Shale than in some 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 and development experience in the Marcellus Shale. As of December 31, 2011, we have participated or are participating in the drilling of 50 gross (14.1 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 some 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.

We have no experience drilling wells in the Utica Shale and less information regarding reserves and decline rates in this shale formation than in some other areas of our operations.

We have no exploration experience and no development experience in the Utica Shale. We have not participated in the drilling of any wells in this area. Other operators in this area 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 Utica Shale than we have in some other areas in which we operate.

If we are unable to acquire adequate supplies of water for our 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.

We use a substantial amount of water in our drilling operations. Our inability to locate sufficient amounts of water, or treat and dispose of water after drilling, could adversely impact our 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 effect 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 positions in the Eagle Ford Shale, the Niobrara Formation or the Utica Shale, this may detract from our efforts to realize our growth strategy in crude oil and liquids-rich plays. 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.

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 gas 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, 2011, approximately 70% of our proved reserves and approximately 79% 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 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 Texas Commission on Environmental Quality has finalized revisions to certain air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production and gathering sites for 23 counties in the Barnett Shale production area. The final rule established new emissions standards for a broad array of equipment at our drillsites, including engines. Additionally, on July 28, 2011, the EPA issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPS”) programs. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion techniques developed in the EPA’s Natural Gas STAR program along with the pit flaring of gas not sent to the gathering line. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed regulations under NESHAPS include maximum achievable control technology (“MACT”) standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. We are currently evaluating the effect these proposed rules could have on our business. Final action on the proposed rules is expected no later than April 3, 2012. 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 Formation. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas production. The U.S. Congress has considered legislation to subject hydraulic fracturing operations to federal regulation and to require the disclosure of chemicals used by us and others in the oil and gas industry in the hydraulic fracturing process. The EPA has recently asserted federal regulatory authority over hydraulic fracturing involving diesel under the federal Safe Drinking Water Act and is developing guidance documents related to this newly asserted regulatory authority. 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. The initial EPA study results are expected to be available in late 2012 with final results available in 2014. Further, the EPA announced on October 20, 2011 that it is launching a study of wastewater resulting from hydraulic fracturing activities and currently plans to propose pretreatment regulations by 2014. Moreover, on November 23, 2011, the EPA announced that it was granting in part a petition to initial rulemaking under the Toxic Substances Control Act, relating to chemical substances and mixtures used in oil and gas exploration and production. The Department of Energy, at the direction of the President, is also studying hydraulic fracturing in order to provide recommendations and identify best practices and other steps to enhance companies’ safety and environmental performance of hydraulic fracturing.

At the state level, the New York legislature has approved a temporary moratorium on drilling involving hydraulic fracturing and 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. Pennsylvania has adopted a variety of regulations since 2010 limiting how and where hydraulic fracturing can be performed in the state, including the adoption of upgraded well construction and casing standards, upgraded cement standards and new recordkeeping requirements. Some municipalities in the state have adopted or are considering adopting bans on drilling, including areas in which we operate, and the Governor of Pennsylvania has instituted a moratorium on leasing state forest land for new gas drilling. Further, in July 2011, the Pennsylvania Governor’s Marcellus Shale Advisory Commission released its report setting forth 96 recommendations on a variety of issues related to natural gas development in Pennsylvania. These recommendations are related to infrastructure; public health, safety, and environmental protection; local impact and emergency response; and economic and workforce development. The Marcellus Shale Advisory Commission made the most recommendations in the area of public health, safety and environmental protection, including doubling penalties authorized for violations of the Oil and Gas Act; increasing bonding requirements; authorizing a state agency to suspend, revoke, or deny permits on a quicker timeframe for violations or failure to correct violations; expanding a well operator’s presumed liability for impaired water quality; amending well stimulation and completion reporting requirements to require disclosure of hazardous chemicals used in fracturing; and other issues related to fracturing operations. Some or all of these recommendations have been incorporated into proposed legislation, will likely be acted upon and may result in the adoption of new laws and regulations governing shale gas development in the Marcellus Shale in Pennsylvania that could result in substantial changes in the way natural gas activities are conducted in the area.

At the international level, the U.K. and EU Parliaments have each in the past 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 2012 Fiscal Year Budget proposals, and certain legislation introduced in the U.S. Congress, if enacted into law, would 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. These 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 final rule to address permitting of GHG emissions from stationary sources. In addition, the U.S. Congress has considered 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. Business—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.

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 and a floating production storage and offloading vessel. Any significant change affecting these infrastructure facilities or vessel could materially harm our business. We deliver crude oil and natural gas through gathering systems and pipelines that we do not own. These facilities or vessel may be temporarily unavailable due to adverse weather conditions or operational issues 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 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 Avista and its affiliates, GAIL, 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:

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 a carry commitment by Reliance to pay 75% of certain of our future development costs up to approximately $52.0 million. 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, 2013, 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 extending through September 2014, 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 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:

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 oil and natural gas and/or receive market prices for our oil and 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 effects, 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.

Historically, we have generally delivered our oil and gas production through gathering systems and pipelines that we do not own under interruptible or short-term transportation agreements. Under the interruptible transportation agreements, the transportation of our oil and gas production 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 Eagle Ford Shale and the Marcellus Shale, we have entered into firm transportation agreements for a portion of our production in the Eagle Ford Shale and Marcellus Shale in order to assure our ability, and that of our purchasers, to successfully market the oil and gas that we produce. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be 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.

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 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:

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 earnings and our 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 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 net operating loss carryforwards that we have accumulated over the years.

Our ability to utilize U.S. net operating loss (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, 2011, 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 U.S. 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 U.S. NOL carryforwards as of December 31, 2011. Future equity transactions involving us or our 5% shareholders (including, potentially, relatively small transactions and transactions beyond our control) could cause further ownership changes and therefore a limitation on the annual utilization of our U.S. NOLs.

Enactment of proposed impact fees on natural gas wells could adversely impact our results of operations and the economic viability of exploiting natural gas drilling and production opportunities in Pennsylvania.

Legislation has been enacted in Pennsylvania, that authorizes counties to impose fees on certain natural gas wells in Pennsylvania. If a county elects to impose a fee, the fee will apply to any “unconventional gas well,” which is generally defined as a well using hydraulic fracture treatments or multilateral well bores. Any county that elects not to impose the fee can be overruled by the municipalities within that county. The fee would be imposed over a fifteen year period, starting with the year the well is actually drilled and declining thereafter, and is based on natural gas prices and the Consumer Price Index. Unconventional gas wells drilled before the fee is imposed would still be subject to the fee and, for purposes of calculating the amount of the fee, will be considered to have been drilled in the calendar year prior to the imposition of the fee. A substantial portion of our Marcellus Shale acreage and a portion of our Utica Shale acreage is located in the Commonwealth of Pennsylvania. To the extent such fees are ultimately enacted by counties in which we now or may in the future operate, or if Pennsylvania adopts severance taxes or additional fees, such actions could adversely impact our results of operations and the economic viability of exploiting natural gas drilling and production opportunities in Pennsylvania.

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 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:

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.

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, cyber 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, a cyber attack or electronic security breach, or an act of war.

Information regarding our properties is included in “Item 1. Business” above and in “Note 4. Property and Equipment, Net” of the notes to our consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data,” which information is incorporated herein by reference.

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 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.

The closing market price of our common stock on February 27, 2012 was $27.62 per share. As of February 27, 2012, there were an estimated 144 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 our Common Stock over the period from December 31, 2006 to December 31, 2011, 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, 2006 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 SEC. Shareholders are cautioned against drawing any conclusions from the data contained therein, as past results are not necessarily indicative of future financial performance.

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

As described in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources,” we have issued warrants and may issue common stock under a 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 (the “Securities Act”), for transactions not involving a public offering. Under the land agreement, we issued warrants to purchase 28,576 shares of common stock in 2011 and warrants to purchase 6,983 shares of common stock on January 4, 2012. 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.

During the second and third quarter of 2011, we contributed $1.0 million and $1.1 million (27,640 shares and 38,122 shares), respectively, in our common stock to the University of Texas at Arlington, where we are producing natural gas from a number of wells in the Barnett Shale play. The shares were issued pursuant to an exemption from registration under §4(2) of the Securities Act, for transactions not involving a public offering.

See Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for information regarding shares of common stock authorized for issuance under our equity compensation plans.

Our financial information set forth below for each of the five years in the period ended December 31, 2011, has been derived from our audited consolidated financial statements. This information should be read in conjunction with Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes included in Item 8. “Financial Statements and Supplementary Data”

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

In 2011, we recognized oil and gas revenues of $202.2 million, record production of 45.1 Bcfe and a record level of proved oil and gas reserves at December 31, 2011, of 935.6 Bcfe. The key drivers to our success in 2011 included the following:

Drilling program. Our success is largely dependent on the results of our drilling program. For the year ended December 31, 2011, we drilled 125 gross (54.4 net) wells with an apparent success rate of 99% that was comprised of: (a) 30 of 30 gross (23 net) wells in the Eagle Ford Shale, (b) 8 of 8 gross (4.7 net) wells in the Niobrara, (c) 33 of 34 gross (10.5 net) wells in the Marcellus Shale, (d) 48 of 48 gross (15.3 net) wells in the Barnett Shale, and (e) 5 of 5 gross (.5 net) wells in other project areas in the U.S. At December 31, 2011, 67 of these gross (24.9 net) wells were awaiting completion or pipeline connections.

Production and reserve growth. Our production for the year ended December 31, 2011 was a record 45.1 Bcfe, or 123.4 MMcfe/d, and reflects an increase of 22% from 2010 production of 36.8 Bcfe. The increase in production was primarily due to increased production from new wells, partially offset by normal production decline. As a result of our drilling program discussed above, our proved oil and gas reserves increased 11% to 935.6 Bcfe at December 31, 2011, as compared to 840.7 Bcfe at December 31, 2010 and replacing 311% of 2011’s record production.

Commodity prices. Our average gas price during 2011 was $2.98 per Mcf, $0.35 per Mcf less than the 2010 price of $3.33. Our average oil price in 2011 was $94.16 per Bbl, or $15.52 greater than the price of $78.64 in 2010. 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, which are beyond our control and have been and are expected to remain volatile.

Financial flexibility. During 2011, we took steps to continue to strengthen our financial flexibility and to provide funding to accelerate the development of our crude oil and liquids-rich plays in the Eagle Ford Shale and the Niobrara. In November 2011, we completed a private placement of an additional $200.0 million aggregate principal amount of our 8.625% Senior Notes due 2018 (“Senior Notes”) at a price to the public equal of 98.501% of the principal amount. The net proceeds of approximately $194.5 million (after deducting initial purchasers’ discounts and our expenses) were used to repay a substantial portion of the borrowings outstanding under our revolving credit facility.

While the market for natural gas remains challenging due to low spot and future prices, we are insulated from a portion of their effect by our hedging of 18,943,000 MMbtus of natural gas for 2012. We are rapidly growing our oil production, part of the effect of which will serve to further reduce our exposure to the weak natural gas market. The current market and outlook for oil and natural gas liquids sales is much more attractive and we are aggressively locking in these prices by increasing our hedge positions as our oil production grows. At December 31, 2011, we had hedges in place for 1,024,800 bbls of oil for 2012. 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 2012:

Control capital costs and maintain financial flexibility. Our Board of Directors has approved a U.S. capital expenditure plan for 2012 of $465.0 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 U.S. capital expenditure plan for 2012.

2012 capital expenditure plan. In 2012, we plan to focus on the drilling and development of our key oil and gas plays. Our 2012 U.S. capital expenditure plan has been set at $465.0 million, which includes $320.0 million in the Eagle Ford Shale, $62.0 million in the Marcellus Shale, $43.0 million for the Niobrara, $15.0 million for the Barnett Shale, and $25.0 million for other areas, all net of carry. Capital expenditures for the Huntington Field development project in the U.K. North Sea are $35.0 million, all of which is expected to be funded by our Huntington Facility. 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.

Revenues from oil and gas production for 2011 increased 46% to $202.2 million from $138.1 million in 2010. Production volumes for oil and gas in 2011 increased 22% to 45.1 Bcfe from 36.8 Bcfe in 2010. The increase in production for the year ended December 31, 2011 as compared to the year ended December 31, 2010 was primarily due to increased production from new wells, partially offset by normal production decline. Average oil prices increased 20% to $94.16 per barrel from $78.64 per barrel in 2010. Average natural gas prices decreased 11% to $2.98 per Mcf in 2011 from $3.33 per Mcf in 2010. Average natural gas liquids prices increased 31% to $8.40 per Mcf in 2011 from $6.43 per Mcf in 2010.

The following table summarizes production volumes, average sales prices and oil and gas revenues for the years ended December 31, 2011 and 2010:

Lease operating expenses for 2011 increased 20% to $28.3 million (or $0.63 per Mcfe) from $23.7 million (or $0.65 per Mcfe) in 2010. Lease operating expenses increased due to increased production. We continue to experience a decrease in the operating cost per Mcfe of our Barnett Shale production which was partially offset by increased operating cost per Mcfe associated with oil production.

Production taxes increased from $3.6 million in 2010 to $5.7 million in 2011 as a result of higher prices and increased production in 2011. The increase in production taxes is due to increased oil and gas production. Production taxes as a percentage of revenues increased from 2.6% to 2.8% due to increased oil production, which has a higher effective production tax rate as compared to natural gas production.

Ad valorem taxes decreased to $3.6 million ($0.08 per Mcfe) in 2011 from $3.7 million ($0.10 per Mcfe) in 2010 due to the sale of substantially all of our non-core area Barnett Shale properties in May 2011, partially offset by new oil and gas wells drilled in 2010.

Depreciation, depletion and amortization (“DD&A”) expense for 2011 increased to $84.6 million ($1.88 per Mcfe or $11.28 per BOE) from $47.0 million ($1.28 per Mcfe or $7.68 per BOE) in 2010. The increases in DD&A and the related per Mcfe/BOE amounts were primarily due to the increase in crude oil reserves in the Eagle Ford that were added in 2011 which have a higher finding cost per equivalent unit than our natural gas reserves.

General and administration (“G&A”) expense for 2011 increased to $41.8 million from $35.9 million in 2010. The increase was due primarily to (a) increased compensation costs related to an increase in personnel in 2011 as compared to 2010, (b) the expense associated with contributions to the University of Texas at Arlington (“UTA”), a university located within the area of our operations in the Barnett Shale, (c) increased office costs related to relocating our corporate headquarters in the fourth quarter of 2011 partially offset by (d) decreased stock-based compensation expense driven by a significant decrease in the fair value of CSARs due to a decrease in stock price during the second half of 2011, partially offset by higher stock-based compensation expense due to a higher number of stock-based compensation awards outstanding during 2011.

The net gain on derivatives was $47.0 million for the year ended December 31, 2011, comprised of (i) $11.5 million of unrealized gains on derivatives and (ii) $35.5 million of realized gains on derivatives. 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.

In January 2011, in connection with our entrance into the Revolving Credit Facility, we terminated our Prior Credit Facility. As a result, we recognized a non-cash, pre-tax loss on extinguishment of debt of $0.9 million representing the deferred financing costs attributable to the commitments of two banks in the Prior Credit Facility who did not participate in the Revolving Credit Facility. In November 2010, we completed a tender offer for $300.0 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 2011 were $52.8 million and $23.4 million, respectively, as compared to $43.3 million and $20.7 million in 2010, respectively. The increase was primarily due to interest on the $400.0 million aggregate principal amount of 8.625% Senior Notes issued in the fourth quarter of 2010 and the $200.0 million aggregate principal amount of the Senior Notes issued in the fourth quarter of 2011 partially offset by decreased interest attributable to the $300.0 million aggregate principal amount of our 4.375% Convertible Senior Notes purchased in the tender offer during the fourth quarter of 2010. This increase was partially offset by increased capitalized interest due to higher levels of unproved properties during 2011.

Our effective income tax rate was 33.2% for 2011 and 36.5% for 2010. The decrease in the effective income tax rate is primarily due to prior period adjustments related to our state and U.K. income tax provisions recorded during the fourth quarter of 2011 and the income tax benefit of a capital loss associated with our investment in Pinnacle Gas Resources, Inc., which was sold in the first quarter of 2011 for which no income tax benefit was recognized in prior years.

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 and NGL prices increased to $3.48 per Mcf in 2010 from $3.20 per Mcf 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:

Lease operating expenses for 2010 decreased 6% to $23.7 million (or $0.65 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.

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 our 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 ($140.6 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.

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 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 UTA, 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) $33.3 million of unrealized losses on derivatives and (ii) $74.9 million of realized gains on derivatives.

In November 2010, we completed a tender offer for $300.0 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 $400.0 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 our prior revolving credit facility, partially offset by decreased interest attributable to the $300.0 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.

2012 Capital Expenditure Plan and Funding Strategy. For 2012, our Board has approved a U.S. capital expenditure plan of $465.0 million which includes approximately $320.0 million for the Eagle Ford Shale, $62.0 million for the Marcellus Shale, $43.0 million for the Niobrara, $15.0 for the Barnett Shale, and $25.0 million for other areas, all net of carry. Capital expenditures for the Huntington Field development project in the U.K. North Sea are $35.0 million, all of which is expected to be funded by our Huntington Facility. We intend to finance the remainder of our 2012 U.S. 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, the acquisitions of leases with drilling commitments and other factors.

Sources and Uses of Cash. 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. 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, the acquisition of leases with drilling commitments and other factors. For the year ended December 31, 2011, capital expenditures, net of proceeds from asset sales, exceeded our net cash provided by operations. During 2011, we funded our capital expenditures with cash provided by operations, proceeds from the sale of assets, payments or carried interest relating to our joint ventures with Reliance and GAIL, offering of $200.0 million in aggregate principal of Senior Notes, and borrowings under our revolving credit facility, the Huntington Facility and our prior credit facility that was in place until January 27, 2011. Potential sources of future liquidity include the following:

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 2012 U.S. capital expenditure plan has been set at $465.0 million with the $35.0 million of capital expenditures for the Huntington Field development project in the U.K. North Sea, expected to be funded by our Huntington Facility. 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 $154.3 million, $94.4 million and $133.4 million for the years ended December 31, 2011, 2010, and 2009, respectively. The increase was primarily due to increased production, particularly higher crude oil and condensate production in the Eagle Ford Shale and increased oil prices, partially offset by lower gas prices in 2011 as compared to 2010. 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 used in investing activities were $286.0 million for the year ended December 31, 2011 and related primarily to capital expenditures, partially offset proceeds from the sale of our non-core area Barnett Shale properties to KKR, proceeds from the sale of an interest in certain of our Eagle Ford Shale properties to GAIL and cash distributions on our B Unit investment in ACP II of $3.3 million. 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. 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.

Net cash provided by financing activities for the year ended December 31, 2011 was $155.6 million and related primarily to net proceeds of $194.5 million from the issuance of an additional $200.0 million aggregate principal amount of Senior Notes in November 2011. The net proceeds were used to repay a substantial portion of the borrowings outstanding under the Senior Secured Revolving

Credit Facility. 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 issuances of common stock in April and December of 2010. Proceeds from the November 2010 issuance of $400.0 million aggregate principal amount of Senior Notes were offset by the purchase of $300.0 million of Convertible Senior Notes by tender offer and repayment of amounts outstanding under our 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.

Economic downturns may adversely affect our ability to access capital markets in the future. We currently believe that cash provided by operating activities, the sale of non-core assets and borrowings under our 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 February 27, 2012, we had hedged approximately 15,583,000 MMBtu (51,000 MMcf per day for the remainder of 2012) of our estimated March through December 2012 natural gas production at a weighted average floor or swap price of $5.37 per MMBtu relative to WAHA and Houston Ship Channel prices. Additionally, we had hedged approximately 1,468,800 Bbls (4,800 Bbls per day for the remainder of 2012) of our estimated March through December 2012 crude oil production at a weighted average floor or swap price of $86.15 per Bbl relative to NYMEX prices. We have $113.0 million and $24.6 million outstanding under our revolving credit facility and Huntington Facility, respectively, as of February 27, 2012. Our borrowing base under our revolving credit facility is currently $340.0 million. We have issued $0.4 million of letters of credit, which reduce the amounts available under our 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 credit agreement governing the revolving credit facility. We are scheduled for a borrowing base redetermination as of May 1, 2012, 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 our 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 2012 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 2012 capital expenditure plan, thereby adversely affecting the recoverability and ultimate value of our oil and gas properties.

The following table sets forth estimates of our contractual obligations as of December 31, 2011:

As of December 31, 2011 the Company had $600.0 million aggregate principal amount of 8.625% Senior Notes due 2018 (“Senior Notes”) issued and outstanding. The Senior Notes are guaranteed by certain of the Company’s domestic subsidiaries: Bandelier Pipeline Holding, LLC; Carrizo (Eagle Ford) LLC; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC, Carrizo Marcellus Holding, Inc.; Carrizo (Niobrara) LLC; CLLR, Inc.; Hondo Pipeline, Inc.; and Mescalero Pipeline, LLC.

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, if any, 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 indenture governing the Senior Notes 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 Senior Notes are subject to customary events of default, including those relating to failures to comply with the terms of the indenture governing the Senior Notes, 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 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 $300.0 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. As of December 31, 2011, $73.8 million aggregate principal amount of Convertible Senior Notes was outstanding.

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 our 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 our revolving credit facility. The Convertible Senior Notes are guaranteed by the same subsidiaries that guarantee the Senior Notes as described above.

We 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 us 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 $2.6 million, $11.6 million and $12.1 million for the years ended December 31, 2011, 2010 and 2009 respectively.

In January 2011, we entered into a new senior secured revolving credit facility. The new revolving credit facility replaced our prior credit facility. The new revolving credit facility permits us to borrow up to the lesser of (i) the borrowing base (as defined in the credit agreement governing our new revolving credit facility) and (ii) $750.0 million. The revolving credit facility matures on January 27, 2016. It is secured by substantially all of our assets (excluding our Carrizo UK assets described below under “—Huntington Field Development Project Credit Facility” and our Utica Shale assets) and is guaranteed by certain of our subsidiaries: Bandelier Pipeline Holding, LLC, Carrizo (Eagle Ford) LLC, Carrizo Marcellus Holding Inc., Carrizo (Marcellus) LLC, Carrizo (Marcellus) WV LLC, Carrizo (Niobrara) LLC, CLLR, Inc., Hondo Pipeline, Inc. and Mescalero Pipeline, LLC. Any subsidiary of ours that does not currently guarantee our obligations under our revolving credit facility that subsequently becomes a material domestic subsidiary (as defined under our revolving credit facility) will be required to guarantee our obligations under our revolving credit facility.

The current borrowing base under the revolving credit facility is $340.0 million. The borrowing base will be redetermined by the lenders at least semi-annually on each May 1 and November 1, with the next redetermination expected as of May 1, 2012. 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 credit agreement governing 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: (i) a Total Debt to EBITDA ( each as defined in the credit agreement governing the revolving credit facility) ratio of not more than (a) 4.75 to 1.00 for fiscal quarter ending December 31, 2011 (b) 4.25 to 1.00 for fiscal quarters ending March 31, 2012 and June 30, 2012 and (c) 4.00 to 1.00 for fiscal quarters ending September 30, 2012 and thereafter; (ii) a current ratio of not less than 1.0 to 1.0; (iii) a Senior Debt (as defined in the credit agreement governing our revolving credit facility) to EBITDA ratio of not more than 2.50 to 1.00; and (iv) an EBITDA to Interest Expense (as defined in the credit agreement governing our revolving credit facility) ratio of not less than 2.50 to 1.00. At December 31, 2011, the ratio of Total Debt to EBITDA was 3.99 to 1.00, the Current Ratio was 1.55 to 1.0, the Senior Debt to EBITDA ratio was 0.08 to 1.00 and the EBITDA to Interest Expense ratio was 4.35 to 1.00.

The revolving credit facility also places restrictions on us and certain of our 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 credit agreement governing our revolving credit facility). If an event of default occurs and is continuing, the Majority Lenders (as defined in the credit agreement governing 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).

At December 31, 2011, we had $47.0 million of borrowings outstanding under the revolving credit facility with a weighted average interest rate of 3.03%. At December 31, 2011, we also had $0.4 million in letters of credit outstanding which reduced the amounts available under the revolving credit facility. Future availability under the $340.0 million borrowing base is subject to the terms and covenants of the revolving credit facility. The revolving credit facility is used to fund ongoing working capital needs and the remainder of our capital expenditure plan only to the extent such amounts exceed the cash flow from operations, proceeds from the sale of oil and gas properties and securities offerings.

On January 28, 2011, we 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 us. 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 multicurrency credit facility consisting of (i) a term loan facility to be used to fund Carrizo UK’s share of project development costs, (ii) a contingent cost overrun term loan facility and (iii) 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 $55.0 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 development 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 development project. 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 were conditioned on, among other things, our having made an approximate $22.0 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. We are currently negotiating with the lenders of the Huntington Facility to modify the repayment schedule as we currently expect first production in the fourth quarter of 2012.

The Huntington Facility requires Carrizo UK to enter into certain hedging arrangements in order to hedge a specified portion of the Huntington Field development 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 us or our 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.

As of December 31, 2011, borrowings outstanding under the Huntington Facility were £11.5 million, with a weighted average interest rate of 4.51% and no letters of credit had been issued. The British Pound denominated borrowings were translated to $17.8 million at December 31, 2011, resulting in an immaterial transaction gain recorded in Other income, net in the consolidated statements of operations.

In November 2011, we issued $200.0 million aggregate principal amount of Senior Notes in a private placement exempt from the registration requirements of the Securities Act. We used the net proceeds of approximately $194.5 million after deducting initial purchasers’ discounts and our estimated expenses, to repay a substantial portion of the borrowings then outstanding under our revolving credit facility. In February 2012, we completed an exchange offer and issued new notes and guarantees having substantially identical terms, but registered with the SEC, in exchange for all such privately issued Senior Notes. The $200.0 million of Senior Notes issued in November 2011 have substantially identical terms as, and are treated as a single series with, the $400.0 million of Senior Notes described in the following paragraph. Holders of all $600.0 million aggregate principal amount of Senior Notes will vote as one series under the indenture governing the Senior Notes.

In November 2010, we issued $400.0 million aggregate principal amount of Senior Notes in a private placement exempt from the registration requirements of the Securities Act. 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 our prior credit facility and held the remaining net proceeds in short-term investments. We subsequently purchased the $300.0 million of Convertible Senior Notes in the tender offer with a combination of cash on hand and borrowings under our prior credit facility. In June 2011, we completed an exchange offer and issued new notes and guarantees having substantially identical terms, but registered with the SEC, in exchange for all such privately issued Senior Notes.

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 our 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 then-outstanding borrowings under our prior credit facility.

From time to time, we have entered into lease purchase option arrangements with third parties. In the first half of 2011, we utilized one lease purchase option arrangement described below with an unrelated third party. Strategically, such 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. The Land Agreement expired by its terms on May 31, 2011. Under this arrangement, we were permitted to acquire up to $20.0 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 purchased a lease group under the Land Agreement, if any, we would 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 had 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 paid 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). Our option to purchase leases under this arrangement has expired.

Under the Land Agreement, we issued warrants to purchase 57,461 shares of common stock in 2010, warrants to purchase 28,576 shares of common stock in 2011 and warrants to purchase 6,983 shares of common stock in January 2012.

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

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 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.

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

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 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 $9.6 million, $5.3 million and $5.6 million for the years ended December 31, 2011, 2010, and 2009, 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 $1.85, $1.25 and $1.55 for the years ended December 31, 2011, 2010 and 2009, respectively.

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 $23.4 million, $20.7 million and $19.7 million for the years ended December 31, 2011, 2010 and 2009, 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, 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 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 $108.0 million and a ten percent decrease in average market prices would have decreased the cost center ceiling by approximately $172.0 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.

The cost center ceiling exceeded our net capitalized costs for the U.S. cost center at December 31, 2011 by approximately $202.6 million and was based on crude oil and condensate prices of $92.76 per barrel, natural gas liquids prices of $44.90 per barrel and natural gas prices of $3.21 per Mcf (or a volume weighted average price of $5.38 per Mcfe), representing the unweighted average market prices on the first calendar day of each month during the 12-month period ended December 31, 2011. A ten percent increase in average market prices at December 31, 2011 would have increased the cost center ceiling by approximately $163.4 million and a ten percent decrease in average market prices would have caused an impairment of approximately $24.4 million. This sensitivity analysis is as of December 31, 2011 and, accordingly, does not consider drilling results, production and prices subsequent to December 31, 2011 that may require revisions of proved reserve estimates.

The cost center ceiling exceeded our net capitalized costs for the U.K. cost center at December 31, 2011 by approximately $124.5 million and was based on crude oil and condensate prices of $106.90 per barrel and natural gas prices of $7.54 per Mcf (or a volume weighted average price of $16.49 per Mcfe), representing the unweighted average market prices on the first calendar day of each month during the 12-month period ended December 31, 2011. A ten percent increase in average market prices at December 31, 2011 would have increased the cost center ceiling by approximately $19.0 million and a ten percent decrease in average market prices would have decreased the cost center ceiling by approximately $19.0 million. This sensitivity analysis is as of December 31, 2011 and, accordingly, does not consider drilling results, production and prices subsequent to December 31, 2011 that may require revisions of proved reserve estimates.

We have a significant amount of proved undeveloped reserves. We had 479.2 Bcfe, 437.8 Bcfe and 267.8 Bcfe of proved undeveloped reserves, representing 51%, 52% and 44% of our total proved reserves at December 31, 2011, 2010 and 2009, respectively. Approximately 285.9 Bcfe, or 60%, and 144.1 Bcfe, or 30%, of our proved undeveloped reserves at December 31, 2011, 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.

The proved oil and gas reserve estimates as of December 31, 2011 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, 2011, would have decreased or increased our DD&A expense by approximately 9.0% or 10.9%, respectively, for the fourth quarter of 2011.

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 and subject to master netting agreements.

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.

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.

Liabilities are recognized for contingencies when (i) it is both probable that an asset has been impaired or that a liability has been incurred and (ii) that the amount of such loss is reasonably estimable.

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, 2011 was a net asset of $37.3 million, 68% with Credit Suisse, 19% BNP Paribas, 6% with Shell Energy North America (US) LP, 5% with Credit Agricole, and the remaining 2% with Societe Generale. 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. Because Credit Suisse, BNP Paribas, Credit Agricole, and Societe Generale are lenders in our revolving credit facility, we are not required to post collateral with respect to derivatives instrument in a net liability position with these counterparties as the contracts 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, 2011.

In connection with the derivative instruments above, we have entered into protective put spreads. In 2012, at market prices below the short put price of $4.77, the floor price becomes the market price plus the put spread of $1.28 on 7,572,000 of the 18,943,000 MMBtus and the remaining 11,370,600 MMBtus have a floor price of $5.43.

In addition to the table above, we sold call positions of 3,650,000 MMBtus at a price of $5.50 per MMBtu for 2014.

The following sets forth a summary of our U.S. crude oil derivative positions at average NYMEX prices as of December 31, 2011.

For the years ended 2011, 2010 and 2009, we recorded the following gains and losses related to our oil and gas derivative instruments:

We deferred the payment of premiums associated with certain of our derivative instruments totaling a net liability of $1.2 million and $3.9 million at December 31, 2011 and December 31, 2010, respectively. We classified $0.4 million and $3.9 million as other current liabilities at December 31, 2011 and December 31, 2010, respectively, and $0.8 million as other non-current liabilities at December 31, 2011. There were no other non-current liabilities at December 31, 2010. These deferred premiums will be paid to the counterparty with each monthly settlement (April 2012 – March 2014) and recognized as a reduction of realized gain (loss) on derivative instruments, net.

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 $19.2 million impact on our revenues for the year ended December 31, 2011.

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. 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 $47.0 million, $47.8 million and $41.5 million for the years ended December 31, 2011, 2010, and 2009, 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 our prior credit facility approximate the carrying amounts as of December 31, 2011, and were based upon interest rates currently available to us for borrowings with similar terms. The fair values of the Convertible Senior Notes and Senior Notes at December 31, 2011 were estimated at approximately $73.0 million and $606.0 million, respectively and were based on quoted market prices. As of December 31, 2011, scheduled maturities of long-term debt are $73.8 million in 2013 and $600.0 million in 2018.

The financial statements and information required by this Item appears on pages F-1 through F-44 of this Annual Report on Form 10-K.

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosures

(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 “SEC”) 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 SEC’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 Rules 13a-15(b) and 15d-15(b) under the Exchange Act, 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 Rules 13a-15(e) and 15d-15(e) under the Exchange Act) 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 SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the SEC’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 Annual Report on 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:

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, 2011. 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, 2011.

KPMG LLP, our independent registered public accounting firm that audited our consolidated financial statements, has also issued its own attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2011, 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, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

The information required by this item is incorporated herein by reference to our definitive Proxy Statement (the “2012 Proxy Statement”) for our 2012 annual meeting of shareholders. The 2012 Proxy Statement will be filed with the SEC not later than 120 days subsequent to December 31, 2011.

The information required by this item is incorporated herein by reference to the 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters

The information required by this item is incorporated herein by reference to the 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated herein by reference to the 2012 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2011.

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

We have audited the accompanying consolidated balance sheets of Carrizo Oil & Gas, Inc. and subsidiaries as of December 31, 2011 and 2010, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2011. 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, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, 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, 2011, 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 February 29, 2012 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

We have audited Carrizo Oil & Gas Inc.’s internal control over financial reporting as of December 31, 2011, 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, 2011, 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, 2011 and 2010, and the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2011, and our report dated February 29, 2012 expressed an unqualified opinion on those consolidated financial statements.

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

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 Eagle Ford Shale in South Texas, the Niobrara Formation in Colorado, the Barnett Shale in North Texas, the Marcellus Shale in Pennsylvania, New York and West Virginia, the Utica Shale in Ohio and Pennsylvania, and the U.K. North Sea where our Huntington Field development project is currently under development.

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 (“GAAP”). 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.

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, total shareholders’ equity, net income (loss), comprehensive income (loss) or net cash provided by or used in operating, investing or financing activities.

The preparation of financial statements in conformity with GAAP 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.

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 average 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 creditworthiness 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.

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

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):

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.

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

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 associated with acquisition, exploration and development activities are capitalized and totaled $9.6 million, $5.3 million, and $5.6 million for the years ended December 31, 2011, 2010, and 2009, respectively. Costs related to production, general corporate overhead and 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 then applying such amount 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. Averagedepreciation, depletion and amortization (“DD&A”) per Mcfe on oil and gas properties was $1.85, $1.25, and $1.55 for the years ended December 31, 2011, 2010 and 2009, 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. 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 term of the properties. The Company capitalized interest costs associated with its unevaluated leasehold and seismic costs of $23.4 million, $20.7 million, and $19.7 million for the years ended December 31, 2011, 2010 and 2009, respectively. Interest is capitalized on the average balance of unproved properties 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, 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.

Capitalized costs, less accumulated amortization and related deferred income taxes, are limited to the “cost center ceiling” equal to (i) 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 (ii) 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.

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 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 recognized using the straight-line method based on estimated useful lives ranging from five to ten years.

Deferred financing costs were $23.2 million (net of $3.2 million of accumulated amortization) and $14.7 million (net of $6.3 million of accumulated amortization) as of December 31, 2011 and 2010, 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 Company’s 8.625% Senior Notes due 2018, May 2013 for the Company’s 4.375% Convertible Senior Notes due 2028, January 2016 for the Revolving Credit Facility and December 2014 for the Huntington Facility. See Note 6. Debt.

Prior to the sale of its investment in Pinnacle Gas Resources, Inc. (“Pinnacle”) in January 2011 (see Note 3. Investments), the Company accounted for its investment in Pinnacle as available-for-sale and adjusted the book value to fair value through other comprehensive income (loss), net of income taxes. This fair value was assessed quarterly for other than temporary impairment based on publicly available information. If the impairment was deemed other than temporary, it was recognized in earnings. Subsequent recoveries in fair value were reflected as increases to investments and other comprehensive income (loss), net of income taxes.

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

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 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 carrying amount of long-term debt under the Prior Credit Facility, the Revolving Credit Facility and the Huntington Facility approximate fair value as these borrowings bear interest at variable rates of interest. The carrying amounts of the Senior Notes and the Convertible Senior Notes may not approximate fair value because the notes bear interest at fixed rates of interest. See Note 6. Debt and Note 12. Fair Value Measurements.

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 the obligation to determine whether a change in the estimated obligation is necessary. On an interim basis, the Company reassesses the estimated cash flows underlying the obligation when indicators suggest the estimated cash flows underlying the obligation have materially changed.

Liabilities are recognized for contingencies when (i) it is both probable that an asset has been impaired or that a liability has been incurred and (ii) the amount of such loss is reasonably estimable.

Oil and gas revenues are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability 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, 2011 and 2010, the Company did not have any material production imbalances.

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 balance sheet date 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 a portion of its forecasted 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 and subject to master netting agreements.

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.

The Company grants stock options, stock appreciation rights (“SARs”) that may be settled in cash or common stock at the option of the Company (“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 expense for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:

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. Subsequent to vesting, the liability for any SARs that the Company expects to settle in cash is remeasured in earnings at each reporting period based fair value until the awards are settled. 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 between four and 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:

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 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.

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 denominated in a currency other than the functional currency are recorded as other income, net in the consolidated statements of operations.

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 by taxing jurisdiction. 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.

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 awards and units, stock options, Stock SARs expected to be settled in common stock, warrants and convertible debt. The Company excluded 4,202 and 23,668 shares related to restricted stock awards and units, and stock options from the calculation of dilutive shares for the years ended December 31, 2011 and 2010, respectively, 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 shares related to stock options from the calculation of dilutive shares for the year ended December 31, 2009 due to the net loss reported in that period. 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, 2011, 2010 or 2009 because the conversion price was in excess of the market price of the common stock for those periods.

The consolidated statement of cash flows for the year ended December 31, 2009 does 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 of $0.1 million, net of income taxes.

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 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.

In May 2008, the Company entered into a strategic alliance agreement with 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.

In 2003, the Company contributed its interests in certain oil and gas leases in Wyoming and Montana in areas prospective for coalbed methane to a newly formed entity, 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, the Company received $0.9 million, or $0.34 per share, for its 2,555,825 shares of Pinnacle common stock during the second quarter of 2011.

At December 31, 2011 and 2010, property and equipment, net consisted of the following:

Costs not subject to amortization totaling $394.4 million at December 31, 2011 were incurred in the following periods: $204.4 million in 2011, $113.9 million in 2010, $25.0 million in 2009 and $51.1 million in 2008 and prior years.

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 U.S. 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) and at December 31, 2009, resulting in an impairment of $122.5 million ($78.1 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/or 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.

In May 2011, the Company sold a substantial portion of its non-core area Barnett Shale properties to KKR Natural Resources (“KKR”), a partnership formed between an affiliate of Kohlberg Kravis Roberts & Co. L.P. and Premier Natural Resources. Net proceeds received from the sale were approximately $98.0 million, which represent an agreed upon purchase price of approximately $104.0 million less net purchase price adjustments. Purchase price adjustments primarily relate to proceeds received by the Company for sales of hydrocarbons from such properties between the effective date of January 1, 2011 and the closing date of May 17, 2011. The proceeds from such sale were recognized as a reduction of proved oil and gas properties, net.

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 and the second quarter of 2011, ACP II declared and paid cash distributions to affiliates of Avista. Because these distributions exceeded Avista’sinternal rates-of-return and return-on-investment thresholds, the Company received cash distributions of approximately $38.8 million during the third and fourth quarters of 2010 and $3.3 million in the second quarter of 2011on its B Units, which were recognized as reductions of capitalized oil and gas property costs.

In June 2011, in accordance with the title and post-closing adjustment provisions of the purchase and sale agreements of the sale described above, the Company provided additional interests in oil and gas properties in parts of Pennsylvania in the Marcellus Shale to Reliance in substitution of properties included in the sale that were affected by certain alleged title defects. In exchange for such substitute properties, the Company received $0.3 million in cash from Reliance relating to the sale of 20% of its interest.

On September 28, 2011, the Company completed the sale of 20% of its interests in oil and gas properties in parts of the Eagle Ford Shale to GAIL GLOBAL (USA) INC. (“GAIL”), a wholly-owned subsidiary of GAIL (India) Limited, effective September 1, 2011. Under the purchase and participation agreement for this transaction, the Company received $63.7 million in cash which was recognized as a reduction of proved oil and gas properties. As part of the consideration for the purchase, GAIL committed to pay a “development carry” of 50% of certain of the Company’s future development costs up to approximately $31.3 million, as further described below. The Eagle Ford Shale assets to be conveyed to GAIL under the terms of the agreement include approximately 4,040 net acres located primarily in LaSalle County, Texas and a 20% interest in eight completed horizontal wells. The agreement also provides for an ongoing joint venture between the Company and GAIL with respect to the interests being purchased by GAIL. The development carry obligation extends until June 30, 2013 or until the earlier full utilization of the approximately $31.3 million development carry, subject to certain conditions and extensions. The Company will continue to operate the joint venture properties that it currently operates, and currently expects the approximately $31.3 million development carry to be exhausted in the first quarter of 2012. The joint venture provides for an area of mutual interest including the purchased interests and specified areas adjacent to such interests. GAIL will have the right to purchase certain interests acquired by the Company in the area of mutual interest at a specified premium to the price paid by the Company.

The Company’s income tax (expense) benefit differs from the income tax (expense) benefit computed by applying the U.S. federal statutory corporate income tax rate of 35% to income (loss) before income taxes as follows:

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. At December 31, 2011 and 2010, deferred tax assets and liabilities are comprised of the following:

Deferred income tax assets and liabilities are classified as current or long term consistent with the classification of the related temporary difference, separately by tax jurisdiction. At December 31, 2011 and 2010, the net deferred income tax asset is classified as follows:

As of December 31, 2011, the Company had U.S. income tax net operating loss (“NOL”) carryforwards of approximately $147.5 million which expire between 2019 and 2031 if not utilized in earlier periods. The realization of the deferred tax assets related to the U.S. NOL carryforwards is dependent on the Company’s ability to generate sufficient future taxable income in the U.S. within the applicable carryforward periods. As of December 31, 2011, the Company determined it was more likely than not that some of its state NOL carryforwards would not be realized and accordingly, established a valuation allowance totaling $0.7 million. The Company believes it will be able to generate sufficient future taxable income in the U.S. within the carryforward periods. As such, the Company believes that it is more likely than not that its net deferred income tax assets will be fully realized.

The ability of the Company to utilize its U.S. 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 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, 2011, 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 U.S. NOL as of December 31, 2011. 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 the U.S. NOL carryforwards.

The Company receives a tax deduction during the period stock options are exercised, generally for the excess of the exercise date stock price over the exercise price of the option. The Company also receives a tax deduction during the period restricted stock awards and units vest, generally equal to the fair value on the date that the awards or units vest. Because these stock-based compensation tax deductions did not reduce current taxes payable as a result of U.S. NOL carryforwards, the benefit of these tax deductions has not been reflected in the U.S. NOL carryforward deferred tax asset. Stock-based compensation deductions included in the U.S. NOL carryforwards of $147.5 million but not reflected in deferred tax assets were $29.2 million at December 31, 2011. The Company plans to recognize the $10.2 million deferred tax asset associated with these stock-based compensation tax deductions when all other components of the U.S. NOL carryforward deferred tax asset have been fully utilized. If and when the stock-based compensation deduction related U.S. NOL carryforward deferred tax asset is realized, the tax benefit of reducing current taxes payable will be credited directly to additional paid-in capital.

At December 31, 2011, 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.

On November 2, 2010, the Company issued $400.0 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 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 $300.0 million of the Convertible Senior Notes as described below.

On November 17, 2011, the Company issued an additional $200.0 million aggregate principal amount of 8.625% Senior Notes due 2018 at a price to the initial purchasers of 98.501% of the principal amount in a private placement. The net proceeds of $194.5 million (after deducting the initial purchasers’ discount and the Company’s expenses) were used to repay a substantial portion of the borrowings outstanding under the Revolving Credit Facility (defined below). These notes were issued as “additional notes” under the

indenture governing the Senior Notes and pursuant to which the Company had previously issued $400.0 million aggregate principal amount of Senior Notes in November 2010, and under the indenture are treated as a single series with substantially identical terms as the Senior Notes previously issued in November 2010. The Senior Notes are guaranteed by certain of the Company’s subsidiaries: Bandelier Pipeline Holding, LLC; CLLR, Inc.; Carrizo (Eagle Ford) LLC; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC; Carrizo Marcellus Holding, Inc.; Carrizo (Niobrara) LLC; Hondo Pipeline, Inc.; and Mescalero Pipeline, LLC.

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

In June 2011 and February 2012, the Company completed the exchange of registered 8.625% Senior Notes due 2018 for any and all of its unregistered $400.0 million and $200.0 million aggregate principal amount of 8.625% Senior Notes due 2018, respectively.

In November 2010, the Company completed a tender offer for $300.0 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 $300.0 million aggregate principal amount of Convertible Senior Notes, $73.8 million aggregate principal amount of Convertible Senior Notes was outstanding as of December 31, 2011 and December 31, 2010.

The Convertible Senior Notes are subject to customary non-financial covenants and events of default, including certain cross defaults of other indebtedness and mortgages, 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, 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 governing the Convertible Senior Notes as a result of the issuance of the 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 remaining 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 $2.6 million, $11.6 million and $12.1 million for the years ended December 31, 2011, 2010 and 2009, respectively.

On January 27, 2011, the Company entered into a new $750.0 million senior 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. The Revolving Credit Facility permits the Company to borrow up to the lesser of (i) the borrowing base (as defined in the senior credit agreement governing the Revolving Credit Facility) and (ii) $750.0 million. The Revolving Credit Facility matures on January 27, 2016. It is secured by substantially all of the Company’s assets (excluding the Company’s Carrizo U.K. assets as described below under “U.K Huntington Field Development Project Credit Facility” and the Company’s Utica Shale assets) and is guaranteed by certain of the Company’s domestic subsidiaries: Bandelier Pipeline Holding, LLC, Carrizo (Eagle Ford) LLC, Carrizo Marcellus Holding Inc., Carrizo (Marcellus) LLC, Carrizo (Marcellus) WV LLC, Carrizo (Niobrara) LLC, CLLR, Inc., Hondo Pipeline, Inc. and Mescalero Pipeline, LLC. Any subsidiary of the Company that does not currently guarantee the Company’s obligation under the Revolving Credit Facility that subsequently becomes a material domestic subsidiary (as defined under the credit agreement governing the Revolving Credit Facility) will be required to guarantee the Company’s obligations under the Revolving Credit Facility.

The initial borrowing base under the Revolving Credit Facility was $350.0 million and the current borrowing base is $340.0 million. The borrowing base will be redetermined by the lenders at least semi-annually on each May 1 and November 1, with the next redetermination expected as of May 1, 2012. 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 credit agreement governing the Revolving Credit Facility. Subsequent to the sale of the Company’s non-core area

Barnett Shale properties in the second quarter of 2011 described in Note 4. Property and Equipment, net, the borrowing base availability under the Revolving Credit Facility was reduced from $350.0 million to $300.0 million. On June 10, 2011, the borrowing base availability was raised to $340.0 million after completing the regular semi-annual borrowing base redetermination. The borrowing base availability remained at $340.0 million after completing the regular semi-annual borrowing base redetermination on December 5, 2011.

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: (i) a Total Debt to EBITDA (each as defined in the credit agreement governing the Revolving Credit Facility) ratio of not more than (a) 4.75. to 1.00 for fiscal quarter ending December 31, 2011, (b) 4.25 to 1.00 for fiscal quarters ending March 31, 2012 through June 30, 2012 and (c) 4.00 to 1.00 for fiscal quarters ending September 30, 2012 and thereafter; (ii) a current ratio of not less than 1.0 to 1.0; (iii) a Senior Debt (as defined in the credit agreement governing the Revolving Credit Facility) to EBITDA ratio of not more than 2.50 to 1.00; and (iv) an EBITDA to Interest Expense (as defined in the credit agreement governing the Revolving Credit Facility) ratio of not less than 2.50 to 1.00. At December 31, 2011, the Total Debt to EBITDA ratio was 3.99 to 1.00, the current ratio was 1.55 to 1.0, the Senior Debt to EBITDA ratio was 0.08 to 1.00 and the EBITDA to Interest Expense ratio was 4.35 to 1.00. Because the calculation of the financial ratios are made as of a certain date, the financial ratios can fluctuate significantly period to period as the amounts outstanding under the Revolving Credit Facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings.

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.

The Revolving Credit Facility is subject to customary events of default, including a change in control (as defined in the credit agreement governing the Revolving Credit Facility). If an event of default occurs and is continuing, the Majority Lenders (as defined in the credit agreement governing 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, the Company borrowed $112.0 million under the Revolving Credit Facility, which was used to repay in full indebtedness outstanding under the Prior Credit Facility (as defined and described below), to pay transaction costs associated with the entrance into the Revolving Credit Facility and for other general corporate purposes.

At December 31, 2011, the Company had $47.0 million of borrowings outstanding under the Revolving Credit Facility with a weighted average interest rate of 3.03%. At December 31, 2011, the Company also had $0.4 million in letters of credit outstanding which reduced the amounts available under the Revolving Credit Facility. The Revolving Credit Facility is generally used to fund ongoing working capital needs and the remainder of the Company’s capital expenditure plan to the extent such amounts exceed the cash flow from operations, proceeds from the sale of oil and gas properties and securities offerings.

Prior to January 27, 2011, the Company had a senior secured revolving credit facility (the “Prior Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent. In connection with the Company’s entrance into the Revolving Credit Facility as discussed above, on January 27, 2011, the Company repaid its full indebtedness outstanding under the senior credit agreement governing the Prior Credit Facility and terminated such senior credit agreement. As a result, the Company recognized a $0.9 million non-cash pre-tax loss on extinguishment of debt, related to the deferred financing costs attributable to the commitments of two banks in the Prior Credit Facility who are not participating in the new credit facility.

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 multicurrency credit facility consisting of (i) a term loan facility to be used to fund Carrizo UK’s share of project development costs, (ii) a contingent cost overrun term loan facility and (iii) 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 $55.0 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 development 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 development project. Based on the redetermination and recalculation, which occurred in the third quarter 2011, availability of the term loan facility and cost overrun facility is currently $55.0 million and $6.5 million, respectively. 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 were conditioned on, among other things, the Company’s having made and spent an approximately $22.0 million equity contribution to Carrizo UK, which was completed in February 2011. 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 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 is 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 Huntington Facility requires Carrizo UK to enter into certain hedging arrangements in order to hedge a specified portion of the Huntington Field development 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 following table sets forth asset retirement obligations for the years ended December 31, 2011 and 2010:

The asset retirement obligations incurred for the year ended December 31, 2011 were primarily related to activity in the U.K. North Sea, Eagle Ford Shale, and Marcellus Shale. The revisions of previous estimates for the year ended December 31, 2011 related primarily to increases in estimates of abandonment costs of wells in the Marcellus Shale, Barnett Shale, and Gulf Coast region. 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 region.

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

The results of 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.

Rent expense included in general and administrative expense for the years ended December 31, 2011, 2010 and 2009 was $1.7 million, $1.0 million, and $0.9 million, respectively, and includes rent expense primarily for the Company’s corporate office and field offices.

At December 31, 2011, total minimum commitments from long-term non-cancelable operating leases, drilling rig, seismic and pipeline volume commitments are as follows:

Common Stock. During the second and third quarters of 2011, the Company contributed $1.0 million and $1.1 million, respectively, in common stock of the Company to the University of Texas at Arlington, a university located within the area of our operations in the Barnett Shale. These contributions are included in general and administrative expense in the consolidated statements of operations.

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.

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.

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. The Land Agreement expired by its terms on May 31, 2011. Under this arrangement, the Company was able to acquire up to $20.0 million of oil, gas and mineral interests/leases in certain specified areas in the Barnett Shale from such 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 purchased a lease group under the Land Agreement the Company would issue to the third party’s affiliate warrants to purchase shares of the Company’s common stock 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 agreed to issue additional warrants. The warrants are subject to antidilution adjustments and may be exercised on a “cashless” basis.

Under the Land Agreement, the Company issued warrants to purchase 57,641 shares of common stock in 2010. During 2011 and January 2012, the Company issued additional warrants to purchase 28,576 and 6,983 shares, respectively of the Company’s common stock to the third party’s affiliate for leases acquired prior to the expiration of the Land Agreement.

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 at the option of the Company (“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, 2011, has issued stock options, restricted stock awards and restricted stock units covering 4,241,346 shares through December 31, 2011, net of forfeitures and excluding Stock SARs the Company has elected or expects 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, 2011, 2010 and 2009:

During 2009, the Company granted 211,683 Stock SARs which the Company then 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:

No stock options or Stock SARs were granted during 2010 or 2011. The Stock SARs contain performance and service conditions. The performance conditions have been met for all awards.

At December 31, 2011, the liability for Stock SARs to be settled in cash was $2.9 million, all of which are vested or are expected to vest within the next 12 months. As of December 31, 2011, unrecognized compensation costs related to unvested Stock SARs to be settled in cash was $0.1 million and will be recognized as stock-based compensation expense over a weighted-average period of 0.41 years.

At December 31, 2011, 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 exercise price) of stock options exercised during the years ended December 31, 2011, 2010 and 2009 was $3.6 million, $6.0 million, and $0.1 million, respectively, and the Company received $47,000, $0.7 million, and $9,000 in cash in connection with stock option exercises for the years ended December 31, 2011, 2010 and 2009, respectively.

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, which may be settled in cash or common stock at the Company’s option, do not have the right to vote and 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, 2011, 2010 and 2009:

As of December 31, 2011, unrecognized compensation costs related to unvested restricted stock awards and units was $14.4 million and will be recognized as stock-based compensation expense over a weighted-average period of two years. The 2009, 2010 and 2011 grants of certain restricted stock units contained performance and service conditions. The performance conditions have been met for all awards.

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 2011 and 2010, the Company issued 153,801 and 408,804 Cash SARs, respectively. At December 31, 2011 and 2010, the liability for Cash SARs was $6.5 million and $4.3 million, of which, $5.2 million and $2.7 million are 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 $1.3 million and $1.6 million, classified as other long-term liabilities, respectively.

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, 2011:

As of December 31, 2011, unrecognized compensation costs related to unvested Cash SARs was $2.3 million and will be recognized as stock-based compensation expense over a weighted-average period of 1.7 years. The 2011 grants of Cash SARs contained performance and service conditions. The performance conditions have been met for all awards.

Utica Shale Joint Venture. In September 2011, the Company entered into a joint venture with affiliates of Avista to acquire and develop acreage in the liquids rich region of the Utica Shale. The properties initially dedicated to the joint venture consist of approximately 15,000 net acres in eastern Ohio and northwestern Pennsylvania. Under the terms of the agreement, the Company owns an initial 10% interest in the joint venture properties with Avista owning the remaining 90%. Avista has the right to contribute aggregate funds of up to $130.0 million to the joint venture, with the ability to raise this amount by an incremental $70.0 million. The Company holds two purchase options to increase its participating interest to 50% in the properties initially dedicated to the joint venture and subsequently acquired by the joint venture that expire in September 2012 and March 2013, respectively. The Company’s purchase options may be exercised at specified increments above acreage cost and associated improvements at any time during the applicable option period. The exercise deadlines for both options are accelerated in connection with a sale by Avista of substantially all of its interests in the joint venture properties. In the event these purchase options are not exercised and the Company is not selling substantially all of its interest in the joint venture (except in connection with such a sale by Avista), the Company will be entitled to share in any cash distributions by Avista to its partners, provided specified return on investment thresholds on Avista’s investment are achieved, with the percentage of such cash distributions to the Company increasing if higher rates of return on investment thresholds are achieved. The Company will initially serve as operator of the joint venture properties and will provide certain management services to Avista related to the joint venture.

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 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 $327.0 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. 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 142,653 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.

In June 2011, in accordance with the title and post-closing adjustment provisions of the purchase and sale agreements described above, the Company provided additional interests in oil and gas properties in parts of Pennsylvania in the Marcellus Shale to Reliance in substitution of properties included in the sale that were affected by certain alleged title defects. In exchange for such substitute properties, the Company received $0.3 million in cash from Reliance relating to the sale of 20% of its interest.

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 ACP II, 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 Holding Inc., a wholly-owned subsidiary of the Company, 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.

Each party 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 disclosed elsewhere, the Company has been and is a party to prior arrangements with affiliates of Avista Capital Holdings, LP in respect of the Company’s joint venture with affiliates of Avista in the Utica Shale and investment in Pinnacle.

ACP II Distributions. During the third and fourth quarters of 2010, the Company received cash distributions aggregating approximately $38.8 million and during the second quarter of 2011 received an additional $3.3 million on its B Unit investment in ACP II, which were recognized as a reduction of capitalized oil and gas property costs.

Advances from Avista and affiliates. Advances for joint operations on the consolidated balance sheets included $9.5 million and $1.2 million as of December 31, 2011 and 2010, respectively, representing the net amounts Avista had advanced the Company related to activity within the Utica and Marcellus Shale joint ventures.

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 recognized as gain (loss) on derivative instruments, net in the consolidated statements of operations for the period in which the changes occur.

The fair value of derivative instruments at December 31, 2011 was a net asset of $37.3 million, of which 68% was with Credit Suisse, 19% was with BNP Paribas, 6% was with Shell Energy North America (US) LP, 5% was with Credit Agricole, and the remaining 2% was with Societe Generale. The fair value of derivative instruments at December 31, 2010 was a net asset of $24.1 million, of which 74% was with Credit Suisse, 14% was with Shell Energy North America (US) LP, 9% was with Credit Agricole, and the remaining 3% was with BNP Paribas. 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, the Company believes it has minimal credit risk and accordingly does not currently require its counterparties to post collateral to support the asset positions of its derivative instruments. As such, the Company 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. Because Credit Suisse, BNP Paribas, Credit Agricole, and Societe Generale are lenders in the Company’s Revolving Credit Facility, the Company is not required to post collateral with respect to derivatives instruments in a net liability position with these counterparties as the contracts 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, 2011.

In connection with the derivative instruments above, the Company has entered into protective put spreads. In 2012, at market prices below the short put price of $4.77, the floor price becomes the market price plus the put spread of $1.28 on 7,572,400 of the 18,943,000 MMBtus and the remaining 11,370,600 MMBtus have a floor price of $5.43.

In addition to the table above, the Company sold call positions of 3,650,000 MMBtus at a price of $5.50 per MMBtu for 2014.

The following sets forth a summary of the Company’s U.S. crude oil derivative positions at average NYMEX prices as of December 31, 2011.

For the years ended December 31, 2011, 2010 and 2009, the Company recorded the following gains and losses related to its oil and gas derivative instruments:

The Company deferred the payment of premiums associated with certain of its oil and gas derivative instruments totaling $1.2 million and $3.9 million at December 31, 2011 and December 31, 2010, respectively. The Company classified $0.4 million and $3.9 million as other current liabilities at December 31, 2011 and December 31, 2010, respectively, and $0.8 million as other non-current liabilities at December 31, 2011. There were no other non-current liabilities at December 31, 2010. These deferred premiums will be paid to the counterparty with each monthly settlement (April 2012 – March 2014) and recognized as a reduction of realized gain (loss) on derivative instruments, net.

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:

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.

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2011 and 2010, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

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 Company had no transfers in or out of Levels 1 or 2 for the years ended December 31, 2011 and 2010.

The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables and short-term 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 amounts of long term debt under the Prior Credit Facility, the Revolving Credit Facility and the Huntington Facility (each as defined in Note 6. Debt) approximate fair value as these borrowings bear interest at variable rates of interest. The fair value of the Convertible Senior Notes at December 31, 2011 and 2010 was estimated at approximately $73.0 million and $71.9 million, respectively, based on quoted market prices. The fair value of the Senior Notes at December 31, 2011 and 2010 was estimated at approximately $606.0 million and $412.0 million, respectively, based on quoted market prices, with an increase of $194.0 million due to the issuance of the additional $200 million of Senior Notes in November 2011.

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

In November 2010 and November 2011, the Company and certain of the Company’s wholly owned subsidiaries (such subsidiaries collectively, the “Subsidiary Guarantors”) issued in private placements $400.0 million and $200.0 million, respectively, aggregate principal amount of the Company’s Senior Notes. Certain, but not all, of the Company’s wholly owned subsidiaries have issued full, unconditional and joint and several guarantees of the Senior Notes and may guarantee future issuances of debt securities. In connection with both offerings, the Company subsequently filed Form S-4 Registration Statements with the SEC to exchange the previously issued privately placed notes for notes registered under the Securities Act of 1933, as amended. On May 4, 2011, two of the Subsidiary Guarantors, CCBM, Inc. and Chama Pipeline Holding LLC, were released from their respective guarantees of the Senior Notes and the Convertible Senior Notes and were subsequently dissolved. On August 5, 2011, two recently formed wholly owned subsidiaries of the Company, Carrizo (Eagle Ford) LLC and Carrizo (Niobrara) LLC, guaranteed the Senior Notes and the Convertible Senior Notes. These entities also guarantee borrowings under the Revolving Credit Facility.

The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information as of December 31, 2011 and December 31, 2010, and for each of the three years ended December 31, 2011, 2010 and 2009 on a parent company, combined guarantor subsidiaries, combined non-guarantor subsidiaries, eliminating entries, and consolidated basis and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the Subsidiary Guarantors operated as independent entities.

Investments in subsidiaries are accounted for by the respective parent company using the equity method for purposes of this presentation. Results of operations of subsidiaries are therefore reflected in the parent company’s investment accounts and earnings. The principal elimination entries set forth below eliminate investments in subsidiaries and intercompany balances and transactions. Typically in a condensed consolidating financial statement, the net income and equity of the parent company equals the net income and equity of the consolidated entity. The Company’s oil and gas properties are accounted for using the full cost method of accounting whereby impairments and DD&A are calculated and recorded on a country by country basis. However, when calculated separately on a legal entity basis, the combined totals of parent company and subsidiary impairments and DD&A can be more or less than the consolidated total as a result of differences in the properties each entity owns including amounts of costs incurred, production rates, reserve mix, future development costs, etc. Accordingly, elimination entries are required to eliminate any differences between consolidated and parent company and subsidiary company combined impairments and DD&A.

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

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

Costs incurred excludes capitalized interest on U.S. unproved properties of $23.4 million, $20.7 million, and $19.7 million for the years ended December 31, 2011, 2010 and 2009, respectively, and includes capitalized internal costs directly identified with acquisition, exploration, and development activities of $9.6 million, $5.3 million, and $5.6 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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, 2011, 2010 and 2009, 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. Such estimates have been prepared in accordance with guidelines established by the SEC.

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:

Natural gas extensions and discoveries are primarily attributable to the following:

Natural gas revisions of previous estimates are primarily attributable to the following:

Natural gas sales of reserves in place are primarily attributable to the following:

Crude oil, condensate and natural gas liquids extensions and discoveries are primarily attributable to the following:

Crude oil, condensate and natural gas liquids sales of reserves in place are primarily attributable to the following:

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:

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 2011, 2010 and 2009 under these rules were $95.28, $74.39, and $56.10 per barrel, respectively, for crude oil and condensate, $44.90, $35.18 and $23.18 per barrel, respectively, for natural gas liquids, and $3.24, $3.50 and $3.30 per Mcf, respectively, 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 the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are summarized below:

The following table presents summarized quarterly financial information for the years ended December 31, 2011 and 2010:

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. In addition, the sum of the individual quarterly revenues, costs and expenses, net and net income (loss) may not agree with year-to-date totals due to rounding.

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*

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.


Texas		76-0415919
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

500 Dallas Street, Suite 2300, Houston, Texas		77002
(Principal executive offices)		(Zip Code)


	Oil, Condensate and Natural Gas Liquids (MBbls)		Natural Gas (MMcf)		Total (Mmcfe) (1)		PV-10 Value (2) (3)
U.S. Proved
Developed		7,989		389,795		437,729	$	731,032
Undeveloped		21,233		333,052		460,448		343,476

Total Proved		29,222		722,847		898,177		1,074,508

U.K. Proved
Developed		2,719		2,419		18,730		196,086
Undeveloped		2,718		2,419		18,729		178,442

Total Proved		5,437		4,838		37,459		374,528

Total Proved
Developed		10,708		392,214		456,459		927,118
Undeveloped		23,951		335,471		479,177		521,918

Total Proved		34,659		727,685		935,636	$	1,449,036


	2011			2010			2009
United States
Reserve replacement		308	%		650	%		400	%
Reserve replacement excluding divestitures		628	%		650	%		400	%
World-wide Reserve Replacement Ratio
Reserve replacement		311	%		749	%		400	%
Reserve replacement excluding divestitures		631	%		749	%		400	%


	Year Ended December 31,
	2011		2010		2009
Production volumes
Oil (MBbls)		802		176		174
Natural gas (MMcf)		38,991		34,092		30,027
NGLs (MMcf)		1,257		1,659		1,975
Natural gas equivalent (MMcfe)		45,060		36,807		33,046
Average sales prices
Oil (per Bbl)	$	94.16	$	78.64	$	58.85
Natural gas (per Mcf)		2.98		3.33		3.11
NGLs (per Mcf)		8.40		6.43		4.65
Natural gas equivalent (per Mcfe)		4.49		3.75		3.41
Average costs (per Mcfe)(1)	$	0.46	$	0.52	$	0.91


Forward Looking Statements			3
PART I			5
Item 1. Business			5
Item 1A. Risk Factors			31
Item 1B. Unresolved Staff Comments			46
Item 2. Properties			46
Item 3. Legal Proceedings			46
Item 4. Mine Safety Disclosures			46
PART II			47
Item 5. Market for Registrant’s Common Stock, Related Shareholder Matters and Issuer Purchases of Equity Securities			47
Item 6. Selected Financial Data			49
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			50
Item 7A. Qualitative and Quantitative Disclosures About Market Risk			66
Item 8. Financial Statements and Supplementary Data			67
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure			67
Item 9A. Controls and Procedures			67
Item 9B. Other Information			68
PART III			68
Item 10. Directors, Executive Officers and Corporate Governance			68
Item 11. Executive Compensation			68
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters			68
Item 13. Certain Relationships and Related Transactions, and Director Independence			68
Item 14. Principal Accountant Fees and Services			69
PART IV			69
Item 15. Exhibits and Financial Statement Schedules			69


	Proved Reserves (Bcfe)
	December 31, 2011		December 31, 2010
Barnett Shale		658		680
Eagle Ford Shale		171		90
U.K. North Sea		38		36
Marcellus Shale		37		3
Gulf Coast/Camp Hill		26		30
Niobrara Formation		6		2

Total		936		841


	Capital Expenditures ($ in millions)
	2012 Plan		2011 Actual
Eagle Ford Shale	$	320	$	195
Marcellus Shale		62		47
Niobrara Formation		43		39
Barnett Shale		15		100

U.S. drilling capital expenditures		440		381
U.S. leasehold, seismic, and other project areas		25		111

Total U.S. capital expenditures		465		492

U.K. North Sea		35		39

Total	$	500	$	531


	Company Operated				Non-Operated				Total
	Gross		Net		Gross		Net		Gross		Net
Oil		126		116.4		8		2.7		134		119.1
Natural gas		223		172.4		169		25.5		392		197.9

Total		349		288.8		177		28.2		526		317.0


	Developed Acreage				Undeveloped Acreage				Total
	Gross		Net		Gross		Net		Gross		Net
Eagle Ford Shale - Texas (1)		15,516		12,075		82,611		28,969		98,127		41,044
Niobrara Formation - Colorado		6,084		5,375		101,468		52,880		107,552		58,255
Barnett Shale - Texas		28,197		20,055		6,116		4,611		34,313		24,666
Marcellus Shale
New York		2,117		158		31,417		6,752		33,534		6,910
Pennsylvania		3,393		1,210		130,792		45,688		134,185		46,898
West Virginia		801		389		116,662		52,629		117,463		53,018
Virginia and other		53		26		5,932		2,930		5,985		2,956

Marcellus Shale Total		6,364		1,783		284,803		107,999		291,167		109,782
Other (2)		34,323		16,357		167,604		111,718		201,927		128,075

Total United States		90,484		55,645		642,602		306,177		733,086		361,822
Total U.K. North Sea		1,767		265		121,179		85,804		122,946		86,069

Total		92,251		55,910		763,781		391,981		856,032		447,891


	High		Low
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
2011
First Quarter	$	39.34	$	28.71
Second Quarter		42.72		32.47
Third Quarter		44.17		20.95
Fourth Quarter		30.00		18.02


	S&P		AMEX		COGI
December 31, 2006		100		100		100
December 31, 2007		104		128		189
December 31, 2008		64		65		55
December 31, 2009		79		90		91
December 31, 2010		89		116		119
December 31, 2011		89		103		91


					2011 Period Compared to 2010 Period
	December 31,				Increase			% Increase
	2011		2010		(Decrease)			(Decrease)
Production volumes -
Oil and condensate (Mbbls)		802		176		626			356	%
Natural gas (MMcf)		38,991		34,092		4,899			14	%
NGLs (MMcf)		1,257		1,659		(402	)		-24	%
Average sales prices -
Oil and condensate (per Bbl)	$	94.16	$	78.64	$	15.52			20	%
Natural gas (per Mcf)		2.98		3.33		(0.35	)		-11	%
NGLs (per Mcf)		8.40		6.43		1.97			31	%
Oil and gas revenues (In thousands)
Oil and condensate	$	75,502	$	13,859	$	61,643			445	%
Natural gas		116,103		113,597		2,506			2	%
NGLs		10,562		10,667		(105	)		-1	%

Total	$	202,167	$	138,123	$	64,044			46	%


					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)⁽¹⁾		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	%


	Total		2012		2013		2014		2015		2016		2017 and Beyond
Long-term debt (1)	$	738,563	$	—	$	73,750	$	17,813	$	—	$	47,000	$	600,000
Interest on long-term debt (2)		375,310		57,206		55,593		53,979		53,176		51,856		103,500
Operating leases		12,886		64		1,179		1,370		1,370		1,370		7,533
Drilling contracts		132,979		54,994		41,158		30,509		6,318		—		—
Pipeline volume commitments		65,916		11,418		15,579		16,343		14,553		8,023		—
Asset retirement obligations		12,168		925		181		298		75		114		10,575
Seismic obligations		2,959		2,959		—		—		—		—		—
Other		1,355		1,355		—		—		—		—		—

Total Contractual Obligations	$	1,342,136	$	128,921	$	187,440	$	120,312	$	75,492	$	108,363	$	721,608


Period	Volume (in MMbtu)		Weighted Average Floor Price ($/MMbtu)		Weighted Average Ceiling Price ($/MMbtu)
2012		18,943,000	$	5.43	$	5.56
2013		10,950,000	$	5.07	$	5.07


Period	Volume (in MMbtu)		Weighted Average Short Put Price ($/MMbtu)		Weighted Average Put Spread ($/MMbtu)
2012		7,572,400	$	4.77	$	1.28


Period	Volume (in Bbls)		Weighted Average Floor Price ($/Bbls)		Weighted Average Ceiling Price ($/Bbls)
2012		1,024,800	$	82.57	$	101.83
2013		839,500	$	83.48	$	102.55


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).

†4.6	–	Sixth Supplemental Indenture dated May 4, 2011 among Carrizo Oil & Gas, Inc. the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011).

†4.7	–	Seventh Supplemental Indenture dated May 4, 2011 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 Quarterly Report on Form 10-Q for the quarter ended March 31, 2011).



†4.8	–	Eighth Supplemental Indenture dated August 5, 2011 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 Quarterly Report on Form 10-Q for the quarter ended June 30, 2011).

†4.9	–	Ninth Supplemental Indenture dated August 5, 2011 among Carrizo Oil & Gas, Inc. the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011).

†4.10	–	Officers’ Certificate of the Company dated as of November 17, 2011 (incorporated herein by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K filed on November 17, 2011).

†4.11	–	Form of Warrant issued pursuant to Land Agreement dated November 24, 2009 (incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011)

*†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) (incorporated herein by reference to Exhibit 10.12 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2010).

*†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 (incorporated herein by reference to Exhibit 10.14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2010).



*†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. Cash-Settled 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 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).

†10.25	–	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 SocieteGenerale 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).

†10.26	–	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).

†10.27	–	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).

†10.28	–	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).

†10.29	–	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).



21.1	–	Subsidiaries of the Company.

23.1		Consent of KPMG LLP.

23.2	–	Consent of Fairchild and Wells, Inc.

23.3	–	Consent of LaRoche Petroleum Consultants, Ltd.

23.4	–	Consent of Ryder Scott Company Petroleum Engineers (U.S.).

23.5	–	Consent of Ryder Scott Company Petroleum Engineers (U.K.).

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, 2011 (U.S.).

99.2	–	Summary of Reserve Report and Report of Ryder Scott Company Petroleum Engineers as of December 31, 2011 (U.K.).

99.3	–	Summary of Reserve Report and Report of Fairchild and Wells, Inc. as of December 31, 2011.

99.4	–	Summary of Reserve Report and Report of LaRoche Petroleum Consultants, Ltd. as of December 31, 2011.


	PAGE
Reports of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets, December 31, 2011 and 2010		F-4
Consolidated Statements of Operations for the Years Ended December 31, 2011, 2010 and 2009		F-5
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2011, 2010 and 2009		F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2011, 2010 and 2009		F-7
Notes to Consolidated Financial Statements		F-8


	For the Years Ended December 31,
	2011			2010			2009
	(In thousands, except per share amounts)
OIL AND GAS REVENUES	$	202,167		$	138,123		$	112,699
COSTS AND EXPENSES
Lease operating		28,314			23,659			25,167
Production tax		5,697			3,648			132
Ad valorem tax		3,625			3,707			5,022
Depreciation, depletion and amortization		84,606			47,030			52,005
Impairment of oil and gas properties		—			2,731			338,914
General and administrative (inclusive of stock-based compensation expense of $11,864, $16,608 and $11,297 for the years ended December 31, 2011, 2010 and 2009, respectively)		41,781			35,906			30,136
Accretion expense related to asset retirement obligations		311			216			308

TOTAL COSTS AND EXPENSES		164,334			116,897			451,684

OPERATING INCOME (LOSS)		37,833			21,226			(338,985	)
OTHER INCOME AND EXPENSES
Gain (loss) on derivative instruments, net		46,991			47,782			41,465
Loss on extinguishment of debt		(897	)		(31,023	)		—
(Impairment) recovery of investment in Pinnacle		—			165			(2,091	)
Interest expense		(52,803	)		(43,264	)		(38,286	)
Capitalized interest		23,369			20,746			19,696
Other income, net		356			47			49

INCOME (LOSS) BEFORE INCOME TAXES		54,849			15,679			(318,152	)
INCOME TAX (EXPENSE) BENEFIT		(18,220	)		(5,729	)		113,307

NET INCOME (LOSS)	$	36,629		$	9,950		$	(204,845	)

OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAXES
Increase in fair value of investment in Pinnacle, net of income taxes		—			17			55
Reclassification of cumulative (increase) decrease in fair value of investment in Pinnacle, net of income taxes		—			(106	)		1,333

COMPREHENSIVE INCOME (LOSS)	$	36,629		$	9,861		$	(203,457	)

NET INCOME (LOSS) PER COMMON SHARE
BASIC	$	0.94		$	0.29		$	(6.61)

DILUTED	$	0.92		$	0.29		$	(6.61)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING
BASIC		39,077			33,861			31,006
DILUTED		39,668			34,305			31,006


					Additional Paid-in Capital			Retained Earnings (Accumulated Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Shareholders’ Equity

	Common Stock
	Shares		Amount
					(In thousands, except share amounts)
BALANCE, January 1, 2009		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 issued, net of forfeitures		226,286		2		304			—			—			306
Other		9,500		—		123			—			—			123
Other comprehensive loss, net of income taxes
Increase in fair value of investment in Pinnacle, net of income tax expense of $31		—		—		—			—			55			55
Reclassification of cumulative decrease in fair value 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 issued, net of forfeitures		344,311		3		(1,101	)		—			—			(1,098	)
Common stock offerings, net of offering costs		7,195,000		72		188,462			—			—			188,534
Other		—		—		750			—			—			750
Other comprehensive income, net of income taxes
Increase in fair value of investment in Pinnacle, net of income tax expense of $9		—		—		—			—			17			17
Reclassification of cumulative increase in fair value 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
Stock options exercised for cash		151,500		1		47			—			—			48
Stock-based compensation		—		—		14,444			—			—			14,444
Restricted stock awards and units issued, net of forfeitures		439,237		4		(483	)		—			—			(479	)
Other		65,762		1		2,576			—			—			2,577
Other comprehensive income, net of income taxes
Net income		—		—		—			36,629			—			36,629

Total comprehensive income		—		—		—			—			—			36,629

BALANCE, December 31, 2011		39,562,676	$	395	$	647,429		$	(137,969	)	$	—		$	509,855


January 1, 2009	$	1,264
Charged to general and administrative		772

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

December 31, 2010		2,470
Charged to general and administrative		31
Amounts written off		(197	)

December 31, 2011	$	2,304


	Years Ended December 31,
	2011			2010		2009
				(In thousands)
Stock Options and SARs	$	1,546		$	6,649	$	1,192
Restricted Stock Awards and Units		13,965			9,959		10,105

		15,511			16,608		11,297
Less: amounts capitalized		(3,647	)		—		—

Total Stock-Based Compensation Expense	$	11,864		$	16,608	$	11,297

Income Tax Benefit	$	4,342		$	6,152	$	4,113

		$00,0000			$00,0000			$00,0000
	Year Ended December 31,
	2011			2010			2009
				(In thousands)
Current income tax expense
U.S. Federal	$	(404	)	$	—		$	(6	)
State		(661	)		(4,236	)		(65	)
U.K.		—			—			—

Total current income tax expense		(1,065	)		(4,236	)		(71	)


Deferred income tax (expense) benefit
U.S. Federal		(22,100	)		(4,937	)		111,325
State		(1,292	)		3,444			2,053
U.K.		6,237			—			—

Total deferred income tax (expense) benefit		(17,155	)		(1,493	)		113,378

Total income tax (expense) benefit	$	(18,220	)	$	(5,729	)	$	113,307


	Year Ended December 31, 2011			Year Ended December 31, 2010
	(In thousands)
Asset retirement obligations at beginning of period	$	6,369		$	5,410
Liabilities incurred		3,772			181
Liabilities settled		(162	)		(288	)
Reduction due to property sales		(369	)		—
Accretion expense		311			216
Revisions of previous estimates		2,246			850
Asset retirement obligations due within one year*		(925	)		—

Asset retirement obligations at end of period	$	11,242		$	6,369


	Amount
	(In thousands)
2012	$	69,434
2013		57,917
2014		48,222
2015		22,241
2016		9,393
2017 and Thereafter		7,533

	$	214,740


	Shares			Weighted- Average Exercise Prices		Weighted- Average Remaining Life (In years)		Aggregate Intrinsic Value (In millions)
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

Exercisable, end of period		414,854		$	6.10

For the Year Ended December 31, 2011
Oustanding, beginning of period		414,854		$	6.10
Granted		—			—
Exercised		(151,500	)		4.36
Forfeited		—			—

Oustanding, end of period		263,354		$	7.11		1.82	$	5.11

Exercisable, end of period		263,354		$	7.11		1.82	$	5.11


	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


	Shares/ Units			Grant-date Fair Value
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
Granted		567,901			35.27
Vested		(452,585	)		25.29
Forfeited		(25,773	)		23.30

Unvested restricted stock awards and units at December 31, 2011		800,498		$	27.96


	Granted in 2011			Granted in 2010
December 31, 2011 fair value	$	18.50		$	23.06
Volatility factor		61.6	%		60.3	%
Dividend yield		—			—
Risk-free interest rate		0.4	%		1.8	%
Expected term (in years)		2.9			4.5


Period	Volume (in MMbtu)		Weighted Average Floor Price ($/MMbtu)		Weighted Average Ceiling Price ($/MMbtu)
2012		18,943,000	$	5.43	$	5.56
2013		10,950,000	$	5.07	$	5.07