# UNITED ST A TES SECURITIES AND EXCHANGE COMMISSION W ashington, D.C. 20549 

# Form 10-K Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the Fiscal Y

ear Ended December

31, 2012 Commission File Number 000-29187-87 

# Carrizo Oil & Gas, Inc. (Exact name of registrant as specified in its charter)
Texas 76-0415919 (State or other jurisdiction of incorporation or

organization) (I.R.S. Employer Identification No.) 500 Dallas Street, Suite 2300, Houston, T

exas 77002 (Principal executive offices) (Zip Code) Registrant’s telephone number , including area code: (713) 328-1000 Securities Registered Pursuant to Section 12(b) of the Act:

Common Stock, $0.01 par value Indicate by check mark ifthe registrant is a well-known seasoned issuer, as defined in Rule 405 ofthe Securities Act. YES 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 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) ofthe 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 NO Indicate by check mark whether the registrant has submitted electronically and posted on its corporate W eb site, if any

, every Interactive Data File required to be submitted and posted pursuant to Rule 405 ofRegulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES NO Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 ofRegulation 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 ofthis 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):
Large accelerated filer Accelerated filer Non-accelerated filer (Do not check if a smaller reporting company) Smaller reporting company Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 ofthe Act). YES NO At June 30, 2012, the aggregate market value of the registrant’s Common Stock held by non-af filiates of the registrant was approximately $848.1 million based on the closing price of such stock on such date of $23.49

. At February 25, 2013, the number of shares outstanding ofthe registrant’s Common Stock was 40,281,069.DOCUMENTS INCORPORA TED BY REFERENCE Portions ofthe definitive proxy statement for the Registrant’s 2013 Annual Meeting of Shareholders are incorporated by reference in Part III ofthis Form 10-K. Such definitive proxy statement will be filed with the U.S. Securities and Exchange Commission not later than 120 days subsequent to December 31, 2012

.2 T ABLE OF

CONTENTS

Forward-Looking Statements P AR T I Item 1. Business Item 1A. Risk Factors Item 1B. Unresolved Staf f Comments Item 2. Properties Item 3. Legal Proceedings Item 4. Mine Safety Disclosures P AR T II Item 5. Market for Registrant’s Common Stock, Related Shareholder Matters and Issuer Purchases of Equity Securities Item 6. Selected Financial Data Item 7. Management’s Discussion and Analysis ofFinancial Condition and Results of Operations Item 7A. Qualitative and Quantitative Disclosures about Market Risk Item 8. Financial Statements and Supplementary Data Item 9. Changes In and Disagreements W ith Accountants on Accounting and Financial Disclosures Item 9A. Controls and Procedures Item 9B. Other Information P AR T III Item 10. Directors, Executive Of ficers and Corporate Governance Item 1 1. Executive Compensation Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters Item 13. Certain Relationships and Related Transactions, and Director Independence Item 14. Principal Accountant Fees and Services P AR T IV Item 15. Exhibits and Financial Statement Schedules 3

4 28 40 40 40 40

41 43 44 59 60 60 60 61

62 62

62 62 62

633

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

• our growth strategies;

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

• our estimates and forecasts ofthe timing and number ofwells we expect to drill and other exploration activities;

• our estimates regarding timing and levels ofproduction;

• anticipated trends in our business;

• the ef

fects of competition on us;

• our future results of operations;

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

• our capital expenditure plan;

• plans regarding our U.K. North Sea assets;

• future market conditions in the oil and gas industry;

• our ability to make, integrate and develop acquisitions; and

• the impact of governmental regulation, taxes, market changes and world events.
Y ou 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 offinancing, 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 af fect 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 ofus by lenders under our credit facilities, the potential impact ofgovernment 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 ofreserve information and future net revenue estimates, property acquisition risks, availability of equipment and crews, actions by our midstream and other industry partners, weather, availability offinancing, actionsby lenders, our abilityto obtainpermits and licenses,theresults ofaudits and assessments, the failure to obtain certain bank and lease consents, the existence and resolution oftitle defects, new taxes and impact fees, delays, costs and dif

ficulties relating to ourjoint ventures, actionsbyjoint venturepartners, results ofexploration activities, the availability and completion of land acquisitions, completion and connection ofwells, and other factors detailed in this annual report.
W e havebased our forward-looking statements on our management’sbeliefs and assumptionsbased on information available to our management at the time the statements are made. W e 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 dif

fer materially from those expressed or implied by our forward-looking statements.
Some ofthe factors that could cause actual results to dif fer from those expressed or implied in forward-looking statements are described under Part I, “Item 1A. Risk Factors” and in other sections ofthis annual report. Should one or more ofthese risks
or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.All subsequentwritten and oral forward-looking statements attributabletous orpersons acting on ourbehalfare expressly qualified in their entirety by reference to these risks and uncertainties.Y ou should not place undue reliance on our forward-looking statements. Each forward-looking statement speaks only as ofthe date ofthe 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 T erms” included under Part I, “Item 1. Business.”4

P AR T I Item 1. Business General Overview 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 ofoil and gas primarily from resource plays located in the United States. Our current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South T exas, the Niobrara Formation in Colorado, the Marcellus Shale in Pennsylvania, the Barnett Shale in North T exas, and the Utica Shale in Ohio.
Since we began focusing a significant portion of our ef forts in shale plays, particularly in the Barnett Shale in 2003 and EagleFord Shalein2010,wehavegrownourreservesatacompoundedannualgrowthrate (“CAGR”)of30%,while simultaneously maintaining a CAGR on our production of 25%. After adjusting for 2012 sales of oil and gas interests in the Barnett Shale and other U.S. areas, andjoint ventures in the Niobrara Formation, we added, net ofproduction, 28.4 MMBoe to proved reserves, for
a reserve replacement ratio of 301% during 2012

. 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 2012 of 9.4 MMBoe, a 26% increase from 201 1

. At year-end 2012, our proved reserves of 121.1 MMBoe were approximately 41% crude oil, condensate and natural gas liquids and approximately 59% natural gas, as compared to 22% and 78% at year-end 201 1 , respectively

. The following table provides details about the Company’s proved reserves as ofthe dates indicated.

Proved Reserves (MMBoe) December 31, 2012 December 31, 2011 U.S. Barnett Shale 50.6 109.6 Eagle Ford Shale 49.0 28.5 Marcellus Shale 12.5 6.2 Niobrara Formation 2.0 1.0 Other U.S. 1.0 4.3 T otal U.S. 115.1 149.6 U.K. North Sea (discontinued operations) 6.0 6.3 W orldwide 121.1 155.9

Our Board of Directors has approved a U.S. capital expenditure plan of $624.0 million for 2013

. This plan reflects our strategy of controlling capital costs and maintaining financial flexibility in light of current economic conditions. W e currently expect to commit the majority of our 2013 U.S. capital expenditure plan to the continued development of our properties in the Eagle Ford Shale, the Marcellus Shale and the Niobrara Formation. The level of our expected Niobrara Formation capital expenditures reflects the obligation of our joint venture partners to carry a portion of our costs. W e intend to finance our 2013 U.S. capital expenditure plan primarily from cash flow from operations and our senior secured credit facility

. Other available
sources offunding include proceeds from the possible selective sale ofassets and of ferings ofsecurities.The table below highlights capital expenditures in our primary areas of activity: Capital Expenditures ($ in millions) 2013 Plan 2012 Actual U.S. Eagle Ford Shale $ 385.0 $ 402.0 Marcellus Shale 70.0 78.8 Niobrara Formation 35.0 62.7 Barnett Shale and Other U.S. 10.0 20.1 Total U.S. drilling and completion 500.0 563.6 U.S. leasehold and seismic 124.0 132.2 T otal U.S. 624.0 695.8 U.K. North Sea (discontinued operations)

— 46.4 W orldwide 624.0 742.25

Crude Oil and Liquids Plays and Projects At December 31, 2012, our crude oil and liquids proved reserves were 49.7 MMBoe, a 43% increase from 34.7 MMBoe at December 31, 201 1

. The significant increase in crude oil and liquids reserves was primarily due to the execution of our growth strategy in crude oil and liquids-rich plays in the Eagle Ford Shale and, to a lesser extent, the Niobrara Formation, collectively adding 18.1 MMBoe ofcrude oil and liquids to our proved reserves (21.5 MMBoe including associated gas) during 2012, which
was partially of

fset by the sale of an aggregate 40% of substantially all of our interest in oil and gas properties in the Niobrara formationtonewjointventurepartners (0.4 MMBoe ofcrude oil and liquidsreserves as ofDecember 31, 201 1). See also “Niobrara Formation—OIL Joint V

enture” and “—Haimo Joint V enture” below

. Eagle For

d Shale The Eagle Ford Shale has become our most significant operational area. Our core Eagle Ford Shale properties are located in LaSalle county and, to a lesser extent, in McMullen, Frio and Atascosa counties in T exas. Our drilling targets in this area are substantially all in the Eagle Ford Shale, although we have recently begun drilling to the Pearsall Shale, which is found below the Eagle Ford Shale. Following the April 2010 announcement of our growth strategy to increase crude oil and liquids production,
we commenced a leasing program targeting the liquids-rich window ofthe Eagle Ford Shale. As ofDecember 31, 2012, we held interests in approximately 95,599 gross (49,003 net) acres, 72 gross (57.0 net) producing wells and 19 gross (15.8 net) wells that
were drilled but waiting on completion. W e operated all of these wells mentioned. During 2012, we drilled 59 gross (46.7 net) wells, all ofwhich we operated, and completed and brought on production 51 gross (29.2 net) wells. Approximately 43% of our 49,003 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. Our 2012 production in the Eagle Ford Shale was 2,910.0 MBoe (7,950.0 Boe/d), 352% above 201 1 production of 644.0 MBoe (1,764.0 Boe/d). T otal proved reserves for the Eagle Ford Shale were 49.0 MMBoe at December 31, 2012, approximately 85%, or 41.7 MMBoe, ofwhich was crude oil (36.5 MMBbls) and liquids (5.2 MMBoe).
As ofDecember 31, 2012, we were operating three rigs in the Eagle Ford Shale and expect to operate three rigs in the Eagle Ford Shale throughout 2013

. W e currently expect our 2013 Eagle Ford Shale development ef forts to require an investment of approximately $385.0 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, Frio and Atascosa counties.
GAIL Joint V

entur e. In September 201 1, we completed the sale of 20% of our interests in certain oil and gas properties in the Eagle Ford Shale 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. The GAIL development carry was fully utilized in 2012.
In connection with this sale transaction, we and GAIL also entered into agreements to form a newjoint venture with respect to the interests purchased by GAIL. Under the terms ofthe agreement, we generally retained a 80% working interest in the acreage and GAIL purchased a 20% working interest. W e 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 a specified premium, and is subject to specified exceptions. W e serve as operator ofthe properties covered by this joint venture. As ofDecember 31, 2012, the joint venture with GAIL included approximately 23,320 net acres in the Eagle Ford Shale.
Niobrara Formation As another 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, primarily in W eld and Adams counties, Colorado. During 2012, we drilled 26 gross wells (9.1 net), ofwhich we operated 23 gross wells (8.9 net), and completed and brought on production 23 gross wells (8.0 net).As ofDecember 31, 2012, we held interests in approximately 1 12,946 gross (36,213 net) acres, 37 gross (13.4 net) producing wells and 2 gross (0.6 net) wells that were drilled but waiting on completion. Ofthese wells, we operated 31 gross (12.5 net) producing wells and 2 gross (0.6 net) wells drilled and waiting on completion. Our 2012 production in the Niobrara was 460.9 MBoe (1,259.2 Boe/d), compared to 201 1 production of 154.3 MBoe (422.7 Boe/d). T otal proved reserves for the Niobrara were 2.0 MMBoe at December 31, 2012, approximately 85%, or 1.7 MMBoe, ofwhich was crude oil and liquids.
OIL Joint V

entur e. In October 2012, we completed the sale of 30% of our interests in certain oil and gas properties in the Niobrara Formation to OIL India (USA) Inc. and IOCL (USA) Inc., wholly owned subsidiaries of OIL India Ltd. and Indian Oil Corporation Ltd., respectively , for $41.25 million in cash and a commitment to pay a development carry of 50% of our future development costs up to $41.25 million net to our interest as described below

. For convenience, in this annual report on Form 10-K the term “OIL JV Partners” is used to refer collectively to OIL India (USA) Inc. and IOCL (USA) Inc. The OIL JV Partners’ development carry period lasts until March 2014, unless earlier utilized, and any remaining portion of the OIL JV Partners’6

development carry is to be paid to us at the end ofthe development carry period. The Niobrara Formation assets conveyed to the OIL JV Partners under the terms ofthe agreement are located primarily in W eld and Adams counties, Colorado.
In connection with this sale transaction, we and the OIL JV Partners entered into agreements to form a new joint venture with respect to the interests purchased by the OIL JV Partners. Under the terms of the agreement, we serve as operator of the properties covered by the joint venture. W e also granted an option in favor of the OIL JV Partners to purchase a 30% share of acreage acquired by us after the ef fective date of the transaction in specified areas of the play

. This option is exercisable at our cost plus a specified premium and is subject to specified exceptions.
HaimoJoint V

entur e. In December 2012, we completed the sale ofan additional portion ofour remaining interests in the same oil and gas properties sold to the OIL JV Partners in the transaction described above to Haimo Oil & Gas LLC (“Haimo”), a wholly owned subsidiary of Lanzhou Haimo T echnologies Co. Ltd., for $27.5 million in cash. Following the closing of the Haimo transaction, the joint venture ownership interests in our Niobrara Formation development activities were 60% Carrizo, 30% the OIL JV Partners, and 10% Haimo. As of December 31, 2012, the collective Niobrara Formation joint ventures included approximately 58,607 net acres. In connection with the sale transaction with Haimo, Carrizo (Niobrara) LLC and Haimo entered into agreements to form a new joint venture with respect to the interests purchased by Haimo. Under the terms of the agreement, we serve as operator of the properties covered by the joint venture. W e also granted an option in favor of Haimo to purchase a 10% share of acreage acquired by us after the ef fective date ofthe transaction in specified areas ofthe play , which areas are the same as the OILjoint venture described above. This option is exercisable at our cost plus a specified premium, and is subject to specified exceptions.
In2013,wecurrentlyexpecttoinvestapproximately $35.0millionindrillingandcompletioncostsfortheNiobraraFormation, net of carry
. Utica Shale In 201 1, 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 ajoint venture described below

. Avista Utica Joint V

entur e. Ef fective September 201 1, our wholly owned subsidiary , Carrizo (Utica) LLC, entered into a joint venture with ACP II Marcellus LLC (“ACP II”), which is also one of ourjoint venture partners in the Marcellus Shale, and ACP III Utica LLC (“ACP III”), both af filiates ofA

vista Capital Holdings, LP , a private equity firm (collectively with ACP II and ACP III, “A

vista”). As of December 31, 2012, our A vista Utica joint venture held approximately 27,883 net acres, in Ohio and Pennsylvania (including 13,177 net acres located in Guernsey County , Ohio.)
Under the terms ofthisjoint venture, we and A vista have the right to contribute cash and properties to acquire and develop acreage in the Utica Shale play

. The joint venture agreements established an area of mutual interest between us and A vista and provided us options on specified categories ofproperties to increase our participating interest in such properties to equal A vista’s. Under thejoint venture agreements, we serve as operator ofthe Uticajoint venture properties and have agreed to provide certain management services to A vista related to the Utica joint venture. A vista or its designee has the right to become a co-operator of thejoint venture properties if(i) A vista sells substantially all ofits interests in the Uticajoint venture properties or (ii) we default under the terms of any pledge of our interest in the Uticajoint venture properties.
In October 2012, we sold substantially all ofour interests in oil and gas properties dedicated to theA vista Uticajoint venture in the northern portion of the Utica Shale play to a third party and received net cash proceeds of $51.7 million

. Simultaneously with the closing ofthis Utica Shale transaction, A vista sold substantially all ofits interests in the same oil and gas properties. The proceeds from such sale were recognized as a reduction of proved oil and gas properties, net. In connection with these sale transactions, we elected to exercise our option to increase our participating interest in the same oil and gas properties on a “net proceeds basis” so that we received net proceeds with respect to 50% ofthe properties subject to the sale rather than the 10% we initially held. Pursuant to the terms ofthe A vista Utica joint venture agreement, as amended, we paid $24.0 million for the 40% additional interest in the acreage subject to the sale and certain other A vista Uticajoint venture properties. Concurrently with the exercise andclosingofouroptiontoincreaseourparticipatinginterestin suchoilandgasproperties,ourrighttoreceivedistributions associated with properties owned by ACP II in the A vista Utica joint venture through our “B Units” interest in ACP II described below under “Natural Gas Plays—A vista Marcellus Joint V

enture,” was terminated. Following the sale transactions described above, on October 24, 2012, we and A vista amended the Utica Shalejoint venture agreements to provide that the expiration date of our remaining option to increase our participating interest in the A vista Utica joint venture properties was accelerated from March 2013 to January 15, 2013. W e exercised this option on January 15, 2013 by paying $63.1 million for an additional 40% interest in approximately 1 1,000 acres pursuant to the terms ofthe A vista Uticajoint venture agreement.W

e andA vista also agreedthat afterthe optionwas exercised, ourparticipating interest in subsequently acquired7

properties within the area ofmutual interest continued to be 10% and A vista’s participating interest is 90%, and we were granted
an additional option to increase our 10% ownership in such subsequently acquired properties to 50% at 8.625% above acreage cost and associated improvements (compounded monthly following A vista’s contribution ofpurchase proceeds). This additional option will expire May 31, 2013. In connection with the January 2013 exercise ofour option to increase our participating interest in the A vista Uticajoint venture properties, our right to receive distributions associated with properties owned by ACP III through
our “B Units” interest in ACP III that we acquired at the formation ofthe Uticajoint venture was terminated.
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 ofthe following events, at which time the area ofmutual interest will only continue to apply to those areas where thejoint venture is active: (i) September 1, 2014, (ii) ACP III’s investment reaches $170.0 million and A vista declines to participate in specified Utica acquisitions or other specified conditions are met, (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, (iv) upon our required designation ofACP 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 Uticajoint venture properties, (v) the sale by A vista ofsubstantially all ofits interest in the Uticajoint venture properties or (vi) termination oftheACP III management services agreement. Each party’s ability to transfer its interest in the Uticajoint venture to third parties is generally subject to “tag along” rights. A vista’s tag along rights do not apply upon a change of control ofthe Company

. Steven A. W

ebster, Chairman of our Board of Directors, serves as Co-Managing Partner and President ofA vista Capital Holdings, LP

, which entity has the ability to control A vista and its af

filiates. ACP II’s and ACP III’s Boards ofManagers 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

. W ebster is not a member of either entity’s Board of Managers. As previously disclosed, we have been a party to prior arrangements with af filiates ofA

vista Capital Holdings LP , including in respect of our existing joint venture with A

vista in the Marcellus Shale. The terms ofthejoint ventures with A vista in the Utica Shale and the Marcellus Shale
were approved by a special committee ofthe Company’s disinterested directors. See also “Natural Gas Plays—A vista Marcellus Joint V enture” and “Note 1 1. Related Party T ransactions” ofthe Notes to our Consolidated Financial Statements.
U.K. North Sea W eused a low cost entrybusiness model in the U.K.North Sea that allowedus to acquireprospective 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 our wholly owned subsidiary Carrizo UK Huntington Ltd (“Carrizo UK”) owned a 15% non-operated working interest and certain overriding royalty interests. On December 27, 2012, we agreed to sell Carrizo UK, and all of its interest in the Huntington Field discovery , to a subsidiary of Iona Energy Inc. (“Iona Energy”) for net proceeds of approximately $1 16.5 million, subject to final post-closing adjustments, which represents an agreed upon price of$184.0 million, including the assumption of$55.0 million in debt and net purchase price adjustments. Purchase price adjustments primarily relate to working capital and other adjustments, transaction costs and accrual of other obligations related to the transaction. The sale closed on February 22, 2013

. W e classified our U.K. North Sea assets and liabilities as held for sale in the consolidated balance sheets alongwiththerelatedresults ofoperations and cash flows as discontinued operations,net ofincometaxes, inthe consolidated statements of income and cash flows.
The Carrizo UK senior secured multicurrency credit facility agreement that was secured by substantially all ofCarrizo UK’s assets with limited recourse to us (the “Huntington Facility”) was repaid by Iona Energy in connection with the sale transaction described above. As of December 31, 2012 and February 22, 2013, borrowings outstanding under the Huntington Facility were $52.0 million and $55.0 million, respectively

. The Huntington Facility provided financing for a substantial portion of Carrizo UK’s 15% share ofthe development costs associated with the Huntington Field development project through a term loan facility , a cost overrun facility and a letter of credit facility

. For further information concerning the sale ofthe U.K. North Sea assets see “Note 3. Assets Held for Sale” and “—Discontinued Operations” ofthe Notes to our Consolidated Financial Statements.
As ofFebruary 25, 2013, we held interests in four other licenses in the U.K. North Sea. W e currently have satisfied or believe that we can satisfy all remaining committed work obligations on these four licenses at no material additional cost to us. Natural Gas Plays At December 31, 2012, our natural gas proved reserves were 428.3 Bcf, approximately 71% of which was located in the Barnett Shale, a 41% decrease from 727.7 Bcf at December 31, 201 1

. Our natural gas production decreased to 37.6 Bcf (102.8 MMcf/d) in 2012, a 4% decrease from the 39.0 Bcf (106.8 MMcf/d) in 201 1

. The decrease in natural gas proved reserves and natural gas production was primarily related to the sale ofa substantial portion ofour Barnett Shale properties in the second quarter of2012. See “Barnett Shale” below for additional information.8

Mar cellus Shale W ebeganactiveparticipationintheMarcellus Shalein2007.W ebelievethatwehaveleveragedtheknowledgeandexperience that we gained in the Barnett Shale to ef fectively 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, 2012, we owned interests in 223,899 gross (80,505 net) acres in the Marcellus Shale, principally in Pennsylvania, New Y

ork and W

est V irginia. During 2012, we drilled 39 gross (12.5 net) wells, of which we operated 38 gross (12.5 net) wells, and completed and brought on production 32 gross (9.0 net) wells. W e commenced producing from our first operated Marcellus well in late October 201 1 when the Laser pipeline was completed and brought on line. Our 2012 production in the Marcellus Shale was 7.9 Bcfe. As of December 31, 2012, we had a backlog of 28 gross (8.2 net) wells in Northeastern Pennsylvania that were drilled and waiting on completion and 5 gross (2.0 net) wells that were drilled and waiting on pipeline connection. T

otal proved reserves for the Marcellus Shale were 74.8 Bcfe at December 31, 2012, all ofwhich was natural gas. In 2013, we plan to spend approximately $70.0 million in the Marcellus Shale, all of which we expect to use for drilling, completion, and other infrastructure in northeastern Pennsylvania, principally in Susquehanna and W yoming counties.As a result ofthe material decline in natural gas prices, we and ourjoint venture partners are carefully reviewing our development program and have reduced our planned spending in the Marcellus shale during 2013. W e 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 , ifnatural gas prices so warrant. W e are currently operating one rig capable of drilling horizontal wells in the Marcellus Shale.
AvistaMar

cellusJoint V

entur e. Ef fective as ofAugust 2008, our wholly owned subsidiary , Carrizo (Marcellus) LLC, entered into ajoint venture with ACP II, an af filiate ofA

vista with which we also have ajoint venture in the Utica Shale. See also “Crude Oil and Liquids Plays—A vista Utica Joint V

enture” and “Note 1 1. Related Party T ransactions” ofthe Notes to our Consolidated Financial Statements.
W e serve as operator of the properties covered by this joint venture and also perform specified management services for ACP II. An operating committee composed ofone representative ofeach party provides overall supervision and direction ofjoint operations. A

vista or its designee has the right to become a co-operator ofthe A vista Marcellusjoint venture properties ifall ofits membership interests or substantially all ofits assets are sold to an unaf filiated third party or ifwe default under the terms ofany pledge ofour interest in the A vista Marcellusjoint venture properties. Thejoint venture agreements provide for an area ofmutual interest applicable to specified halos in which thejoint venture is active. Subject to specified exceptions (including the Reliance transactions described below), net cash flow from hydrocarbon production fromtheA

vistaMarcellusjointventureproperties andrelated salesproceeds,ifsuchproperties are sold,willbe allocated (a) 75% to A

vista and 25% to us until A vista 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. W e have also agreed tojointly market A vista’s share ofthe production from the Marcellusjoint 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 connection with the formation ofACP II, we were issued “B Units” inACP II. Concurrently with the exercise and closing of our option to increase our participating interest in certain oil and gas properties in the Utica Shale in October 2012, our right to receive distributions associated with properties owned byACP II in theA vista Uticajoint venture through our “B Units” interest in ACP II was terminated. See “Crude Oil and Liquids Plays—A vista Utica Joint V

enture” above for more information.
Each party’s ability to transfer its interest in the Marcellusjoint venture properties to third parties is subject in most instances to preferential purchase rights for transfers ofless than 10% ofits interest in suchjoint venture properties or to “tag along” rights for most other transfers.
As part ofthe closing ofthe transactions with Reliance, we and A vista amended our then-existingjoint venture agreements to provide that the properties that we and A vista sold to Reliance, as well as the properties we committed to thejoint venture with Reliance, are not subject to the terms of our A vista Marcellus joint venture, and that the area of mutual interest of our A vista Marcellusjoint venture will generally not include Pennsylvania, in which those properties are located. OurA vista Marcellusjoint venture will otherwise continue and, as ofDecember 31, 2012, included approximately 71,774 net acres,primarily inW estV irginia and New Y

ork.
Reliance Joint V

entur e. In September 2010, we completed the sale of20% ofour interests in substantially all ofour oil and gas properties in Pennsylvania that had been subject to the A vista Marcellus joint venture to Reliance Marcellus II, LLC9

(“Reliance”), a wholly owned subsidiary ofReliance Holding USA, Inc. and an af filiate ofReliance Industries Limited, for $13.1 million in cash and a commitmentby Reliance topay 75% ofcertain ofour future drilling and completion costsup to approximately $52.0 million. As ofDecember 31, 2012, the development carry had been fully utilized. Simultaneously with the closing of our transaction with Reliance, 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 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 A vista. The Carrizo/Reliance joint venture agreement included approximately 103,232 net acres in northern and central Pennsylvania as ofDecember 31, 2012.
W e have agreed to various restrictions on our ability to transfer our properties covered by the Reliance joint venture. Additionally

, since the expiration ofthe Reliance development carry , we are subject to a mutual right of first of fer on direct and indirect property transfers for the remainder of a ten-year development period (through September 2020), subject to specified exceptions. W

e 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 ofPennsylvania, is exercisable at our cost plus, in the case of direct property sales, a specified premium, and is subject to specified exceptions. W e serve as operator ofthe properties covered by the Reliancejoint venture, with Reliance having the right to assume operatorship of60% of undeveloped acreage in portions of central Pennsylvania and until September 2014 to purchase all of our 40% interest in such acreage at a specifiedprice. Operations under the Reliancejoint venture will generally be required to conform to a budget approved byanoperatingcommitteethatincludesrepresentativesofbothparties, subjecttoexceptions,includingthose for soleriskoperations and inthe event ofdefaultsbytheparties. Thepartieshave also generally agreedto certainrestrictionsregarding solerisk operations and other operations.
Barnett Shale W e have been operating in the Barnett Shale since 2003.As ofDecember 31, 2012, we held interests in approximately 1 1,788 gross (9,615 net) acres, 85 gross (54.9 net) producing wells and 1 gross (1.0 net) wells that were drilled but waiting on completion. Of these wells, we operated 72 gross (50.3 net) producing wells and 1 gross (1.0 net) wells drilled and waiting on completion. During 2012, we drilled 6 gross (1.7 net) wells, of which we operated 1 gross (1.0 net) wells, and completed and brought on production 10 gross (4.1 net) wells. Approximately 90% of our 1 1,788 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. Our 2012 production in the Barnett Shale was 25.4 Bcfe, a 29% decrease from 201 1 production of35.7 Bcfe, primarily related to the sale ofa substantial portion ofour Barnett Shale properties in the second quarter of2012. T otal proved reserves for the Barnett Shale were 303.5 Bcfe at December 31, 2012 all ofwhich was natural gas. As ofDecember 31, 2012, we were not operating any drilling rigs in the Barnett Shale.W e completed the hydraulic fracturing ofone well in first quarter 2013 and currently expect only minimal expenditures in the Barnett Shale in 2013 due to non-operated drilling and completion costs.
In April 2012, we sold a substantial portion of our Barnett Shale properties to an af filiate ofAtlas Resource Partners, L.P

. (“Atlas”). Net proceeds received from the sale were approximately $187.4 million , which represents an agreed upon purchase price of approximately $190.0 million less net purchase price adjustments.
Business Strategy Measur ed Gr owth Thr ough the Drillbit Our objective is to increase value through the execution ofa business strategy focused on organic growth through the drillbit. Key elements of our business strategy include:

• Gr owPrimarily Thr

oughDrilling. W

epursue atechnology-driven exploration drillingprogram.W e generate exploration prospects through geological and geophysical analysis of3-D seismic and other data. Our ability to successfully define and drill exploratory prospects is demonstrated by our 99% apparent drilling success rate in the Barnett Shale, Eagle Ford Shale, Marcellus Shale andNiobrara Formation areas since our entrance into suchplays.W e have shown consistent
success in rapidly growing oil and gas reserves and production in our oil and gas focused resource plays. Additionally , we believe our success and ability to execute our growth strategy is demonstrated by our ability to attractjoint venture partners in our existing acreage in the Eagle Ford, Marcellus and Utica Shales and the Niobrara Formation.

• Pursue Gr

owth in Crude Oil andLiquids-Rich Plays. Since April 2010, we have pursued a growth strategy in crude oil and liquids-rich plays driven by the attractive economics associated with those commodities. By focusing on and implementing this strategy , our crude oil revenue as a percentage oftotal revenues has increased significantly from 10% for the year ended December 31, 2010 to 78% for the year ended December 31, 2012. Additionally , over 67% of our10

2013 U.S. drilling and completion capital expenditure plan is directed towards opportunities that we believe are predominantly prospective for crude oil and liquids development.

• Contr

ol Operating and Capital Costs. W e emphasize ef

ficiencies to lower our costs to find, develop and produce our oil and gas reserves. This includes concentrating on our core areas, which allows us to optimize drilling and completion techniques aswell asbenefit from economies ofscale.In addition, aswe operate a significantpercentage ofourproperties, the majority ofour capital expenditure plan is discretionary allowing us the ability to reduce or reallocate our spending in response to changes in market conditions. For example, our discretionary capital spending has been strategically redeployed to pursue growth in crude oil and liquids-rich plays.

• Maintain OurFinancialFlexibility

. W e are committedtopreserving our financial flexibility

.W ehavehistorically funded
our capital program with a combination of cash generated from operations, proceeds from the sale of assets, proceeds from sales ofsecurities, proceeds, payments or carried interest from ourjoint ventures and borrowings under our senior secured revolving credit facility

.
• Utilize Our Experience as a T echnical Advantage. W

e believe we have developed a technical advantage from our extensive experience drilling over 450 horizontalwells in the Barnett, Eagle Ford and Marcellus Shales and theNiobrara Formation, which has allowed our management, technical staf fand field operations teams to gain significant experience in resource plays. W

e are now leveraging this advantage in our existing and other shale trends, including the Utica Shale. W eplan to focus substantially all ofour capital expenditures in these core areas,wherewehave acquired, or are acquiring significant acreage positions and a large prospect inventory

.
• Maintain a ConservativeExploration andDevelopmentPortfolio. W e continueto focus our exploration ef fort and capital program on resource plays where individual wells tend to have lower risk, such as our operations in the Eagle Ford Shale and the Niobrara Formation.

• Manage Risk Exposur e. W e seek to limit our financial risks, in part by seeking well-funded partners to ensure that we are able to move forward on projects in a timely manner
. Ourjoint ventures with Reliance in most ofPennsylvania, with GAILintheEagleFord Shale andwiththe OILJVPartners andHaimo intheNiobraraFormation areprominent examples ofthis strategy

. W

e also attempt to limit our exposure to reductions in commodity prices by actively hedging production ofboth crude oil and natural gas. Our current long-term strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to 60 months.
Our Competitive Strengths W e believe we have the following competitive strengths that will support our ef forts to successfully execute our business strategy:

• Lar ge inventory ofoil-focused drilling locations. W e have developed a significant inventory offuture drilling locations, primarily in our well-established position in LaSalle and McMullen counties in the Eagle Ford Shale and W eld and Adams counties in theNiobrara Formation.As ofDecember 31, 2012,we owned leases covering approximately 208,545 gross acres in our focus areas ofthe Eagle Ford Shale and the Niobrara Formation. At December 31, 2012, we also had
a substantial inventory ofalready drilled wells that were waiting on completion, including 19 gross (15.8 net) wells in the Eagle Ford Shale and 2 gross (0.6 net) wells in the Niobrara Formation. Approximately 54% of our estimated U.S. provedreserves atDecember 31, 2012 wereundeveloped. In 2012, our crude oilrevenue as apercentage oftotalrevenues was 78%

.
• Successful drilling history

. W e follow a disciplined approach to drilling wells by applying proven horizontal drilling and hydraulic-fracturing technology

. Additionally , we rely on advanced technologies such as 3-D seismic and microseismic analysis to better define geologic risk and enhance the results of our drilling ef forts.

• Experiencedmanagement andpr ofessional workfor

ce. W e employ 54 oil and gas professionals, including geophysicists, petrophysicists, geologists, petroleum engineers and production and reservoir engineers and technical support staf f, who have an average of over 19 years of experience. W e believe our experience and expertise, particularly as they relate to successfully identifying and developing resource plays, is a competitive advantage.

• Operationalcontr

ol. As ofDecember 31,2012,we operated approximately 81% ofthewells inwhichweheld an interest. Of those wells we operate, we hold an average interest of approximately 73%

. Our significant operational control provides us with the flexibility to align capital expenditures with cash flow and control our costs as we are generally able to adjust drilling plans in response to changes in commodity prices. Exploration Approach Our exploration strategy in our shale resource plays has been to accumulate significant leasehold positions in areas with known shale thickness and thermal maturity in the proximity ofknown or emerging pipeline infrastructures. A component ofour1 1

exploitation strategy is to first identify and acquire surface tracts or “well pads” from which multiple wells can be drilled. W e then seek to acquire contiguous lease blocks in the areas immediately adjacent to these well pads that can be developed quickly

. W e 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 Eagle Ford Shale, Niobrara Formation, 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 depressed levels of natural gas prices, we sometimes seek to reduce costs by deferring drilling or drilling more wells on units where we hold a lower working interest than our historic average. In addition,
we seek to enter intojoint ventures with well-funded partners that will pay a disproportionate share ofthe drilling and completion costs ofwells that we drill. For example, in 2012, we sold 30% ofour interests in certain ofour Niobrara Formation properties to theOILJVPartners,withtheOILJVPartnersagreeingtopay 50%ofcertainofourdrillingandcompletioncostsuptoapproximately $41.25 million, which we currently expect to fully utilize or receive by the end ofthe first quarter of2014. In 201 1, 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 was fully utilized in 2012. In 2010, we sold 20% of our interests in
our Pennsylvania properties to Reliance who agreed to pay 75% ofcertain ofour drilling and completion costs up to approximately $52.0 million, which was fully utilized by the end ofthe fourth quarter of2012. 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 completion and pipeline connection costs of our horizontal wells to coincide with periods of lower services costs.
W e 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 ofhorizontal wells, because they allow us to evaluatethermalmaturity androckproperty data,while alsopermittingustotestvarious completiontechniqueswithoutincurring the cost of drilling a substantial number ofhorizontal wells. As discussed above, we have also shifted our focus toward crude oil and liquids-rich plays to take advantage ofthe attractive economics associated with those commodities.
W e 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.” W e complement
our exploratory drilling portfolio through the use ofthese outside sources ofproject 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. Operating Approach Ourmanagementteamhasextensiveexperienceinthedevelopmentandmanagementofexplorationanddevelopmentprojects in the Barnett Shale, onshore Gulf Coast and, more recently , the Marcellus Shale, Eagle Ford Shale and Niobrara Formation. W e believe that the experience we have gained in the Barnett, Eagle Ford and Marcellus Shales, along with our extensive experience in hydraulic fracturing and horizontal drilling technologies and the experience ofour management in the development, processing and analysis of 3-D projects and data will play a significant part in our future success. W e 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 ofDecember 31, 2012, we operated 300 gross (218.4 net) producing oil and gas wells. W e generally seek to control operations for most new exploration and development taking advantage ofour technical staf fexperience in horizontal drilling and hydraulic fracturing. During 2012, we operated all 59 ofthe gross wells drilled in the Eagle Ford Shale, 38 ofthe 39 gross wells drilled in the Marcellus Shale, 23 ofthe 26 gross wells drilled in the Niobrara, and 1 ofthe 6 gross wells drilled in the Barnett Shale. W orking Interest andDrilling in ProjectAreas 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. W e 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 ofworking interest.12

Additional Oil and Gas Disclosures Proved Oil and Gas Reserves The following table sets forth our estimated net proved oil and gas reserves and the PV -10 value of such reserves as of December 31, 2012

. Over 99% of the reserve data and the present value as of December 31, 2012 were prepared by LaRoche Petroleum Consultants,Ltd. andR yder Scott CompanyPetroleumEngineers.For furtherinformation concerningthese independent third party engineers’ estimates of our proved reserves at December 31, 2012, 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 ofthe first day ofthe month oil and gas prices for each month in the prior twelve-month period ended December 31, 2012, 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 15. Supplemental Disclosures About Oil and Gas Producing Activities (Unaudited)” ofthe Notes to our Consolidated Financial Statements. Summary of Proved Oil and Gas Reserves as of December 31, 2012 Based on A

verage 2012Prices (Dollars in thousands)
Oil, Condensate and Natural Gas Liquids (MBoe) Natural Gas (MMcf) T otal (MBoe) (1) PV -10 V alue (2) (3) U.S.Developed 14,295 229,539 52,552 $ 739,480 Undeveloped 30,163 194,134 62,519 672,813 Total Proved 44,458 423,673 115,071 1,412,293 U.K. North Sea (discontinued operations) Developed 5,241 4,664 6,018 441,597 Undeveloped

— — — — Total Proved 5,241 4,664 6,018 441,597 W orldwide Developed 19,536 234,203 58,570 1,181,077 Undeveloped 30,163 194,134 62,519 672,813 T otal Proved 49,699 428,337 121,089 $ 1,853,890

(1) Barrel of oil equivalents are determined using the ratio of 6 Mcf ofnatural gas to 1 Bbl of crude oil or 1 Boe ofnatural gas liquids which represents their approximate energy content. Despite holding this ratio constant at six Mcfto one Bbl, current prices are 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

. (2) The PV

-10 value as ofDecember 31, 2012 is pre-tax and was determined by using the average ofoil and gas prices at the beginning ofeach month in the twelve-month period prior to December 31, 2012, which averaged $101.35 per Bbl ofoil, $32.12 per Bbl ofnatural gas liquids and $1.95 per Mcfofnatural gas in the United States and $1 1 1.21 per Bbl ofoil and $13.32 per Mcfofnatural gas for the U.K. North Sea. Management believes that the presentation of PV -10 value is considered a non-U.S. GAAP financial measure as defined in Item 10(e) of Regulation S-K. Therefore, we have included a reconciliation ofthe measure to the most directly comparable U.S. GAAP financial measure (standardized measure of discounted future net cash flows in footnote (3) below). Management believes that the presentation of PV -10 value provides useful information to investors because it is widely used by analysts and investors in evaluating oil and gas companies. Because many factors that are unique to each individual company may impact the amount offuture income taxes to be paid, the use ofthe pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative monetary significance ofour oil and gas properties. Further, investors may utilize the measure as a basis for comparison ofthe relative size and value of our reserves to other oil and gas companies. Management also uses this pre-tax measure when assessing the potential return on investment related to its oil and gas properties and in evaluating acquisitions. The PV -10 value is not a measure offinancial or operating performance under U.S. GAAP , nor is it intended to represent the current market value ofthe estimated oil and gas reserves owned by us. PV -10 value should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under U.S. GAAP

. (3) Future income taxes and present value discounted (10%) future income taxes were $764.3 million and $435.5 million, respectively

. Accordingly

, the after-tax PV

-10 value ofT

otal Proved Reserves (or standardized measure ofdiscounted future net cash flows) is $1,418.4 million

.13

Pr oved Undeveloped Reserves United States. At December 31, 2012 and 201 1 , we had 62.5 MMBoe and 76.7 MMBoe of proved undeveloped reserves, respectively

. In 2012, we (a) added 17.2 MMBoe, which included 24.1 MMBoe, 12.3 MMBoe, and 0.8 MMBoe of proved undeveloped reserves as a result ofdrilling and additional of fset locations in the Marcellus Shale, Eagle Ford Shale and Niobrara Formation, respectively

, (b) converted a net of9.5 MMBoe ofreserves from proved undeveloped to proved developed, primarily in the Eagle Ford Shale and Marcellus Shale and (c) sold 22.6 MMBoe ofproved undeveloped reserves in the Barnett Shale.
Costs incurred relating to the development ofproved undeveloped reserves were approximately $227.0 million in 2012, as compared to $57.0 million in 201 1

. Costs incurred relating to the development of proved undeveloped reserves are currently projected to be approximately $356.3 million in 2013, $313.8 million in 2014, and $196.1 million in 2015.All proved undeveloped
reserves drilling locations are scheduled to be drilled within five years. U.K. North Sea

. In 2012, we converted 2.9 MMBoe ofreserves from proved undeveloped to proved developed.
Costs incurred relating to the development of proved undeveloped reserves were approximately $35.2 million in 2012, as compared to $38.8 in 201 1

. As a result ofthe sale on February 22, 2013 of Carrizo UK, and its interest in the Huntington Field,
we no longer own any proved reserves in the U.K. North Sea.
Other Reserve Matters. No estimates ofproved 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.” Over 99% 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. RiskFactors—W e depend on successful exploration, development and acquisitionstomaintainreserves andrevenue 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—W e 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., R yder Scott Company Petroleum Engineers and
our internal reserve engineers each used the price based on the unweighted average ofoil and gas prices at the beginning ofeach month in the twelve-month period ended December 31, 2012, adjusted for basis and quality dif ferentials. 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, 2012

. There can be no assurance that all ofthe 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 orjudicially enforced.
LaRoche Petroleum Consultants, Ltd. determined 50.6 MMBoe, or 42% of our proved reserves (all ofwhich were located inthe Barnett Shale), fortheyear ended December 31, 2012

. R yder Scott Company Petroleum Engineers determined 69.5 MMBoe, or 57% of our proved reserves, for the year ended December 31, 2012

. Qualifications ofThir

d Party Engineers As discussed above, we engaged LaRoche Petroleum Consultants, Ltd. and R yder Scott Company Petroleum Engineers, independent third party reserve engineers, to perform independent estimates of over 99% 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 ofPetroleum Engineers. None ofthese firms own an interest in our properties
or is employed on a contingent fee basis.
Internal Contr

ols A significant component of our internal controls in our reserve estimation ef fort is our practice ofusing independent thirdparty reserve engineering firms to determine over 99% of our year-end reserves. The qualifications of each of these firms are discussed above under “Qualifications ofThird 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 and for the portion of reserves estimates not prepared by third party14

engineers. Each of these individuals has over 26 years of experience in the petroleum industry and extensive experience in the estimation ofreserves and the review ofreserve reports prepared by third party engineering firms.
Thesethree individuals alongwith other Companypersonnel,reviewthe inputs and assumptionsmade inthereserve 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 Of ficer, who is a registered petroleum engineer and holds a B.S. in Mechanical Engineering from the University of Colorado, and the Chief Operating Of ficer, who holds a B.S. in Petroleum Engineering from T exas A&M University

. Oil and Gas Reserve Replacement Finding and developing suf ficient amounts ofoil 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 ofmore than of fsetting 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. W e 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. W

e 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 ittypicallyvarieswidelybased onthe extent andtiming ofnew discoveries andproperty acquisitions.Itspredictive 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 ofnew reserves, it cannot be used as a measure ofvalue 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. Our reserve replacement ratio may be calculated dif ferently from the comparable measure ofother oil and gas companies. It is relevant to note the percentage ofour reserves that were producing in the United States was 45% in 2012, 41% in 201 1 and 45% in 2010

. Set forth below is our reserve replacement ratio for the years ended December 31, 2012, 201 1 and 2010

. W e also present the reserve replacement ratio, as adjusted for U.S. property sales, primarily the sale ofnatural gas reserves toAtlas in 2012 and KKR in 201 1. W e have no reserves that are producing in the U.K. North Sea. Year Ended December 31, 2012 2011 2010 U.S. Reserve replacement (267)% 308% 650% Reserve replacement adjusted for property sales 303 % 628% 650%

W orldwide Reserve replacement (269)% 311% 749% Reserve replacement adjusted for property sales 301 % 631% 749%15

Oil and Gas V

olumes, Prices and Production Expense The following table sets forth certain information regarding the production volumes of, average sales prices received for and average production costs associated with our sales of oil and gas for the periods indicated. Year Ended December 31, 2012 2011 2010 Production volumes - Oil and condensate (MBbls) 2,862 802 176 NGLs (MBoe) 305 210 277 Natural gas (MMcf) 37,612 38,991 34,092 T otal Natural gas and NGLs (MMcfe) 39,442 40,251 35,754 T otal barrels of oil equivalent (MBoe) 9,436 7,511 6,135

Production volumes per day

- Oil and condensate per day (Bbls/d) 7,820 2,197 482 NGLs per day (Boe/d) 833 575 759 Natural gas per day (Mcf/d) 102,765 106,825 93,403 Total Natural gas and NGLs per day (Mcfe/d) 107,765 110,277 97,956 T otal barrels of oil equivalent per day (MBoe) 25,781 20,578 16,808

A verage realized prices

- Oil and condensate ($ per Bbl) $ 99.97 $ 94.14 $ 78.74 NGLs ($ per Boe) 34.86 50.30 38.51 Natural gas ($ per Mcf) 1.90 2.98 3.33

A verage costs ($ per Boe)(1) $ 3.33 $ 2.76 $ 3.12

(1) Includes direct lifting costs (labor, repairs and maintenance, materials and supplies), workover costs, transportation costs and the administrative costs ofproduction of fices, and insurance and property

.16

Acquisition, Exploration andDevelopment Capital Expenditures and Finding andDevelopment Costs Our finding and development costs ($ per Boe) as adjusted for property sales for the years ended December 31, 2012, 201 1 and 2010 are reflected in the table below

. Year Ended December 31, 2012 2011 2010 (In thousands, except per Boe amounts) U.S. Unproved property acquisition costs $ 139,344 $ 108,212 $ 126,783 Exploration costs 557,523 374,366 134,487 Development costs 25,756 19,769 62,952 Asset retirement obligations 2,401 3,369 1,031 T otal costs incurred (1) $ 725,024 $ 505,716 $ 325,253

A verage all-sources finding cost $ 23.35 $ 9.62 $ 9.64 A verage finding and development cost (2) 20.78 9.37 10.72 A verage drilling finding cost 17.04 7.32 5.89

W orldwide Unproved property acquisition costs $ 150,479 $ 109,216 $ 127,589 Exploration costs 557,523 374,366 134,487 Development costs 60,981 58,544 68,327 Asset retirement obligations 3,437 6,018 1,031 T otal costs incurred (1) $ 772,420 $ 548,144 $ 331,434

A verage all-sources finding cost $ 24.84 $ 10.47 $ 8.33 A verage finding and development cost (2) 22.32 10.26 9.32 A verage drilling finding cost 18.45 8.17 5.12

(1) T otal costs incurred include capitalized overhead of$1 1.8million, $9.6million and $5.3million and exclude capitalized interest onunproved properties of $24.8 million, $23.4 million and $20.7 million for the years ended December 31, 2012, 201 1 and 2010, respectively

. (2) Comprised of all exploration and development costs incurred in the year plus the leasehold and seismic costs attributable to all proved drilling locations additions in the year
. For the three-year period ended December 31, 2012, our total cost for exploration, development and acquisition activities
was approximately $1,652.0 million. T otal exploration, development and acquisition activities for the three-year period ended December 31, 2012 have added approximately 1 15.6 MMBoe of net proved reserves, as adjusted for property sales, at an allsources finding cost of $14.29 per Boe.
Our finding and development cost computation excludes net additions (reductions) to total future development costs with respect to proved undevelopedproperties necessary to convert thoseproperties into provedproducing properties of$214.0 million, $531.3 million and $379.0 million at December 31, 2012, 201 1 and 2010, respectively , and includes net additions to proved undeveloped reserves of22.0 MMBoe, 14.4 MMBoe and 22.1 MMBoe for the years ended December 31, 2012, 201 1 and 2010, respectively

. Accordingly , had we included future development costs in our computations, the average all-sources finding costs would have been $16.98, $21.50 and $14.64 per Boe for the years ended December 31, 2012, 201 1 and 2010, respectively

. Y ear on year, U.S. future development costs decreased in 2012 by approximately $181.3 million net, largely comprised of (1) a $19.4 million increase in the Eagle Ford Shale comprised of (a) a $288.4 million increase for the development costs attributable to additions of 17.3 MMBoe ($16.67/Boe) ofproved undeveloped reserves and (b) a net $268.9 million decrease due to development costs incurred in 2012 and revisions of previous estimates and (2) a $201.3 million net decrease in the Barnett Shale primarily due to a net $190.4 million reduction associated with a decrease of 194.6 Bcfe ($0.98/Mcfe), primarily from wells sold during the year or that are currently not in the drilling plan as we shift our drilling ef forts to crude oil and liquids-rich plays. Our finding and development costs exclude the ef fect of acquisitions or dispositions.17

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 offactors including the extent and timing ofnew discoveries and property acquisitions. Due to the timing ofproved reserve additions and timing ofthe related costs incurred to find and develop our reserves, our all-sources finding cost measure often includes quantities ofreserves for which a majority ofthe 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 dif ferently than the comparable measure ofother oil and gas companies. DrillingActivity The following table sets forth our drilling activity for the years ended December 31, 2012, 201 1 and 2010 by geographical
area. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein.
Year Ended December 31, 2012 2011 2010 Gross Net Gross Net Gross Net U.S. Exploratory W

ells - Productive 69 31.8 88 38.4 57 28.9 Exploratory W

ells - Nonproductive 1 0.5 1 0.5 3 2.3 Development W

ells - Productive 60 37.7 33 15.0 28 13.4 Development W

ells - Nonproductive

— — — — — —
U.K. North Sea (discontinued operations) Exploratory W

ells - Productive

— — — — — — Exploratory W

ells - Nonproductive 1 0.2

— — — — Development W

ells - Productive 2 0.3 2 0.3

— — Development W

ells - Nonproductive

— — — — — —

W orldwide Exploratory W

ells - Productive 69 31.8 88 38.4 57 28.9 Exploratory W

ells - Nonproductive 2 0.7 1 0.5 3 2.3 Development W

ells - Productive 62 38.0 35 15.3 28 13.4 Development W

ells - Nonproductive

— — — — — —
The wells are in various stages of development or stages ofproduction.
As ofDecember 31, 2012, we are in the process ofdrilling 6 gross (4.7 net) wells in the United States that are not included in the table above. W

e have no current plans to drill a well outside ofthe United States in 2013.
Productive W

ells The following table sets forth the number ofproductive oil and gas wells in which we owned an interest as ofDecember 31, 2012

. Company Operated Non-Operated Total Gross Net Gross Net Gross Net Oil 186 151.3 7 1.2 194 161.3 Natural gas 114 67.1 65 8.3 179 75.4 T otal 300 218.4 72 9.5 372 227.918

As ofDecember 31, 2012, we did not have any producing wells in the U.K. North Sea. For further information concerning the sale of the U.K. North Sea assets see “Note 3. Assets Held for Sale” and “—Discontinued Operations” of the Notes to our Consolidated Financial Statements. Acreage Data The followingtable sets forth certain informationregarding our developed andundeveloped lease acreage as ofDecember 31, 2012

. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would permit production ofoil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to apoint that wouldpermitproduction ofoil and gas in commercial quantities whether or not the acreage containsproved reserves.
Developed Acreage Undeveloped Acreage Total Gross Net Gross Net Gross Net U.S. Eagle Ford Shale - T

exas 28,763 21,281 66,836 27,722 95,599 49,003 Niobrara Formation - Colorado 16,774 6,975 96,172 29,238 112,946 36,213 Barnett Shale - Texas 10,641 8,839 1,147 776 11,788 9,615 Marcellus Shale New Y ork 2,117 158 29,407 6,392 31,524 6,550 Pennsylvania 4,694 1,589 121,365 42,906 126,059 44,495 W est V irginia 893 435 61,875 27,250 62,768 27,685 V irginia 53 27 3,495 1,748 3,548 1,775 Marcellus Shale T

otal 7,757 2,209 216,142 78,296 223,899 80,505 Other (1) 8,362 6,805 197,732 122,653 206,094 129,458 T otal U.S. 72,297 46,109 578,029 258,685 650,326 304,794 U.K. North Sea (discontinued operations) 1,767 265 121,179 55,769 122,946 56,034 W orldwide 74,064 46,374 699,208 314,454 773,272 360,828

(1) “Other” includes other non-resource plays in T exas and Louisiana; Utica Shale in Ohio and Pennsylvania; Fayetteville Shale in Arkansas; theNewAlbany Shale in Kentucky and Illinois; the Floyd/Neal Shale in Mississippi; the Barnett/W oodford in W

est T exas andNew Mexico; and the Bakken in North Dakota.
Our lease agreements generally terminate ifproducing 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). Ifno production is established on our leases that are in their primary term, approximately 30% ofour acreage will expire in 2013, 6% will expire in 2014 and 32% will expire in 2015. Marketing Ourproduction is marketed to thirdparties consistent with industrypractices. T ypically , our oil and gas is sold at the wellhead to unaf filiated third parties. Oil is sold at field-posted prices plus or minus a bonus and natural gas is sold under contract at a negotiated price which is based on published prices for specified locations or pipelines, such as W AHA, Houston Ship Channel, Dominion T

ransmission and Tx. Eastern, Zone M-3, and then discounted by the purchaser 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 ofnatural gas and prevailing supply and demand conditions. W e have made the strategic decision to sell as much of our naturalgasproduction atthewellhead aspossible, sothatwe can concentrateouref forts andresources on exploration andproduction which we believe are more consistent with our competitive expertise, rather than in natural gas pipeline operation, natural gas marketing and sales. In each case we sell at competitive market prices based on a dif ferential to several sales points. W e do not believe the loss of any one of our purchasers would materially af fect our ability to sell the oil and gas we produce. W e believe other purchasers are available in all our areas of operations.
Our marketing objective is to receive competitive wellhead prices for our product. W e are aided by the presence ofmultiple outlets near our production in the Eagle Ford and Barnett Shale areas and, beginning in late fourth quarter 2012, a second outlet for our production in the Marcellus Shale.
There are a variety of factors that af fect the market for oil and gas generally , including:19

• demand for oil and gas;

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

• the proximity and capacity ofnatural gas pipelines and other transportation facilities;

• the marketing of competitive fuels; and

• the ef

fects of state and federal regulations on oil and gas production and sales.
See “Item 1A. Risk Factors—Oil and gas prices are highly volatile, and lower oil and gas prices will negatively af fect our financial position, planned capital expenditures and results of operations,” “—W e are subject to various environmental risks and governmental regulations, including those relating to benzene emissions, hydraulic fracturing and global climate changes, and future regulations may be more stringent resulting in increase operating costs and decreased demand for oil and gas that we produce,” and “—Ifour 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 receive market prices for our oil and natural gas may be adversely af

fected by pipeline and gathering system capacity constraints.”
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. W e also conduct an active hedging program at a corporate level 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 DiscussionandAnalysisofFinancialConditionandResultsofOperations—SummaryofCriticalAccountingPolicies—Derivative Instruments,” “Item 7A. Qualitative and Quantitative Disclosures About Market Risk—Commodity Risk,” and “Item 1A. Risk Factors — W

e may continue to enter into derivative transactions to manage the price risks associated with our production, which may expose us to risk of financial loss and limit the benefit to us of 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 oil and natural gas and receive market prices for our oil and natural gas may be adversely af fected by pipeline and gathering system capacity constraints.” Competition and T

echnological Changes W e encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of exploratoryprospects andprovenproperties.Many ofourcompetitors arelarge,well-established companiesthathavebeen engaged in the oil and gas business for much longer than we have and possess substantially larger operating staf fs and greater capital
resources than we do. W e 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 af fected. Regulation Oil and gas operations are subject to various federal, state, local and international environmental regulations that may change fromtimetotime,includingregulationsgoverning oil andgasproduction andtransportation, federal and stateregulationsgoverning environmental quality and pollution control and state limits on allowable rates of production by well or proration unit. These regulations may af

fect 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 ofoil 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,providenondiscriminatory accessto common carrierpipelines and control contamination ofthe environment.Pipelines
are subject to thejurisdiction ofvarious federal, state and local agencies. W e are also subject to changing and extensive tax laws, the ef fects ofwhich cannot be predicted.
The following discussion summarizes theregulation oftheUnited States oil and gas industry

.W ebelievewe 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 af fect our results of operations and financial condition. The following discussion is20

not intended to constitute a complete discussion ofthe various statutes, rules, regulations and governmental orders to which our operations may be subject. Regulation ofNatural Gas and Oil Exploration and Pr oduction Our operations are subject to various types ofregulation at the federal, state and local levels that:

• require permits for the drilling ofwells;

• mandate that we maintain bonding requirements in order to drill or operate wells; and regulate the location ofwells, the method ofdrilling and casing wells, the surface use and restoration ofproperties upon whichwellsaredrilled,thepluggingandabandoningofwellsandthedisposaloffluidsusedinconnectionwithoperations.
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 ofwells 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 Colorado) allow the forced pooling or integration of tracts to facilitate exploration while other states (including T exas) rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary , it may be more dif

ficult to form units and therefore more dif ficult to develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum rates ofproduction from oil and gas wells generally prohibit the venting or flaring ofnatural gas and impose specified requirements regarding the ratability ofproduction. The ef fect 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 ofdoing business and, consequently , af fects our profitability

. Because these laws and regulations are frequently expanded, amended and reinterpreted, we are unable to predict the future cost or impact of complying with such regulations. Regulation ofSales and T ransportation ofNatural Gas Federal legislation and regulatory controls have historically af fected the price ofnatural 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 forresale ofnatural gas. Ef fective January 1, 1993, the Natural Gas W ellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” ofnatural gas, including all ofour sales ofour own production. As a result, all ofour domestically produced natural gas is sold at market prices, subject to the terms of any private contracts that may be in ef fect. The FERC’s jurisdiction over interstate natural gas transportation, however, was not af fected by the Decontrol Act.
Under the NGA, facilities used in the production or gathering ofnatural gas are exempt from the FERC’s jurisdiction. W e 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 ormore ef ficiently than waiting on anunrelated 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”) ofthe T exas Utilities Code. Both GURA and the Cox Act prohibit unreasonable discrimination in the transportation ofnatural gas and authorize the T

exas 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,thenegotiatedrate is substantiallythe same asthatnegotiatedwith at leasttwo other customersunder similar conditions,
or suf ficient 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 ofthirdparty pipelines and facilities could indirectly af fect our ability to market ourproduction. Beginning in the 1980s the FERC initiated
a series ofmajorrestructuring ordersthatrequiredpipelines, among otherthings,toperform open accesstransportation, “unbundle” their sales and transportation functions, and allow shippers to release their pipeline capacity to other shippers. As a result ofthese 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 ofcounterparties. W e believe these changes generally have improved our access to marketswhile, at the same time, substantially increasing competition in thenatural gas marketplace. Itremains tobe seen,however, what ef fect the FERC’s other activities will have on access to markets, the fostering ofcompetition and the cost ofdoing business.21

W e cannot predict what new or dif ferent regulations the FERC and other regulatory agencies may adopt, or what ef fect subsequent regulations may have on our activities.
In the past, Congress has been very active in the area ofnatural gas regulation. However, the more recent trend has been in favor ofderegulation or “lighter handed” regulation and the promotion ofcompetition in the gas industry

. In light ofthis 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 ofnatural 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 ofinformation about the availability and prices ofgas sold and new regulations that require both interstatepipelines and certainnon-interstatepipelinestopost daily informationregardingtheir 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 ofthe NGA and the FERC’s regulations to up to $1.0 million per day for each violation.
Oil Price Contr

ols and T ransportation Rates Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The price we receive from the sale ofthese products may be af fected by the cost oftransporting the products to market. Much ofthat transportation is through interstate common carrier pipelines. Ef fective as ofJanuary 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 oftransporting 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, 201 1. W e are not able at this time to predict the ef

fects ofthis 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 af fect 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 ef fect, if any

, such proposals might have on us. Similarly , we cannot predict whether or to what extent the trend toward federal deregulation ofthe petroleum industry will continue, or what the ultimate ef fect
on our sales of oil, gas and other petroleum products will be.
Envir onmental Regulations Our operations are subject to numerous international, federal, state and local laws and regulations governing the discharge ofmaterials 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 ofvarious substances that can bereleasedintothe environmentin connectionwith drilling andproduction activities,limit orprohibit drilling activities on specified landswithinwilderness,wetlandsandotherprotectedareas,requireremedialmeasurestomitigatepollutionfromformeroperations, 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 ofadministrative, civil and criminal penalties, imposition of investigatory or remedial obligations or the issuance of injunctions prohibiting or limiting the extent ofour operations. Public interest in the protection ofthe 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 ofdoing business and consequently af fecting our profitability

. T o 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 af fected.
W e generate waste that may be subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The U.S. Environmental ProtectionAgency (“EP A”), and various state agencies have limited the approved methods ofdisposal 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.
W e 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 generally 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 has been taken for22

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 LiabilityAct (“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. CERCLA, also known as the “Superfund” law , and analogous state laws impose liability , without regard to fault or the legality ofthe original conduct, on specified classes ofpersons that are considered to have contributed to therelease ofa “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 ofthe hazardous substances found at the site. Persons who are or were responsible for releases ofhazardous substances under CERCLA may be subject tojoint and several liability for the costs ofcleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs ofcertain 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 EP A and states have developed and continue to develop regulations to implement these requirements. W e 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 airemission-relatedissues.Moreover,changesinenvironmentallawsandregulationsoccurfrequently ,and stricterlaws,regulations
or enforcement policies could significantly increase our compliance costs. Further, stricter requirements could negatively impact
our production and operations. For example, the T exas 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 inthe Barnett Shaleproduction area. These initiatives could leadtomore stringent airpermitting, increased regulation and possible enforcement actions at the local, state, and federal levels. Additionally , the EP A has finalized rules that establish new air emission control requirements for natural gas and natural gas liquids production, processing and transportation activities, including New Source Performance Standards to address emissions ofsulfur dioxide and volatile organic compounds,andNationalEmission StandardsforHazardousAirPollutantstoaddresshazardousairpollutantsfrequentlyassociated with gas production and processing activities.
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 (“OP A”) contains numerous requirements relating to the prevention of and response to oil spills into waters ofthe United States. The OP A subjects owners offacilities to strictjoint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs ofresponding to a release of oil to surface waters. The OP A also requires owners and operators of of fshore 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 shelfwaters 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 ifa formal risk assessment indicates that the increase is warranted. Noncompliance with OP A may result in varying civil and criminal penalties and liabilities. Our operations are also subject to the federal Clean W aterAct (“CW

A”) and analogous state laws. In accordance with the CW A, the State ofLouisiana issued regulations prohibiting discharges ofproduced water in state coastal waters ef fective July 1, 1997. Pursuant to other requirements ofthe CW A, the EP A has adopted regulations concerning discharges ofstorm waterrunof f. Thisprogram requires covered facilities to obtain individualpermits or seek coverage under an EP

A general permit. Like OP A, the CW

A and analogous state laws relating to the control of water pollution provide varying civil and criminal penalties and liabilities for releases ofpetroleum 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 — W e 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.”
W e also are subjectto avariety offederal, state, local and foreignpermitting andregistrationrequirementsrelatingtoprotection ofthe environment. W

e 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 ef fect on our financial position or results of operations.
Our of fshore 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.23

Global Climate Change There is increasing attention in the United States and worldwidebeingpaid to the issue ofclimate change and the contributing ef fect of greenhouse gas (“GHG”) emissions. On December 15, 2009, the EP A published a Final Rule, also known as the EP A ’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 EP A 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 Vprograms to apply to certain stationary sources ofGHG 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 EP A on a case-by-case basis. The EP A 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 gasprocessing,transmission,distributionand storagefacilities.Inaddition,theU.S.Congresshasconsideredanumberoflegislative proposals to restrict GHG emissions and more than 20 states, either individually or as part of regional initiatives, have begun taking actions to control or reduce GHG emissions. Moreover, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change,which establishes abinding set ofemissiontargets for GHGs,becamebinding on allthose countries that had ratified it. Ongoing international discussions following the United Nations Climate Change Conference in Doha, Qatar in December 2012 are exploring options to replace the Kyoto Protocol.While it is notpossible at this time topredict how regulation that may be enacted to address GHG emissions would impact our business, the modification ofexisting laws or regulations or the adoption ofnew laws or regulations curtailing oil and gas exploration in the areas ofthe United States or the North Sea in which
we operate could materially and adversely af fect 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 ef

fects offuture regulation, the meteorological ef fects ofglobal climate change could pose additional risks to our onshore and of

fshore operations in the form ofmore frequent and/or more intense storms and flooding, which could in turn adversely af

fect our cost of doing business.
T itle to Properties;Acquisition Risks W e 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 ef fect on our business and operations in such area, taken as a whole. For additional information, please see “Item 1A. Risk Factors—W e may incur losses as a result oftitle deficiencies.”
Customers For the year ended December 31, 2012, Flint Hills Resources, LP and Enterprise Products Operating, L.L.C. accounted for approximately 53% and 10%, respectively , of our oil and gas revenues. For the years ended December 31, 201 1 and 2010, DTE Energy T rading, Inc. accounted for approximately 43% and 63%, respectively ofour oil and gas revenues. W e do not believe the loss ofany one ofour purchasers would materially af fect our ability to sell the oil and gas we produce. W e believe other purchasers
are available in our areas of operations. See “Additional Oil and Gas Disclosures—Marketing.” Employees At December 31, 2012, we had 208 full-time employees. W e believe that our relationships with our employees are good.
In order to optimize prospect generation and development, we utilize the services ofindependent 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. W e believe that this use ofthird-party service providers has enhanced our ability to manage general and administrative expenses. Available Information Our website address is www.crzo.net. W e 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. W e 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. Y ou may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street NE, W ashington, D.C. 20549. Y

ou may obtain information regarding the Public Reference Room by calling the SEC at 1-800-SEC-0330.24

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

• Audit Committee Charter;

• Compensation Committee Charter;

• Nominating and Corporate Governance Committee Charter;

• Code ofEthics and Business Conduct; and

• Compliance Employee Report Line.
W e intend to satisfy the requirement under Item 5.05 of Form 8-K to disclose any amendments to our Code of Ethics and BusinessConductandanywaiverfromaprovisionofourCodeofEthicsbyposting suchinformationonourwebsiteatwww.crzo.net under “About Carrizo—Governance.” Glossary ofCertain Industry T erms The definitions set forth below shall apply to the indicated terms as used herein.All volumes ofnatural gas referred to herein
are stated at the legal pressure base ofthe state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances
are rounded to the nearest multiple or power often. Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons.
Bbls/d. Stock tank barrels per day

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

. One barrel ofoil equivalent. A Boe is determined using the ratio ofsix Mcfofnatural gas to one Bbl ofoil, 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

. Boe/d. Barrels of oil equivalent per day

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

est. An agreement under which one party (carrying party) agrees to pay for a specified portion or for all ofthe drilling and completion and operating costs of another party (carried party) on a property for a specified time in which both own a portion ofthe working interest. The carrying party may be able to recover a specified amount of costs from the carried party’s share ofthe revenue from the production ofreserves from the property

. Completion. The process of treating a drilled well followed by the installation ofpermanent equipment for the production of oil or 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 ofhydrocarbons 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 acr

eage. The number of acres assignable to productive wells. Developed oil and gas r

eserves. 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 ofthe required equipment isrelativelyminor comparedtothe cost ofanewwell; and (ii) through installed extraction equipment and infrastructure operational at the time ofthe reserves estimate ifthe extraction is by means not involving a well. Development Costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gatheringand storingtheoilandgas.Developmentcosts,includingdepreciationandapplicableoperatingcostsofsupportequipment and facilities and other costs ofdevelopment activities, are costs incurredto (i) gain accessto andpreparewell locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining,25

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 ofplatforms and ofwell equipment such as casing, tubing, pumping equipment, and the wellhead assembly , (iii) acquire, construct and install, production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage tanks, natural gas cycling andprocessingplants, and centralutility 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 extensionwell thatproves tobe incapable ofproducing either oil or gas in suf ficient quantities tojustify completion as an oil or gas well. Economicallypr

oducible. 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) ofRegulation S-X promulgated under the Securities Exchange Act of 1934, as amended. 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 gas in another reservoir

. Field. An area consisting ofa singlereservoir ormultiplereservoirs all grouped on orrelatedtothe same individual geological structural feature or stratigraphic condition, or both. 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, including all costs involved in acquiring acreage, geological and geophysical work and the cost of drilling and completing wells. Finding and development costs. Expressed in dollars per Boe or Mcfe. Finding and development cost metrics provide information as to the cost ofadding proved reserves from various activities. Calculated as capital costs incurred in the acquisition, exploration, development and revisions ofproved oil and natural gas reserves divided by proved reserve additions. Findinganddevelopmentcost- drilling

. Calculatedby dividingthe amount ofcosts incurred for exploration and development activities, by the amount ofproved reserve additions.
Gr oss acr es or gr oss wells. The total acres or wells, as the case may be, in which a working interest is owned. Hydraulicfracturing. Hydraulic fracturing is a well stimulation process using a liquid (usually water with an amount of chemicals mixed in) that is forced into an underground formation under high pressure to open or enlarge fractures in reservoirs with low permeability to stimulate and improve the flow ofhydrocarbons from these reservoirs. As the formation is fractured, a proppant (usually sand or ceramics) is pumped into the fractures to “prop” or keep them from closing after they are opened by the liquid. 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.
MBbls

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

. MBoe

. One thousand barrels of oil equivalent.
MBoe/d. One thousand barrels of oil equivalent per day

. Mcf. One thousand cubic feet ofnatural gas. Mcf/d. One thousand cubic feet ofnatural gas per day

. Mcfe. One thousand cubic feet equivalent, determined using the ratio ofsix Mcfofnatural gas to one Bbl ofoil, or condensate
or one Boe ofnatural gas liquids, which represents the approximate 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

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Mcfe/d. One thousand cubic feet equivalent per day

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

. One million barrels of oil equivalent.
MMBtu. One million British Thermal Units. MMcf. One million cubic feet. MMcf/d. One million cubic feet per day

. MMcfe. One million cubic feet equivalent, determined using the ratio ofsix Mcfofnatural gas to one Bbl ofoil, condensate
or natural gas liquids, which represents the approximate energy content ofoil, 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

. MMcfe/d. One million cubic feet equivalent per day

. Net acr es or net wells. The sum ofthe fractional working interests owned in gross acres or gross wells.
Pr oduction 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.
Pr oductive well. A well that is found to be capable ofproducing oil or gas in suf ficient quantities tojustify completion as an oil or gas well.
Pr oved developed r

eserves. Reserves that are both proved and developed.
Pr oved r eserves. Has the meaning given to such term in Rule 4-10(a)(22) ofRegulation S-X, which defines proved reserves as: The quantities ofoil and gaswhich,by analysis ofgeoscience and engineering data, canbe estimatedwithreasonable certainty tobeeconomicallyproduciblefromagivendate forward,fromknownreservoirs,andunderexistingeconomicconditions,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 ofwhether 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 ofa reservoir considered proved includes (i) the area identified by drilling and limited by fluid contacts, ifany , and (ii) adjacent undrilled portions ofthe reservoir that can, with reasonable certainty , bejudged 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 ofthe 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 ofthe 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,27

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.
Pr oved undeveloped r

eserves. Reserves that are both proved and undeveloped.
PV -10 V alue. 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 ofproved reserves, net ofestimated 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 ef

fect at the determination date, without giving ef fect 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. Ifprobabilistic 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 ofconfidence exists ifthe quantity is much more likely to be achieved than not, and, as changes due to increased availability ofgeoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimatedultimaterecovery (“EUR”)with time,reasonably certain EUR is much more likely to increase
or remain constant than to decrease. Recompletion. The completion for production ofan 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 ofdelivering 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 or gas, or both, that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Standar dized measur

e. The present value, discounted at 10%, offuture net cash flows from estimated proved reserves after income taxes, calculated holding prices and costs constant at amounts in ef fect on the date of the report (unless such prices or costs are subject to change pursuant to contractual provisions) and otherwise in accordance with the U.S. Securities Exchange Commission’s rules for inclusion ofoil and gas reserve information in financial statements filed with the U.S. Securities Exchange Commission.

“T ag along” rights. An agreement may provide that if one or more persons owning a majority (or some other specified portion) ofcertain interests desires to sell all (or some specified portion) oftheir interests in one or more related transactions, other
owners ofthe same or similar interests have the “tag along” right tojoin in the sale.
3-D seismic data. Three-dimensional pictures ofthe 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 acr

eage. 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 ofwhether such acreage contains proved reserves. Undeveloped oil and gas r eserves. 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 onundrilled acreage are limited to those directly of fsetting 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 ifa development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstancesjustify 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 ef fective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty

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W orking inter

est. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share ofproduction.
W orkover

. Operations on a producing well to restore or increase production.
Item 1A. Risk Factors Oil and gas prices are highly volatile, and lower oil and gas prices will negatively affect our financial position, planned capital expenditures and results of operations. 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. In the past, we have reduced or curtailed production to mitigate the impact of low oil and gas prices. Particularly in recent years, decreases in natural gas prices led us to suspend or curtail drilling and other exploration activities for natural gas. 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 oflow oil or gas prices may materially adversely af fect our financial position, liquidity (including
ourborrowing capacityunder ourrevolving credit facility), abilityto financeplanned capital expenditures andresults ofoperations.
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:

• the level of consumer product demand;

• the levels and location of oil and gas supply and demand and expectations regarding supply and demand, including the supply ofnatural gas due to increased natural gas production from resource plays;

• overall economic conditions;

• weather conditions;

• domestic and foreign governmental relations, regulations and taxes;

• the price and availability of alternative fuels;

• political conditions or hostilities and unrest in oil producing regions;

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

• the ability ofthe members ofthe Organization ofPetroleum Exporting Countries and other exporting nations to agree upon and maintain production constraints and oil price controls;

• technological advances af fecting energy consumption;

• speculation by investors in oil and gas; and

• variations between product prices at sales points and applicable index prices.
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 ofour 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 ofdrilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including:

• unexpected or adverse drilling conditions;

• elevated pressure or irregularities in geologic formations;

• equipment failures or accidents;

• adverse weather conditions;

• fluctuations in the price of oil and gas;

• surface access restrictions;

• loss oftitle or other title related issues;29

• compliance with governmental requirements; and

• shortages or delays in the availability of drilling rigs, crews and equipment.
Because we identify the areas desirable for drilling in 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 ofthe risks and uncertainties ofour business,
our future performance in exploration and drilling may not be comparable to our historical performance described herein.
W e may not adhere to our proposed drilling schedule. Our final determination of whether to drill any scheduled or budgeted wells will be dependent on a number of factors, including:

• the results of our exploration ef forts and the acquisition, review and analysis ofthe seismic data;

• the availability of suf ficient capital resources to us and the other participants for the drilling ofthe prospects;

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

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

• the availability of leases and permits on reasonable terms for the prospects. Although we have identified orbudgeted for numerous drilling prospects, we may not be able to lease or drill those prospects within our expected time frame or at all. W ells 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 ofseismic 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 expectationsbecause offuture uncertainties. In addition, our ability toproduce oil and gas may be significantly af fected by the availability and prices ofhydraulic fracturing equipment and crews.There can be
no assurance that these projects can be successfully developed or that any identified drill sites or budgeted wells will, if drilled, encounter reservoirs of commercially productive oil or gas. W e may seek to sell or reduce all or a portion of our interest in a project area or with respect to prospects or budgeted wells within such project area. 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 ofthe producer

. The reserve data included herein represents only estimates. Reservoir engineering is a subjective and inexact process ofestimating underground accumulations ofoil and gas that cannot be measured in an exact manner and is based
on assumptions that may vary considerably from actual results. Furthermore, dif ferent reserve engineers may make dif ferent estimates ofreserves and cash flows based on the same data. 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

, in recent years, there has been increased debate and disagreement over the classification ofreserves, with particular focusonprovedundevelopedreserves. TheinterpretationofSECrulesregardingtheclassificationofreservesandtheirapplicability in dif ferent situations remain unclear in many respects. Changing interpretations of the classification standards of reserves or disagreements with our interpretations could cause us to write-down reserves. As ofDecember 31, 2012, approximately 55% of our United States proved reserves were proved undeveloped and proved nonproducing. Moreover, some ofthe producing wells included in our reserve reports as ofDecember 31, 2012 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

. V olumetric analysis involves estimating the volume ofa reservoir based on the net feet ofpay ofthe structure and an estimation ofthe 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 ofreasonable certainty with respect to development plans for proved undeveloped reserves could cause the discontinuation ofthe classification ofthese reserves as proved.30

The discounted futurenet cash flows includedherein arenotnecessarily the same as the currentmarketvalue ofour 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 ofthe 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 af fected by factors such as:

• the actual prices we receive for oil and gas;

• our actual operating costs in producing oil and gas;

• the amount and timing of actual production;

• supply and demand for oil and gas;

• increases or decreases in consumption of oil and gas; and

• changes in governmental regulations or taxation.
In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliancewiththeFinancialAccounting StandardsBoardAccounting Standards CodificationT opic 932, “ExtractiveActivities —Oil and Gas” may not be the most appropriate discount factor based on interest rates in ef fect from time to time and risks associated with us or the oil and gas industry in general.
W e depend on successful exploration, development and acquisitions to maintain reserves and revenue in the future. In general, the volume ofproduction 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

. T o 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 af fected.
W e participate in oil and gas leases with third parties and these third parties may not be able to fulfill their commitments to our projects. W e 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 ofthe working interest. Financial risks are inherent in any operation where the cost ofdrilling, equipping, completing and operating wells is shared by more than one person. W e could be held liable forjoint activity obligations ofthe other working interest owners such as nonpayment of costs and liabilities arising from the actions ofthe 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 ofthese working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. Some of these working interest owners have experienced liquidity and cash flow problems. Theseproblems may lead theseparties to attempt to delay thepace ofdrilling orproject development in order topreserve cash. A working interest owner may be unable or unwilling to pay its share of project costs. In some cases, a working interest
owner may declare bankruptcy

. In the event any ofthese third party working interest owners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any ef forts to recover these costs from such parties, which could materially adversely af fect our financial position.
W e have substantial capital requirements that, if not met, may hinder operations. W e have experienced and expect to continue to experience substantial capital needs as a result of our active exploration, development and acquisition programs. W e expect that additional external financing will be required in the future to fund our growth. W

e may not be able to obtain additional financing, and financing under our existing revolving credit facility or new credit facilities may not be available in the future. Even ifadditional 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 drillingprogrambyreleasingrigs or deferring fracturing, completion andhookup ofthewells topipelines andthereby adversely af

fect ourproduction, cash flow , and the recoverability andultimate value ofour oil and gasproperties, in turn negatively af fecting our business, financial position and results of operations. 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. W e rely upon access toboth ourrevolving credit facility and longer-term capital markets as sources ofliquidity for any capital requirements not satisfied by the cash flow from operations or other sources. Our ability to access the capital markets or borrow money may be31

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 , challenges in the economy could lead to 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.
The risks associated with our debt and the provisions ofour debt agreements could adversely affect our business, financial position and results of operations. W e have demands on our cash resources, including interest expense, operating expenses and funding of our capital expenditures. Our level oflong-term debt, the demands on our cash resources and the provisions ofthe credit agreement governing
our revolving credit facility and the indentures governing our 4.375% Convertible Senior Notes due 2028, our 8.625% Senior Notes due 2018, and our 7.50% Senior Notes due 2020 may have adverse consequences on our operations and financial results, including:

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

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

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

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

• requiring us to use a substantial portion of our cash flow to make debt service payments, which will reduce the funds that would otherwise be available for operations and future business opportunities;

• requiring us to modify our operations, including by curtailing portions ofour drilling program, selling assets, reducing
our capital expenditures, refinancing all or a portion ofour existing debt or obtaining additional financing, which may be on unfavorable terms; and

• making us more vulnerable to downturns in our business or the economy
. In addition, the provisions of our revolving credit facility and our 8.625% Senior Notes and 7.50% Senior Notes place restrictions on us and certain ofour subsidiaries with respect to incurring additional indebtedness and liens, making dividends and other payments to shareholders, repurchasing or redeeming our common stock, redeeming our convertible senior notes, 8.625% Senior Notes and 7.50% Senior Notes, making investments, acquisitions, mergers and asset dispositions, entering into hedging transactions and othermatters. Ourrevolving credit facility alsorequires compliancewith covenants tomaintain specified financial ratios. 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. Ifthe 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. 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 of

ferings.Additionally

, these ratios may have the ef fect ofrestricting us from borrowing the full amount available under theborrowingbase for ourrevolving credit facility

. In ordertoprovide amargin ofcomfortwithregardto 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

. W e cannot assure you that we will be able to successfully execute any of these strategies, or if executed, that they will be suf ficient 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 may be reduced below the amount ofborrowings 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.Anegative adjustment could occur ifthe estimates offuture 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 2013. 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 and32

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 ofour borrowings. W e may not have suf

ficient funds to make any required repayment. Ifwe do not have suf ficient 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.
W e 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. In the past our management has 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 suf ficient to ensure that our internal controls are ef fective in the future. In addition, our history of material weaknesses, any future material weaknesses, or any failure to ef fectively address a material weakness or other control deficiency or implement required new or improved controls, or dif ficulties 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 ofthe SEC, NASDAQ and our various debt arrangements.
W e may face difficulties in securing and operating under authorizations and permits to drill or operate our wells. The recent growth in oil and gas exploration in the United States 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 dif ficult or impossible to obtain permits and other needed authorizationstooperate,resultinoperationaldelays,orotherwisemakeoperatingmorecostly ordif ficultthanoperating elsewhere.
W e 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. W e have no exploration experience and no development experience in the Utica Shale. W e have not participated in the drilling ofany wells in this area. Other operators in this area have significantly more experience in the drilling ofwells, including the drilling ofhorizontalwells.As aresult,wehave lessinformationwithrespecttotheultimaterecoverablereserves,theproduction decline rate and other matters relating to the exploration, drilling and development ofthe Utica Shale than we have in some other
areas in which we operate.
Ifwe are unable to acquire adequate supplies ofwater 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. W e use a substantial amount ofwater in our drilling operations. Our inability to locate suf ficient amounts ofwater, or treat anddisposeofwaterafterdrilling,couldadverselyimpactouroperations.Moreover,theimpositionofnewenvironmentalinitiatives 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 ofnatural 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 ofoperations, the extent ofwhich cannotbepredicted, all ofwhich could have an adverse ef fect on our operations and financial performance.
W e may not increase our acreage positions in areas with exposure to oil, condensate and natural gas liquids. Ifwe are unable to increase our acreage positions in the Eagle Ford Shale, the Niobrara Formation or the Utica Shale, this may detract from our ef

forts 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. One of our current primary core gas producing areas is located in largely urban portions ofthe Barnett Shale, which could disproportionately expose us to operational and regulatory risk in that area. At December 31, 2012, approximately 44% of our33

United States proved reserves and approximately 45% ofour then current production were located in the Barnett Shale. The core ofthe Barnett Shale is located in and around the greater Dallas-Fort W orth, T exas metropolitan area and much of our operations
are within the city limits ofvarious municipalities in that region, such as Arlington and Mansfield, T exas. In such urban or other populated areas, we may incur additional expenses, including expenses relating to mitigation ofnoise, 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 oflitigation or increased insurance and other costs related to our operations or facilities in such highly populated areas. W e face strong competition from other oil and gas companies. W e 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, wellestablished companies that have been engaged in the oil and gas business much longer than we have and possess substantially larger operating staf

fs 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 ofproperties 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. These companies may also have a greater ability to continue drilling activities during periods of low oil and gas prices and to absorb the burden of current and future governmental regulations and taxation. W e may not be able to conduct our operations, evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment.
W e 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. W e 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 af fected.
Part of our strategy involves drilling existing or emerging shale plays using some ofthe latest available horizontal drilling and completion techniques. The results of our planned exploratory and delineation drilling in these plays are subject to drilling and completion technique risks, and drilling results may not meet our expectations for reserves or production. As
a result, the value of our undeveloped acreage could decline if drilling results are unsuccessful. Many of our operations involve drilling and completion techniques developed by us or our service providers in order to maximize cumulative recoveries. Risks that we face while drilling include, but are not limited to, landing our well bore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the well bore, and being able to run tools and recover equipment consistently through the horizontal well bore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools and other equipment the entire length ofthe well bore during completion operations, being able to recover such tools and other equipment, and successfully cleaning out the well bore after completion of the final fracture stimulation. Ultimately

, the success ofthese drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a suf ficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity

, and/or commodity price decline, or other reasons, then the return on our investment for a particular project may not be as attractive as we anticipated and the value of our undeveloped acreage could decline in the future.
W e are subject to various environmental risks and governmental regulations, including those relating to benzene emissions, hydraulic fracturing and global climate change, and future regulations may be more stringent resulting in increased operating costs and decreased demand for the oil and gas that we produce. 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 ofwells, unitization and pooling ofproperties and taxation. From time to time,34

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 regulationsrelatingprimarilytotheprotectionofhumanhealthandtheenvironmentapplytothedevelopment,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 ofproperty 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. W e also are subject to changing and extensive tax laws, the ef fects 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 ef fect 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, which could have a material adverse ef fect on our results ofoperations and cash flows. See “Item 1. Business—Additional Oil and Gas Disclosures—Regulation—Environmental Regulations” for additional information.
There is increasing attention intheUnited States andworldwidebeingpaidtothe issue ofclimate change andthe contributing ef fect of GHG emissions. The modification of existing laws or regulations or the adoption ofnew laws or regulations curtailing oil and gas exploration in the areas in which we operate could materially and adversely af fect our operations by limiting drilling opportunities or imposing materially increased costs. See “Item 1. Business—Additional Oil and Gas Disclosures—Regulation; Global Climate Change” for additional information. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays. Hydraulic fracturing involves the injection ofwater, 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 EP A has asserted federal regulatory authority over hydraulic fracturing involving diesel under the federal Safe Drinking W

ater Act and has released draft permitting guidance for hydraulic fracturing operations that use diesel fuel in fracturing fluids in those states where EP A is the permitting authority

. A number of federal agencies are also analyzing, or have beenrequestedtoreview

, avariety ofenvironmentalissues associatedwithhydraulic fracturing.For example,theEP Ais conducting
a comprehensive research study to investigate the potential adverse environmental impacts ofhydraulic fracturing, including on water quality and public health. The EP A released a progress report outlining work currently underway on December 21, 2012 and is expected to release results of the study in 2014. These on-going or proposed studies, depending on their course and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking W ater Act, the T oxic Substances Control Act, or other regulatory mechanisms. President Obama has created the Interagency W orking Group on Unconventional Natural Gas and Oil by Executive Order, which is charged with coordinating and aligning federal agency research and scientific studies on unconventional natural gas and oil resources. At the state level, the New Y ork legislature has approved a temporary moratorium on drilling involving hydraulic fracturing andtheNewY

ork State Department ofEnvironmental Conservationhas ceased issuing exploration andproduction drillingpermits, 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. Additionally , the Governor of Pennsylvania has instituted a moratorium on leasing state forest land for new gas drilling. Further, in February 2012, Pennsylvania passed Act 13 of 2012, a comprehensive oil and gas bill that, among other things, strengthens permit requirements, extendswell setbacks, establishes standards for containment onwell sites,requires annual inventory ofair emissions, enhances disclosure requirements, and increases the maximum amount ofcivil penalties. Act 13 is currently being challenged in various lawsuits. The adoption of these new laws and regulations governing shale gas development in the Marcellus Shale in Pennsylvania could result in substantial changes in the way natural gas activities are conducted in the area. Several other states, including states where we operate such as Colorado, Ohio, and T exas, have proposed or adopted legislative orregulatory restrictions onhydraulic fracturingthrough additionalpermitrequirements,public disclosure offracturing fluid contents, water sampling requirements, and operational restrictions. Further, some cities and municipalities have adopted
or are considering adopting bans on drilling, including in Colorado, W est V irginia, and Pennsylvania.
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. W e use hydraulic fracturing extensively and any increased federal, state, local, foreign or international regulation of hydraulic fracturing or of fshore drilling, including legislation and regulation in the states of Colorado, New Y ork,35

Ohio, T exas and Pennsylvania, could reduce the volumes ofoil and gas that we can economically recover, which could materially and adversely af

fect our revenues and results of operations.
From time to time legislation is introduced in the U.S. Congress that, if enacted into law , would make significant changes to United States tax laws, including the elimination ofcertain 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 af fect our financial position and results of operations.
Our onshore and offshore operations are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues. The oil and gas business involves operating hazards such as:

• well blowouts;

• mechanical failures;

• explosions;

• pipe or cement failures and casing collapses, which could release oil, natural gas, drilling fluids or hydraulic fracturing fluids;

• uncontrollable flows of oil, natural gas or well fluids;

• fires;

• geologic formations with abnormal pressures;

• spillagehandlinganddisposingofmaterials,includingdrillingfluidsandhydraulicfracturingfluidsandotherpollutants;

• pipeline ruptures or spills;

• releases oftoxic gases;

• adverseweatherconditions,includingdrought, flooding,winter storms, snow ,hurricanesorother severeweatherevents; and

• other environmental hazards and risks including conditions caused by previous owners and lessors of our properties. Any ofthese hazards and risks can result in substantial losses to us from, among other things, injury or loss or 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. 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.
Of fshore operations are subject to a variety ofoperating risks in addition to the hazards described above, such as capsizing and collisions.The occurrence ofother events such as blowouts and oil spills in marine environments can make containment and remediation more dif

ficult and costly than on land. These conditions can and have caused substantial damage to facilities and interrupted production in the past. Additionally , of fshore operations generally involve increased costs and more expansive regulatory requirements as compared to onshore operations. Interruption to crude oil and natural gas gathering systems, pipelines and processing facilities we do not own could result in the loss of production and revenues. Our operations are dependent upon the availability , proximity and capacity ofpipelines, natural gas gathering systems and processing facilities we do not own. Any significant change af fecting these infrastructure facilities could materially harm our business. The lack of available capacity of gathering systems and pipelines could reduce the price of fered for our production or result in the shut-in ofproducing wells or the delay or discontinuance of development plans for properties. These facilities may be temporarily unavailable due to adverse weather conditions or operational issues or may not be available to us in the future. See “—Our onshore and of

fshore operations are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.” Additionally , activists or other ef

forts may delay or halt the construction of additional pipelines or facilities. T o the extent these services are unavailable, we would be unable to realize revenue from wells servedby such facilitiesuntil suitable arrangements aremadetomarket ourproduction.As aresult,we could experiencereductions in revenue that could reduce or eliminate the funds available for our exploration and development programs and acquisitions, or result in the loss ofproperty

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W e may not have enough insurance to cover all of the risks we face. W e 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. W e do not carry business interruption insurance. W e may elect not to carry insurance ifmanagement believes that the cost ofavailable 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. W

e cannot insure fully against pollution and environmental risks. W e 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 ef fect on our financial position and results of operations.
W e 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. W e conduct a substantialportion ofour operations throughjoint ventures with thirdparties, includingA vista and its af

filiates, GAIL, Haimo, the OIL JV Partners, Reliance and an af filiate ofSumitomo Corporation. W e may also enter into otherjoint venture arrangements in the future. These third parties may have obligations that are important to the success ofthejoint venture, such as the obligation to pay substantial carried costs pertaining to thejoint venture and to pay their share ofcapital and other costs ofthe joint venture. The performance ofthese third party obligations, including the ability ofthe 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 af fected.
Ourjoint venture arrangements may involve risks not otherwise present when exploring and developing properties directly , including, for example:

• ourjoint venture partners may share certain approval rights over major decisions;

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

• we may incur liabilities as a result of an action taken by ourjoint venture partners;

• we may be required to devote significant management time to the requirements of and matters relating to the joint ventures;

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

• disputes between us and ourjoint venture partners may result in delays, litigation or operational impasses.
The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely af fect our ability to transact the business that is the subject of such joint venture, which would in turn negatively af

fect our financial condition and results of operations. The risks described above or the failure to continue our joint ventures or to resolve disagreements with ourjoint venture partners could adversely af fect our ability to transact the business that is the subject of such joint venture, which would in turn negatively af fect our financial condition and results of operations. The agreements under which we formed certain joint ventures may subject us to various risks, limit the actions we may take with respect to the properties subject to thejoint venture and require us to grant rights to ourjoint venture partners that could limit our ability to benefit fully from future positive developments. Somejoint ventures requires us to make significant capital expenditures. Ifwe do not timely meet our financial commitments or otherwise do not comply with ourjoint venture agreements, our rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely af fected. Certain of our joint venture partners may have substantially greater financial resources than we have and we may not be able to secure the funding necessary to participate in operations ourjoint venture partners propose, thereby reducing our ability to benefit from the joint venture.
W e cannot control the activities on properties we do not operate. W e do not operate all ofthe 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 ofthe 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. W ith respect to properties that we do not operate:

• the operator could refuse to initiate exploration or development projects;37

• ifwe proceed with any ofthose projects the operator has refused to initiate, we may not receive any funding from the operator with respect to that project;

• the operator may initiate exploration or development projects on a dif ferent schedule than we would prefer;

• the operator may propose greater capital expenditures than we wish, including expenditures to drill more wells or build
more facilities on a project than we have funds for, which may mean that we cannot participate in those projects or participate in a substantial amount ofthe revenues from those projects; and

• the operator may not have suf ficient expertise or resources. Any ofthese events could significantly and adversely af fect 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 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
ouroil orgasmayhave several adverse ef fects,includinghighertransportation costs, fewerpotentialpurchasers (therebypotentially 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 limited pipeline and gathering system capacity in areas of the Marcellus Shale where we operate. See “—Interruption to crude oil and natural gas gathering systems, pipelines and processing facilities we do not own could result in the loss ofproduction and revenues.” 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 ofour oil and gasproductionmaybe interrupted dueto capacity constraints onthe applicable system, formaintenance
or repair ofthe system, or for other reasons as dictated by the particular agreements. Due to the lack ofavailable pipeline capacity inthe EagleFord Shale andthe Marcellus Shale,wehave entered into firmtransportation agreements for aportion ofourproduction 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. W e 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.
Ifproduction in the Marcellus Shale by oil and gas companies continues to expand, the amount ofnatural gas being produced by us and others could exceed the capacity ofthe 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 abilitytobuild intrastate gathering systemsnecessarytotransport our gasto interstate pipelines. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity or sell natural gasproduction at significantly lower prices than those we currently project, which could materially and adversely af fect our results ofoperations.
Aportion ofour oil and gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result ofweather conditions, accidents, loss ofpipeline or gathering system access, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. Ifa substantial amount ofour production is interrupted at the same time, it could temporarily adversely af fect 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, development and operating costs, potential environmental and other liabilities and other factors relating to the properties. Our assessments are necessarily inexact and their accuracy is inherently uncertain. Our review ofa subject property in connection with our acquisition assessment will not reveal all existing or potential problems or permit us to become suf ficiently familiar with the property to assess fully its deficiencies and capabilities. W e may not inspect every well, and we may not be able to observe structural and environmental problems even when we do inspect a well. Ifproblems are identified, the seller may be unwilling or unable to provide ef fective 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 ef fect on our financial position and future results of operations.38

Our business may suffer if we lose key personnel. W e depend to a large extent on the services ofcertain key management personnel, including our executive of ficers and other key employees, the loss ofany ofwhom could have a material adverse ef fect on our operations. W

e have entered into employment agreements with many of our key employees as a way to assist in retaining their services and motivating their performance. W e 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.
W e may experience difficulty in achieving and managing future growth. W e have experienced growth in the past primarily through the expansion ofour 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 af fecting our financial position and results of operations. Our ability to grow will depend on a number of factors, including:

• our ability to obtain leases or options on properties, including those for which we have 3-D seismic data;

• our ability to acquire additional 3-D seismic data;

• our ability to identify and acquire new exploratory prospects;

• our ability to develop existing prospects;

• our ability to continue to retain and attract skilled personnel;

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

• the results of our drilling program;

• hydrocarbon prices; and

• our access to capital.
W e 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 af fect our financial position and results of operations.
W e may continue to enter into derivative transactions to manage the price risks associated with our production, which may expose us to risk of financial loss and limit the benefit to us of 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 dif ferential swaps to reduce our exposure to price declines associated with a portion ofour oil and gas production and thereby to achieve a more predictable cash flow

. The use ofthese arrangements limits our ability to benefit from increases in the prices ofoil and gas. Our derivative arrangements may apply to only a portion ofour 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 inwhichproduction is less than expected, our customers fail topurchase contracted quantities ofoil and gas or a sudden,unexpected eventmaterially impacts oil or gasprices. 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 ofpoor 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.
W e may record impairments of oil and gas properties that would reduce our shareholders’ equity
. W e use the full cost method of accounting for our oil and gas properties. Accordingly , we capitalize all productive and nonproductive costs directly associatedwithproperty acquisition, exploration and development activitiesto 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 ofthe 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 ofproperties not subject to amortization,39

plus the lower ofthe cost or estimated fair value ofunproved properties included in the costs being amortized, less related income tax ef fects. 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 or gas prices. In addition, impairments would occur ifwe were to experience suf ficient downward adjustments to our estimated proved reserves or the present value ofestimated 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 ifhigher oil and gas prices increase the cost center ceiling applicable to the subsequent period. W e have in the past and could in the future incur additional impairments ofoil and gas properties, particularly as a result ofa decline in oil
or gas prices.
W e 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 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 of fering of stock during any three-year period resulting in an aggregate change ofmore than 50% in our beneficial ownership. In the event of an ownership change, Section 382 ofthe Code imposes an annual limitation on the amount of our taxable income that can be of fset by these carryforwards. The limitation is generally equal to the product of(a) the fair market value ofour 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 ifthere 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, 2012, we believe an ownership change occurred in February 2005, which imposed an annual limitation ofapproximately $12.6 million ofthe Company’s taxable income that can be of

fset by the pre-change carryforwards. Subsequent 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. loss carryforwards.
Enactment ofproposed impact fees on natural gas wells could adversely impact our results ofoperations 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 awellusinghydraulic fracturetreatments ormultilateralwellbores. Any countythat electsnotto imposethe fee canbe 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 ofcalculating the amount ofthe 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 ofour Utica Shale acreage is located in the Commonwealth ofPennsylvania. T o 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 ofoperations and the economic viability ofexploiting natural gas drilling and production opportunities in Pennsylvania.
W e may incur losses as a result of title deficiencies. W e 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 ofa material title deficiency can render a lease worthless and can adversely af fect our results of operations and financial condition. Title insurance covering mineral leaseholds is not generally available and, in all instances, we forego the expense ofretaining 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 ofperforming detailed title work can be expensive. W e may choose to forgo detailed title examination by title lawyers on a portion ofthe 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 of fices and abstract facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract. W e, in some cases, perform curative work to correct deficiencies in the marketability or adequacy of the title to us. The work might include obtaining af fidavits ofheirship or causing an estatetobe administered. In cases involvingmore serioustitleproblems, the amount paid for af

fected oil and gas leases can be generally lost and the target area can become undrillable. The failure oftitle 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

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

• currency restrictions and exchange rate fluctuations;

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

• increases in taxes and governmental royalties;

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

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

• labor problems; and

• other uncertainties arising out of foreign government sovereignty over our international operations.
Our international operations also may be adversely af fected by the laws and policies ofthe United States af fecting 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 ofthe courts of the United States.
The threat and impact of terrorist attacks, cyber attacks or similar hostilities may adversely impact our operations. W e 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 af fect
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 ofterror, a cyber attack or electronic security breach, or an act ofwar
. Item 1B. Unresolved Staff Comments None. Item 2. Properties Information regarding our properties is included in “Item 1. Business” above and in “Note 5. Property and Equipment, Net” ofthe Notes to our Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data,” which information is incorporated herein by reference.
Item 3. Legal Proceedings From time to time, we are party to certain legal actions and claims arising in the ordinary course of business. While the outcome ofthese events cannot be predicted with certainty , management does not expect these matters to have a materially adverse ef fect on our financial position or results of operations.
Item 4. Mine Safety Disclosures Not applicable.41

P AR TII 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 ofour common stock on the NASDAQ Global Select Market for the periods indicated. High Low 201 1 First Quarter $ 39.34 $ 28.71 Second Quarter 42.72 32.47 Third Quarter 44.17 20.95 Fourth Quarter 30.00 18.02 2012 First Quarter $ 31.62 $ 22.79 Second Quarter 31.32 19.04 Third Quarter 29.50 22.09 Fourth Quarter 27.30 19.47

The closing market price ofour common stock on February 25, 2013 was $21.29 per share. As ofFebruary 25, 2013, there
were an estimated 185 owners ofrecord of our common stock.
W e have not paid any dividends on our common stock in the past and do not intend to pay such dividends in the foreseeable future. W e currently intend to retain any earnings for the future operation and development ofour 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 ofFinancial Condition and Results of Operations—Liquidity and Capital Resources.”
The following graph presents a comparison ofthe yearly percentage change in the cumulative total return on our Common Stock over the period from December 31, 2007 to December 31, 2012, with the cumulative total return ofthe S&P 500 Index and the American Stock Exchange (“AMEX”) Natural Resources Industry Index ofpublicly traded companies over the same period. The graph assumes that $100 was invested on December 31, 2007 in our common stock at the closing market price at the beginning ofthis period and in each ofthe 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.

S&P AMEX CRZO December 31, 2007 100 100 100 December 31, 2008 62 51 29 December 31, 2009 76 71 48 December 31, 2010 86 91 63 December 31, 201 1 86 80 48 December 31, 2012 97 76 38

Pursuant to SEC rules, the foregoing graph is not deemed “filed” with the SEC.
W e made no repurchases of our common stock in the fourth quarter of2012.
On November 24, 2009, we entered into a land agreement with an unrelated third party and its af filiate. This land agreement expired by its terms on May 31, 201 1

. Under the land agreement, we issued warrants to purchase 31,983, 28,576 and 57,641 shares of common stock in 2012, 201 1 and 2010, respectively

. The warrants have an expiration date ofAugust 21, 2017, an exercise price of $22.09, which may be exercised on a “cashless” basis and are subject to antidilution adjustments

. The final issuance of warrantsunderthe land agreementwas ef fected inApril 2012

. Thewarrants were issuedpursuant to an exemption from registration under §4(2) ofthe Securities Act of 1933, as amended. Please see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results ofOperations—Liquidity and Capital Resources—Lease OptionArrangements” formore information about this land agreement and other lease option arrangements.42

During second and fourth quarters of2012, we issued 45,327 and 47,962 newly issued shares, respectively , ofour common stock to the University ofT exas at Arlington at par value ($0.01 per share) of$453 and $480

. These issuances were related to our five-year conditional and revocable pledge to donate $1.0 million per year to the University ofT exas at Arlington, where we are producing natural gas from a number ofwells in the Barnett Shale play

. Following the issuance in the first quarter of 2013, two donations remain. The shares were issued pursuant to an exemption from registration under §4(2) ofthe Securities Act of 1933,
as amended, for transactions not involving a public of fering.
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 stock incentive plans.43 Item 6. Selected Financial Data Our financial information set forth below for each ofthe five years in the period ended December 31, 2012, has been derived from continuing operations information included in our audited consolidated financial statements. This information should be read in conjunction with “Item 7. Management’s Discussion andAnalysis ofFinancial Condition and Results ofOperations” and our Consolidated Financial Statements and related Notes included in “Item 8. Financial Statements and Supplementary Data.”
Year Ended December 31, 2012 2011 2010 2009 2008

(In thousands, except per share data) Statements of Operations from Continuing Operations Data: Oil and gas revenues $ 368,180 $ 202,167 $ 138,123 $ 112,699 $ 209,829 Costs and expenses: Oil and gas operating expenses 54,826 37,636 31,014 30,321 37,607 Impairment of oil and gas properties

— — — 338,914 178,470 Depreciation, depletion and amortization 165,621 84,606 47,030 52,005 58,311 General and administrative 48,708 41,539 35,906 30,136 23,425 Accretion expense related to asset retirement obligations 372 235 216 308 154 Total costs and expenses 269,527 164,016 114,166 451,684 297,967 Operating income (loss) 98,653 38,151 23,957 (338,985) (88,138) Gain (loss) on derivative instruments, net 31,371 48,423 47,782 41,465 37,499 Loss on extinguishment of debt

— (897) (31,023)

— (5,689) Interest expense, net of amounts capitalized (48,158) (27,629) (22,518) (18,590) (9,730) Other income (loss), net 267 97 212 (2,042) 286 Income (loss) from continuing operations before income taxes 82,133 58,145 18,410 (318,152) (65,772) Income tax (expense) benefit (30,956) (25,611) (6,685) 113,307 20,725 Net income (loss) from continuing operations $ 51,177 $ 32,534 $ 11,725 $ (204,845) $ (45,047) Basic net income (loss) from continuing operations per common share $ 1.29 $ 0.83 $ 0.34 $ (6.61) $ (1.49) Diluted net income (loss) from continuing operations per common share $ 1.28 $ 0.82 $ 0.34 $ (6.61) $ (1.49) Basic weighted average common shares outstanding 39,591 39,077 33,861 31,006 30,326 Diluted weighted average common shares outstanding 40,026 39,668 34,305 31,006 30,326 Statements of Cash Flows from Continuing Operations Data: Net cash provided by operating activities - continuing operations $ 253,071 $ 155,511 $ 94,416 $ 133,372 $ 148,754 Net cash used in investing activities - continuing operations (465,151) (250,068) (264,115) (160,675) (549,794) Net cash provided by financing activities - continuing operations 237,778 116,826 169,990 25,956 398,198 Other Cash Flows from Continuing Operations Data: Capital expenditures - oil and gas properties $ (735,711) $ (516,004) $ (340,784) $ (179,891) $ (565,555) Proceeds from sales of oil and gas properties, net 341,597 167,265 54,217 48,524 3,259 Proceeds from (repayments of) debt (1) 244,772 126,401 (7,021) 31,652 279,259 Proceeds from common stock of ferings, net of of

fering costs

— — 188,534

— 135,075 Balance Sheet from Continuing Operations Data: Working capital (deficit) $ (43,432) $ (150,559) $ (58,672) $ (47,328) $ (57,602) Property and equipment, net 1,487,674 1,240,917 960,393 712,364 966,471 Total assets 1,749,488 1,445,075 1,121,470 841,771 1,051,544 T otal long-term debt, net of debt discount 967,808 711,486 558,254 520,336 475,961 Total shareholders’ equity 585,016 509,855 456,636 247,609 440,085
(1) Repayments include amounts refinanced.44

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations General Overview
In 2012, we recognized record oil and gas revenues of $368.2 million, record production of 9.4 MMBoe and U.S. proved oil and gas reserves of 1 15.1 MMBoe at December 31, 2012

. The key drivers to our success in 2012 included the following: Drillingpr

ogram. Our success is largely dependent on the results ofour drilling program. For the year ended December 31, 2012, we drilled 133 gross (70.8 net) wells a success rate of99% that was comprised of: (a) 59 of 59 gross (46.7 net) wells in the Eagle Ford Shale, (b) 26 of26 gross (9.1 net) wells in the Niobrara Formation, (c) 38 of39 gross (12.5 net) wells in the Marcellus Shale, (d) 6 of6 gross (1.7 net)wells in the Barnett Shale, and (e) 2 of3 gross (0.4 net) wells in otherproject areas.At December 31, 2012, 61 ofthese gross (28.7 net) wells were awaiting completion or pipeline connections.
Pr oduction and r

eserve gr owth. Our production for the year ended December 31, 2012 was a record 9.4 MMBoe, or 25,781 Boe/d, and reflects an increase of 26% from 201 1 production of 7.5 MMBoe

. The increase in production was primarily due to increased production from new wells, partially of fset by normal production decline, the Atlas sale, and the sale of substantially all of our non-core area Barnett Shale properties to KKR Natural Resources ("KKR") in May 201 1. Due to divestitures during 2012, our U.S. proved oil and gas reserves decreased 23% to 1 15.1 MMBoe at December 31, 2012, as compared to 149.7 MMBoe at December 31, 201 1

. Adjusted for the divestitures of 53.8 MMBoe in 2012, we replaced 303% of2012’s record production. Commodityprices. Our average gas price during 2012 was $1.90 per Mcf, $1.08 per Mcfless than the 201 1 price of $2.98

. Our average oil price in 2012 was $99.97 per Bbl, or $5.83 greater than the price of$94.14 in 201 1

. Commodity prices are af fected by changes in market demand, overall economic activity , weather, pipeline capacity constraints, inventory storage levels, basis dif ferentials 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.
Financialflexibility

. During 2012, 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 Formation. In September 2012, we issued in a public of fering $300.0 million aggregate principal amount of our 7.50% Senior Notes due 2020 at a price to the public of 100% of the principal amount. The net proceeds of approximately $294.2 million (after deducting underwriters’ discounts and our expenses) were used to repay a substantial portion of the borrowings outstanding under our revolving credit facility

. Outlook for 2013 While the market for natural gas remains challenging due to low spot and future prices, we are insulated from a portion of their ef fect by our hedging of 18,250,000 MMBtus ofnatural gas (approximately 57% of currently forecasted 2013 production) for 2013

. W

e are rapidly growing our oil production, part of the ef fect ofwhich will serve to further reduce our exposure to the weak natural gas market. The current market and outlook for crude oil 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, 2012, we had hedges in place for 2,774,000 Bbls ofoil (approximately 84% offorecasted 2013 production) and 2,555,000 Bbls ofoil for 2013 and 2014, respectively

. 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 2013

. On February 22, 2013, we completed the sale ofCarrizo UK, and all ofits interest in the Huntington Field discovery , to Iona Energy
. The U.K. North Sea assets and associated liabilities have been classified as current and long-term assets held for sale and current and long-term liabilities associated with assets held for sale in the consolidated balance sheets. The related results of operations and cash flows have been classified as discontinued operations, net ofincome taxes, in the consolidated statements of income and cash flows.
Contr ol capital costs and maintainfinancialflexibility

. Our Board ofDirectors has approved a U.S. capital expenditure plan for 2013 of $624.0 million, and we are striving to maintain our financial flexibility and a positive production growth profile. A weakening in commodity prices during 2013 could cause us to reduce our U.S. capital expenditure plan accordingly

. 2013 capital expenditur

eplan

. In 2013, we plan to focus on the development ofour key U.S. oil and gas resource plays. Our capital expenditures could vary from our currentplan depending upon various factors, including the availability and cost ofdrilling rigs, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors. For additional information on our 2013 capital expenditure plan, please see “Liquidity and Capital Resources—2013 Capital Expenditure Plan and Funding Strategy.”45

Results of Operations Y ear EndedDecember 31, 2012 Compared to the Y ear EndedDecember 31, 2011 Revenues from oil and gas production for 2012 increased 82% to $368.2 million compared to $202.2 million in 201 1

. Production volumes in 2012 were 9.4 MMBoe, an increase of26%, compared to production of7.5 MMBoe in 201 1

. The increase in production was primarily due to increased production from new wells, partially of fset by normal production decline, and the Atlas and KKR sales. See “Item 1. Business—Natural Gas Plays—Barnett Shale” for additional information. A verage oil prices increased 6% to $99.97 per Bbl in 2012 from $94.14 per Bbl in 201 1

. A verage natural gas prices decreased 36% to $1.90 per Mcf in 2012 from $2.98 per Mcfin 201 1

. A verage NGL prices decreased 31% to $34.86 per Bbl in 2012 from $50.30 per Bbl in 201 1

. The following table summarizes production volumes, production volumes per day , average realized prices and oil and gas revenues for the years ended December 31, 2012 and 201 1 : 2012 Period Compared to 2011 Period December 31, Increase % Increase 2012 2011 (Decrease) (Decrease) Production volumes

- Oil and condensate (MBbls) 2,862 802 2,060 257 % NGLs (MBoe) 305 210 95 45 % Natural gas (MMcf) 37,612 38,991 (1,379) (4)% T otal Natural gas and NGLs (MMcfe) 39,442 40,251 (809) (2)% T otal barrels of oil equivalent (MBoe) 9,436 7,511 1,925 26 %

Production volumes per day

- Oil and condensate per day (Bbls/d) 7,820 2,197 5,623 256 % NGLs per day (Boe/d) 833 575 258 45 % Natural gas per day (Mcf/d) 102,765 106,825 (4,060) (4)% Total Natural gas and NGLs per day (Mcfe/d) 107,765 110,277 (2,512) (2)% T otal barrels of oil equivalent per day (Boe/d) 25,781 20,578 5,203 25 %

A verage realized prices

- Oil and condensate ($ per Bbl) $ 99.97 $ 94.14 $ 5.83 6 % NGLs ($ per Boe) 34.86 50.30 (15.44) (31)% Natural gas ($ per Mcf) 1.90 2.98 (1.08) (36)% T otal average realized price ($ per Boe) $ 39.02 $ 26.92 $ 12.10 45 %

Oil and gas revenues (In thousands)

- Oil and condensate $ 286,119 $ 75,502 $ 210,617 279 % NGLs 10,631 10,562 69 1 % Natural gas 71,430 116,103 (44,673) (38)% T otal oil and gas revenues $ 368,180 $ 202,167 $ 166,013 82 %

Lease operating expenses for 2012 increased to $31.5 million ($3.34 per Boe) from $28.3 million ($3.77 per Boe) in 201 1

. Lease operating expenses increased $3.2 million primarily due to increased production from new wells partially of fset by theAtlas and KKR sales. The decrease in operating cost per Boe is due to the Atlas and KKR sales (which were higher operating cost per Boe properties as compared to our remaining Barnett Shale properties) partially of fset by the higher operating cost per Boe associated with oil production.
Production taxes increased to $13.5 million (or 3.7% ofoil and gas revenues) in 2012 from $5.7 million (or 2.8% ofoil and gas revenues) in 201 1 as a result of increased oil production in 2012

. The increase in production taxes as a percentage of oil and gas revenues was primarily due to increased oil production, which has a higher ef fective production tax rate as compared to our natural gas production.46

Ad valorem taxes increased to $9.8 million ($1.04 per Boe) in 2012 from $3.6 million ($0.48 per Boe) in 201 1

. The increase in ad valorem taxes is due primarily to new oil wells drilled in 201 1 and the Commonwealth of Pennsylvania’s February 2012 enactment ofan “impact fee” on the drilling ofunconventional natural gas wells. Because ofthe retroactive nature ofthe impact fee, approximately $1.0 million of ad valorem taxes recognized during 2012 is attributable to wells drilled prior to 2012. The increase in ad valorem taxes per Boe is due primarily to new oil wells drilled in 201 1, which have higher property tax valuations
as compared to our natural gas wells, as well as the recognition ofthe impact fee in 2012. Depreciation, depletion and amortization (“DD&A”) expense for 2012 increased to $165.6 million ($17.55 per Boe) from $84.6 million ($1 1.26 per Boe) in 201 1

. The increase in DD&A is attributable to both the increase in production and an increase in the DD&Arate per Boe

. The increase in the DD&Arate per Boe is largely due to the impact ofthe significant decrease in natural gas reserves in the Barnett Shale as a result ofthe Atlas and KKR sales as well as the increase in crude oil reserves in the Eagle Ford Shale that have been added during 201 1 and 2012, which have a higher finding cost per Boe than our natural gas reserves. General and administration (“G&A”) expense for 2012 increased to $48.7 million from $41.5 million in 201 1

. The increase
was primarily due to increased compensation costs related to an increase in personnel in 2012 as compared to 201 1

. This was partially of

fset by decreased stock-based compensation expense due to a decrease in the fair value of stock appreciation rights resulting from a decrease in stock price during 2012 as compared to an increase in stock price during 201 1, partially of fset by higher stock-based compensation expense due to a higher number ofrestricted units outstanding during 2012 as compared to 201 1.
The net gain on derivative instruments of $31.4 million in 2012 consisted of a $9.7 million unrealized loss on derivatives and a $41.1 million realized gain on derivatives. The net gain on derivative instruments of $48.4 million in 201 1 consisted of
a $13.0 million unrealized gain on derivatives and a $35.4 million realized gain on derivatives. The net decrease was due to the change in fair value of our open derivative positions during those periods.
Interest expense and capitalized interest in 2012 were $73.0 million and $24.8 million, respectively , as compared to $51.0 million and $23.4 million in 201 1 , respectively

. The net increase was primarily attributable to interest on the $200.0 million aggregate principal amount of our 8.625% Senior Notes issued in the fourth quarter of 201 1 as well as interest on the $300.0 million aggregate principal amount of our 7.50% Senior Notes issued in the third quarter of2012.
Our ef fective income tax rate was 37.7% for 2012 and 44% for 201 1

. The decrease in the ef fective income tax rate isprimarily due to the adjustments to prior state income tax provisions recorded during fourth quarter of 201 1 and the income tax benefit of
a capital loss associated with a prior investment.
Net income from discontinued operations, net ofincome taxes for 2012 increased to $4.3 million from $4.1 million in 201 1. The increase is primarily related to income tax benefits associated with Carrizo UK.
Y ear EndedDecember 31, 2011 Compared to the Y ear EndedDecember 31, 2010 Revenues from oil and gas production for 201 1 increased 46% to $202.2 million from $138.1 million in 2010. Production volumes for oil and gas in 201 1 increased 22% to 7.5 MMBoe from 6.1 MMBoe in 2010. The increase in production for the year ended December 31, 201 1 as compared to the year ended December 31, 2010 was primarily due to increased production from new wells, partially of

fset by normal production decline, the Atlas sale, and the KKR sale. A verage oil prices increased 20% to $94.14 per Bbl from $78.74 per Bbl in 2010. A verage natural gas prices decreased 1 1% to $2.98 per Mcf in 201 1 from $3.33 per Mcfin 2010. A verage NGL prices increased 31% to $50.30 per Boe in 201 1 from $38.51 per Boe in 2010.47

The following table summarizes production volumes, production volumes per day , average realized prices and oil and gas revenues for the years ended December 31, 201 1 and 2010:
2011 Period Compared to 2010 Period December 31, Increase % Increase 2011 2010 (Decrease) (Decrease) Production volumes

- Oil and condensate (MBbls) 802 176 626 356 % NGLs (MBoe) 210 277 (67) (24)% Natural gas (MMcf) 38,991 34,092 4,899 14 % Total Natural gas and NGLs (MMcfe) 40,251 35,754 4,497 13 % Total barrels of oil equivalent (MBoe) 7,511 6,135 1,376 22 %

Production volumes per day

- Oil and condensate per day (Bbls/d) 2,197 482 1,715 356 % NGLs per day (Boe/d) 575 759 (184) (24)% Natural gas per day (Mcf/d) 106,825 93,403 13,422 14 % Total Natural gas and NGLs per day (Mcfe/d) 110,277 97,956 12,321 13 % Total barrels of oil equivalent per day (MBoe) 20,578 16,808 3,770 22 %

A verage realized prices

- Oil and condensate ($ per Bbl) $ 94.14 $ 78.74 $ 15.40 20 % NGLs ($ per Boe) 50.30 38.51 11.79 31 % Natural gas ($ per Mcf) 2.98 3.33 (0.35) (11)% T otal average realized price ($ per Boe) $ 26.92 $ 22.51 $ 4.41 20 %

Oil and gas revenues (In thousands) - Oil and condensate $ 75,502 $ 13,859 $ 61,643 445 % NGLs 10,562 10,667 (105) (1)% Natural gas 116,103 113,597 2,506 2 % T otal oil and gas revenues $ 202,167 $ 138,123 $ 64,044 46 %

Lease operating expenses for 201 1 increased to $28.3 million ($3.77 per Boe) from $23.7 million ($3.86 per Boe) in 2010. Lease operating expenses increased due to increased production. W e continue to experience a decrease in the operating cost per Boe ofour Barnett Shale production as a result ofthe Atlas and KKR sales, which was partially of fset by increased operating cost per Boe associated with oil production.
Production taxes increased to $5.7 million (2.8% of oil and gas revenues) in 201 1 from $3.6 million (2.6% of oil and gas revenues) in 2010 as a result ofhigher oil prices and increased production in 201 1. The increase in production taxes as a percentage ofoil and gas revenues is due to increased oil production, which has a higher ef fective production tax rate as compared to natural gas production.
Ad valorem taxes decreased to $3.6 million ($0.48 per Boe) in 201 1 from $3.7 million ($0.60 per Boe) in 2010 due to the sale ofsubstantially all ofour non-core area Barnett Shale properties in May 201 1, partially of fset by new oil and gas wells drilled in 2010.
DD&A expense for 201 1 increased to $84.6 million ($1 1.26 per Boe) from $47.0 million ($7.68 per Boe) in 2010. The increases in DD&A and the related per Boe amounts were primarily due to the increase in crude oil reserves in the Eagle Ford that were added in 201 1 which have a higher finding cost per equivalent unit than our natural 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 ef forts 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

.48

G&Aexpense for 201 1 increased to $41.5 million from $35.9 million in 2010. The increase was dueprimarily to (a) increased compensation costs related to an increase in personnel in 201 1 as compared to 2010, (b) the expense associated with contributions to University ofT

exas atArlington, (c) increased of fice costs related to relocating our corporate headquarters in the fourth quarter of 201 1 partially of

fset by (d) decreased stock-based compensation expense driven by a significant decrease in the fair value of SARs that we expect to be settled in cash due to a decrease in stock price during the second halfof201 1, partially of fset by higher stock-based compensation expense due to a higher number of stock-based compensation awards outstanding during 201 1.
The net gain on derivative instruments of $48.4 million in 201 1 consisted of a $13.0 million unrealized gain on derivatives and a $35.4 million realized gain on derivatives. The net gain on derivative instruments of $47.8 million in 2010 consisted of a $14.6 million unrealized gain on derivatives and a $33.2 million realized gain on derivatives.
In January 201 1, in connection with our entrance into our current 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 oftwo banks in the prior credit facility who did notparticipate in the new revolving credit facility

. InNovember 2010, we completed a tender of fer for $300.0 million aggregateprincipal amount outstanding ofour convertible senior notes for an aggregate consideration of approximately $306.3 million, including accrued and unpaid interest on the convertible senior notes. W e recognized a $31.0 million pre-tax loss on extinguishment of debt as a result ofthe purchase ofthe convertible senior notes in the tender of fer, substantially all of which was non-cash representing the associated unamortized discount and deferred financing costs.
Interest expense and capitalized interest in 201 1 were $51.0 million and $23.4 million, respectively , as compared to $43.3 million and $20.7 million in 2010, respectively

. The net increase was primarily due to interest on the $400.0 million aggregate principal amount of 8.625% Senior Notes issued in the fourth quarter of2010 and the $200.0 million aggregate principal amount of8.625% Senior Notes issued in the fourth quarter of201 1 partially of fset by decreased interest attributable to the $300.0 million aggregate principal amount of our convertible senior notes purchased in the tender of fer during the fourth quarter of 2010. This increase was partially of

fset by increased capitalized interest due to higher levels ofunproved properties during 201 1.
Our ef fective income tax rate was 44.0% for 201 1 and 36.3% for 2010. The increase in the ef fective income tax rate is primarily due to prior period adjustments to state income tax provisions recorded during the fourth quarter of201 1 and the income tax benefit of a capital loss associated with a prior investment.
Net income (loss) from discontinued operations, net of income taxes for 201 1 increased to $4.1 million from a loss of $1.8 million in 2010. The increase is primarily related to income tax benefits recognized in 201 1 while in 2010 we had a full-cost ceiling test impairment of $2.7 million. Liquidity and Capital Resources 2013 Capital Expenditur

e Plan andFunding Strategy

. For 2013, our Board has approved a U.S. capital expenditure plan of $624.0 million which includes $500.0 million for drilling and completion (approximately $385.0 million for the Eagle Ford Shale, $70.0 million for the Marcellus Shale, $35.0 million for the Niobrara Formation, and $10.0 million in other areas) and $124.0 million for leasehold and seismic, after giving ef fect to carried interests. All 2013 capital expenditures for the Huntington Field development project in the U.K. North Sea were funded by our Huntington Facility and additional capital contributions by us, all of which were reimbursed by Iona Energy in connection with the sale and purchase transaction of Carrizo UK, which closed in February 2013. W

e intend to finance the remainder ofour 2013 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 acquisition of leases with drilling commitments and other factors. Sour ces and Uses ofCash. Our primary use ofcash is capital expenditures related to our drilling and development programs and,to a lesser extent, ourlease and seismic data acquisitionprograms.Fortheyear endedDecember 31,2012, capital expenditures, net ofproceeds from asset sales exceeded our net cash provided by operations for continuing operations. During 2012, we funded
our capital expenditures with cash provided by operations, payments relating to ourjoint ventures with Reliance in the Marcellus Shale, A vista in the Utica Shale, GAIL in the Eagle Ford Shale, and the OIL JV Partners in the Niobrara Formation, net proceeds from the sale of assets, including the Atlas, Gulf Coast and A vista Utica divestures, the Haimo joint venture, net proceeds from the of fering ofour 7.50% Senior Notes, and borrowings under our revolving credit facility and the Huntington Facility

. Potential
sources of future liquidity include the following:49

• Cash on handandcashgeneratedby operations. Cash flows from operations are highly dependent on commodity prices and market conditions for oilfield services. W e hedge a portion of our forecasted production to mitigate the risk of a decline in oil and gas prices.

• Borr owings under our r

evolving cr

editfacility

. At February 25, 2013, we had no borrowings outstanding and $0.9 million in letters ofcredit outstanding under the revolving credit facility , which reduce the amounts available under our revolving credit facility

. The amount we are able to borrow with respect to the borrowing base ofthe revolving credit facility , which borrowing base is currently $365.0 million, is subject to compliance with the financial covenants and other provisions ofthe credit agreement governing our revolving credit facility

.
• Asset sales

. In order to fund our U.S. capital expenditure plan, we may consider the sale of certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to sell such assets on terms that are acceptable to us. On April 30, 2012, we completed the sale of a significant portion of
our Barnett Shale properties to Atlas for net proceeds ofapproximately $187.4 million. W e used substantially all ofthe net proceeds from this sale to reduce the outstanding borrowings under our revolving credit facility

. During the third quarter of 2012, we completed the sale of substantially all of our legacy producing properties along the onshore Gulf ofMexico located primarily in T exas and Louisiana for net proceeds ofapproximately $17.6 million. In October 2012,
we sold substantially all of our interests in oil and gas properties dedicated to the A vista Utica joint venture that were located in the northern portion of the play to a third party for net cash proceeds of approximately $51.7 million, after finalpost-closing adjustments. Theproceeds from all the sales described above were recognized as a reduction ofproved oil and gasproperties. OnFebruary 22, 2013,we sold CarrizoUK, and all ofits interest intheHuntingtonField discovery , to Iona Energy for net proceeds of approximately $1 16.5 million, subject to final post-closing adjustments, which represents an agreed upon price of $184.0 million, including the assumption of $55.0 million in debt and net purchase price adjustments.

• Securities offerings

. In September 2012, we issued $300.0 million in aggregate principal amount of our 7.50% Senior Notes in an underwritten public of fering and received net proceeds of approximately $294.2 million. As situations or conditions arise, we may choose to issue debt, equity or other instruments to supplement our cash flows. However, we may not be able to obtain such financing on terms that are acceptable to us, or at all.

• Joint ventur

es
. Joint ventures with third parties through which such third parties fund a portion of our exploration activities to earn an interest in our exploration acreage or purchase a portion of interests, or both, such as our joint ventures with Reliance in the Marcellus Shale in Pennsylvania, with A vista in the Utica Shale and other parts of the Marcellus Shale, with GAIL in the Eagle Ford Shale, and with an af filiate ofSumitomo Corporation in the Barnett Shale. Ef fective October 1, 2012, we completed the sale of 30% of substantially all of our interest in oil and gas properties in the Niobrara Formation to the OIL JV Partners. W e received cash proceeds ofapproximately $41.25 million, subject to final post closing adjustments, and the OIL JV Partners committed to pay a “development carry” of 50% of certain of
our future exploration and development costs up to an aggregate of approximately $41.25 million. W e expect the development carry to be fully utilized by early 2014. In December 2012, we completed the sale of a portion of our remaining interest in the same oil and gas properties previously sold to the OIL JV Partners in the transaction described above to Haimo, ef

fective October 1, 2012, for cash proceeds of approximately $27.5 million, subject to final post closing adjustments. The cash proceeds from such sales were recognized as a reduction ofproved oil and gas properties. Following the close of the Haimo transaction late in the fourth quarter of 2012, we, the OIL JV Partners, and Haimo
own 60%, 30% and 10% ofthe joint venture acreage, respectively.’’

• Leasepur

chase option arrangements

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

• Other sour

ces
. W e may consider sale/leaseback transactions of certain capital assets, such as our remaining pipelines and compressors, which are not part of our core oil and gas exploration and production business.
Overview ofCash FlowActivities. Net cash provided by operating activities from continuing operations were $253.1 million and $155.5 million and $94.4 million for the years ended December 31, 2012, 201 1 and 2010, respectively

. The increase was primarily due to increased crude oil production and oil prices, partially of fset by lower gas prices in 2012 as compared to 201 1. Net cash provided by operating activities from continuing operations increased in 201 1 from 2010 due to increased production, particularly higher crude oil and condensate production in the Eagle Ford Shale and increased oil prices, partially of fset by lower gas prices in 201 1 as compared to 2010.
Net cash used in investing activities from continuing operations were $465.2 million, $250.1 million and $264.1 million for the years ended December 31, 2012, 201 1 and 2010, respectively

. Net cash used in investing activities from continuing operations in 2012 related primarily to increased capital expenditures in our Eagle Ford Shale and Niobrara Formation as well as utilization ofadvances received forjoint operations in 201 1, partially of fset by an increase in proceeds from the sale of oil and gas properties.50

Net cash used in investing activities from continuing operations in 201 1 related primarily to capital expenditures, partially of fset by proceeds from the sale of our non-core area Barnett Shale properties to KKR, proceeds from the sale of an interest in certain ofour Eagle Ford Shale properties to GAIL and cash distributions on our “B Units” interest inACP II of$3.3 million. The decrease in investing activities from continuing operations in 201 1 as compared to 2010 was due to higher proceeds from the sales of oil and gas properties and increase in advances forjoint ventures, partially of fset by increased capital expenditures during 201 1.
Net cash provided by financing activities from continuing operations for the years ended December 31, 2012, 201 1 and 2010
were $237.8 million, $1 16.8 million and $170.0 million, respectively

. Net cash provided by financing activities from continuing operations for 2012 related primarily to net proceeds of $294.2 million from the issuance of $300.0 million aggregate principal amount of 7.50% Senior Notes in September 2012, partially of fset by a decrease in net borrowings under the revolving credit facility during 2012 as compared to 201 1. Net cash provided by financing activities from continuing operations in 201 1 related primarily tonetproceeds of$194.5million from the issuance ofan additional $200.0million aggregateprincipal amount of8.625% Senior Notes in November 201 1, partially of fset by repayment ofborrowings outstanding under our revolving credit facility

. The decrease in financing activities from continuing operations in 201 1 as compared to 2010 was due the absence of common stock of ferings and less debt issuance and borrowing during 201 1. Liquidity/Cash Flow Outlook Economic downturns may adversely af fect our ability to access capital markets in the future. W e currently believe that cash provided by operating activities from continuing operations, the sale of assets (including our sale ofthe Huntington Field in the North Sea, which closed on February 22, 2013), carry resulting from our Niobrara joint venture transactions, borrowings under
our revolving credit facility and our cash on hand will be suf ficient to fund our immediate cash flow requirements. Cash provided by operating activities from continuing operations isprimarily drivenbyproduction and commodityprices.While we have steadily increased production over the last few years, spot and futures prices ofnatural gas continue to remain depressed. T o 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 ofour forecasted production and, as ofFebruary 25, 2013, we had hedged approximately 18,250,000 MMBtu (50,000 MMBtu per day for the remainder of 2013, which is approximately 57% of forecasted 2013 production) of our estimated March through December 2013 natural gas production at a weighted average floor or swap price of $4.63 per MMBtu relative to NYMEX prices. Additionally , we had hedged approximately 2,941,000 Bbls (8,058 Bbls per day for the remainder of 2013, which is approximately 90% of forecasted 2013 production) of our estimated March through December 2013 crude oil production at a weighted average floor or swap price of$89.21 per Bbl relative to NYMEX prices. Our borrowing base under our revolving credit facilityis currently $365.0 million.As ofFebruary 25,2013,wehadno borrowings outstandingunderourrevolving credit facility and had issued $0.9 million in letters ofcredit, which reduce the amounts availableunder ourrevolving credit facility

. As ofFebruary 25, 2013, we had no borrowings outstanding under the Huntington Facility , which was repaid by Iona Energy upon consummation ofthe sale ofthe U.K. North Sea assets. 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 ofthe credit agreement governing the revolving credit facility

. The borrowing base under our revolving credit facility is af fected by our lenders’ assumptions with respect to future oil and gas prices. Our borrowing base may decrease if our lenders reduce their expectations with respect to future oil and gas prices from those assumptions used to determine our existing borrowing base. The next borrowing base redetermination is scheduled to occur during the second quarter of2013.
Ifcash provided by operating activities from continuing operations, net proceeds from asset sales, funds available under our revolving credit facility and the other sources of cash described under “Sources and Uses of Cash” are insuf ficient to fund our 2013 capital expenditure plan, we may need to reduce our capital expenditure plan or seek other financing alternatives. W e may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. Ifwe cannot obtain adequate financing, we may be required to limit or defer our planned 2013 capital expenditure plan, thereby adversely af fecting the recoverability and ultimate value ofour oil and gas properties. Subject in each case to then existing market conditions and to our then expected liquidity needs, among other factors, we may use a portion of our internally generated cash flows, proceeds from asset sales or borrowings or cash on hand to reduce debt prior to scheduled maturities through debt repurchases, either in the open marketorinprivatelynegotiatedtransactions,throughdebtredemptionsortenderof fers,orthroughrepaymentsofbankborrowings.51

Contractual Obligations The following table sets forth estimates of our contractual obligations as ofDecember 31, 2012: U.S. Contractual Obligations

Total 2013 2014 2015 2016 2017 2018 and Beyond Long-term debt (1) $ 973,750 $

— $

— $

— $ 73,750 $

— $ 900,000 Interest on long-term debt (2) 510,561 80,328 80,328 80,328 76,077 74,250 119,250 Operating leases 12,969 1,255 1,419 1,392 1,370 1,370 6,163 Drilling contracts 103,056 62,228 30,532 9,490 806

— — Pipeline volume commitments 74,022 17,429 16,876 16,333 9,994 4,041 9,349 Asset retirement obligations 6,764 1,670 22 8

— — 5,064 Seismic commitments 636 636

— — — — — Total U.S. Contractual Obligations $1,681,758 $ 163,546 $ 129,177 $ 107,551 $ 161,997 $ 79,661 $1,039,826

U.K. Contractual Obligations - Discontinued Operations

Total 2013 2014 2015 2016 2017 2018 and Beyond Debt (3) $ 52,000 $ 33,800 $ 18,200 $

— $

— $

— $

— Interest on debt (4) 1,675 1,330 345

— — — — Asset retirement obligations 5,243

— — — — — 5,243 Other 764 660 104

— — — — Total U.K. Contractual Obligations $ 59,682 $ 35,790 $ 18,649 $

— $

— $

— $ 5,243
(1) Noteholders may require us to repurchase our convertible senior notes in June 2013, June 2018, or June 2023. W e have the intent and ability to refinance our convertible senior notes on a long-term basis with the available capacity ofour revolving credit facility , which matures in 2016, and accordingly

, our convertible senior notes have been presented as a 2016 contractual obligation. (2) Interest on long-term debt is based on the 8.625% Senior Notes, the 7.50% Senior Notes and the convertible senior notes until June 1, 2013 and our revolving credit facility rate of3.87% thereafter (reflecting our intent and ability to refinance the convertible senior notes with the available capacity under our revolving credit facility). There were no borrowings under our revolving credit facility as of December 31, 2012, therefore no interest was computed for our revolving credit facility as it relates to the table above. (3) The Huntington Facility was repaid in full in connection with the sale to Iona Energy in February 2013. (4) The December 31, 2012 average interest rate is 3.79% for the amounts outstanding under the Huntington Facility

. Off Balance Sheet Arrangements W e currently do not have any of fbalance sheet arrangements. Financing Arrangements 8.625% Senior Notes and 7.50% Senior Notes As ofDecember 31, 2012, we had $600.0 million aggregate principal amount of 8.625% Senior Notes due 2018 issued and outstanding. The 8.625% Senior Notes are guaranteed by all ofthe our existing subsidiaries (other than Carrizo UK Huntington Ltd, Monument Exploration LLC, and Carrizo UK Bardolph Ltd).
The 8.625% Senior Notes mature on October 15, 2018, with interest payable semi-annually

. Except in certain circumstances described below

, we may not redeem the 8.625% Senior Notes prior to October 15, 2014. On and after October 15, 2014, we may redeem all or a part ofthe 8.625% Senior Notes, at redemption prices decreasing from 104.313% ofthe principal amount to 100% ofthe principal amount on October 15, 2017, plus accrued and unpaid interest. In connection with certain equity of ferings by the Company , we may at any time prior to October 15, 2013, subject to certain conditions, on one or more occasions, redeem up to 35% ofthe aggregate principal amount ofthe 8.625% Senior Notes at a redemption price of 108.625%, ofthe principal amount, plus accrued and unpaid interest, if any , to the redemption date using the net cash proceeds of such equity of ferings. Prior to October 15, 2014, we may redeem all or part ofthe 8.625% Senior Notes at 100% ofthe principal amount thereof, plus accrued and unpaid interest and a make whole premium (as defined in the Indenture governing the 8.625% Senior Notes). If a Change of Control (as defined in the indenture governing the 8.625% Senior Notes) occurs, we may be required by holders to repurchase the 8.625% Senior Notes for cash at a price equal to 101% ofthe aggregate principal amount, plus any accrued but unpaid interest.52

On September 10, 2012, the Company issued in a public of fering $300.0 million aggregate principal amount of7.50% Senior Notes due 2020 that were issued and outstanding as of December 31, 2012

. The 7.50% Senior Notes are guaranteed by are guaranteed by the same subsidiaries that guarantee our 8.625% Senior Notes.
The 7.50% SeniorNotes mature on September 15, 2020, with interestpayable semi-annually

. Except in certain circumstances described below

, we may not redeem the 7.50% Senior Notes prior to September 15, 2016. On and after September 15, 2016, we may redeem all or a part ofthe 7.50% Senior Notes, at redemption prices decreasing from 103.750% ofthe principal amount to 100% ofthe principal amount on September 15, 2018, plus accrued and unpaid interest. In connection with certain equity of ferings by the Company

, we may at any time prior to September 15, 2015, subject to certain conditions, on one or more occasions, redeem up to 35% ofthe aggregateprincipal amount ofthe 7.50% SeniorNotes at a redemptionprice of 107.500%, oftheprincipal amount, plus accrued and unpaid interest, if any , to the redemption date using the net cash proceeds of such equity of ferings. Prior to September 15, 2016, we may redeem all or part ofthe 7.50% Senior Notes at 100% ofthe principal amount thereof, plus accrued and unpaid interest and a make whole premium (as defined in the Indenture governing the 7.50% Senior Notes). If a Change of Control (as defined in the indenture governing the 7.50% Senior Notes) occurs, we may be required by holders to repurchase the 7.50% Senior Notes for cash at a price equal to 101% ofthe aggregate principal amount, plus any accrued but unpaid interest.
The indentures governing the 8.625% Senior Notes and the 7.50% Senior Notes contain covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: pay distributions on, purchase or redeem our common stock or other capital stock or redeem our subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types ofequity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all ofour assets; enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us; engage in transactions with af filiates; and create unrestricted subsidiaries.
The indentures governingthe 8.625% SeniorNotes andthe 7.50% SeniorNotes are subjectto customary events ofdefault, including those relating to failures to comply with the terms of the notes and the indentures, certain failures to file reports with the SEC, certain cross defaults of other indebtedness and mortgages and certain failures to pay finaljudgments.
Convertible Senior Notes In May 2008, we issued $373.8 million aggregate principal amount of 4.375% Convertible Senior Notes due 2028. These notes are convertible, using a net share settlement process, into a combination of cash and common stock that entitles holders of
our convertible senior notes to receive cash up to the principal amount ($1,000 per note) and common stock in respect of the remainder, if any

, of our conversion obligation in excess of such principal amount. As of December 31, 2012, $73.8 million aggregate principal amount of convertible senior notes was outstanding.The holders of our convertible senior notes may require
us to repurchase the notes on June 1, 2013, 2018 and 2023, or upon a fundamental corporate change at a repurchase price in cash equal to 100% of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any
. W e may redeem notes at any time on or after June 1, 2013 at a redemption price equal to 100% ofthe principal amount ofthe notes to be redeemed plus accrued and unpaid interest, if any
. While the holders ofthe convertible senior notes may require us to repurchase such notes in June 2013, we have the intent and ability to refinance the convertible senior notes on a long-term basis with the available capacity ofour revolving credit facility , and accordingly

, the convertible senior notes have been classified as long-term debt in the consolidated balance sheets as of December 31, 2012.
For additional information on our convertible senior notes, please see “Note 7. Long-term Debt” of the Notes to our Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data,” which information is incorporated herein by reference.
Senior Secured Revolving Credit Facility W e have a senior secured revolving credit facility that permits us to borrow up to the lesser of (i) the borrowing base (as defined inthe credit agreement governingtherevolving credit facility) and (ii) $750.0million. Therevolving credit facilitymatures on January 27, 2016. The revolving credit facility is secured by substantially all ofour U.S. assets and is guaranteed by the same subsidiaries that guarantee our 8.625% Senior Notes, 7.50% Senior Notes and convertible senior notes. 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 $365.0 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 on or about May 1, 2013

. The amount we are able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions ofthe credit agreement governing the revolving credit facility

.53

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 ofthe borrowing base, we have the option within 30 days to take any ofthe 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 suf ficient 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 ofthe 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 oftheAgent’s Prime Rate, the Federal Funds Ef fective 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 ofborrowing 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 ofborrowing base usage).
W e and our lenders amended the revolving credit facility three times in 2012. On March 26, 2012, the revolving credit facility was amended to, among other things, (1) extend by two quarters the dates on which the maximum ratio ofT otal Debt to EBITDA (each as defined in the credit agreement governing the revolving credit facility) steps down and (2) increase the basket available for redemptions of our convertible senior notes. On September 4, 2012 the revolving credit facility was amended to increase the basket available for issuances ofadditional senior notes, including those issued in the September 2012 notes of fering. On September 27, 2012, the revolving credit facility was amended to, among other things, extend the maximum permitted duration of hedge agreements entered into by the Company and its restricted subsidiaries and to reflect the Fall 2012 borrowing base redetermination
W e are subject to certain covenants under the terms ofthe revolving credit facility , as amended, which include, but are not limited to, the maintenance of the following financial covenants: (1) a ratio T otal Debt to EBITDA of not more than (a) 4.25 to 1.00 for fiscal quarter ending December 31, 2012 and (b) 4.00 to 1.00 for fiscal quarters ending March 31, 2013 and thereafter; (2) a Current Ratio of not less than 1.00 to 1.00; (3) a ratio of Senior Debt to EBITDA of not more than 2.50 to 1.00; and (4) a ratio ofEBITDA to Interest Expense ofnot less than 2.50 to 1.00 (each ofthe capitalized terms used in the foregoing clauses (1) through (4) being as defined in the credit agreement governing the revolving credit facility). At December 31, 2012, the ratio of T otal Debt to EBITDA was 2.97 to 1.00, the Current Ratio was 2.23 to 1.00, the ratio of Senior Debt to EBITDA was 0.00 to 1.00 andtheEBITDAto InterestExpenseratiowas 5.19 to 1.00.T otalDebt and SeniorDebt, as defined inthe credit agreement governing the revolving credit facility , are net of cash and cash equivalents.
Our 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 ofour common stock, redemptions of our senior notes, investments, acquisitions, mergers, asset dispositions, transactions with af filiates, hedging transactions and other matters.
Our revolving credit facility is subject to customary events ofdefault, including a change in control (as defined in the credit agreement governing our revolving credit facility). Ifan event ofdefault 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, 2012, we had no borrowings outstanding under the revolving credit facility

. At December 31, 2012, we had $0.9 million in letters of credit outstanding which reduced the amounts available under the revolving credit facility

. Future availability under the $365.0 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 to the extent such amounts exceed the cash flow from operations, proceeds from the sale ofoil and gas properties and securities of ferings. The revolving credit facility may also be used to repurchase our convertible senior notes. Huntington FieldDevelopment Project Credit Facility On January 28, 201 1, we and Carrizo UK, as borrower, entered into the Huntington Facility

. The Huntington Facility was secured by substantially all ofCarrizo UK’s assets and was limited recourse to us. The Huntington Facility provided 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.54

The sale ofCarrizo UK, and all ofits interest in the Huntington Field discovery , closed on February 22, 2013

. The Huntington facility that was secured by substantially all of Carrizo UK's assets with limited recourse to us was repaid by Iona Energy in connection with the close ofthe sales transaction.As ofDecember 31, 2012 and February 22, 2013, borrowings outstanding under the Huntington Facility were $52.0million and $55.0 million, respectively

. As of December 31, 2012, $33.8 million of the borrowings outstanding were classified as current, with a weighted average interest rate of3.79% and no letters ofcredit had been issued.
Securities Of

ferings in 2012

, 2011 and 2010 In September 2012, we issued in a public of fering $300.0 million aggregate principal amount of 7.50% Senior Notes. W e used the net proceeds of approximately $294.2 million after deducting the underwriters’ discount and our estimated expenses to repay borrowings outstanding under our revolving credit facility

. Holders of all $300.0 million aggregate principal amount of 7.50% Senior Notes will vote as one series under the indenture governing the 7.50% Senior Notes.
In November 201 1, we issued $200.0 million aggregate principal amount of 8.625% Senior Notes in a private placement exempt from the registration requirements ofthe Securities Act of 1933, as amended. W e used the net proceeds ofapproximately $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 of fer and issued
new notes and guarantees having substantially identical terms, but registered with the SEC, in exchange for all such privately issued 8.625% Senior Notes. The $200.0 million of 8.625% Senior Notes issued in November 201 1 have substantially identical terms as, and are treated as a single series with, the $400.0 million of 8.625% Senior Notes described below

. In November 2010, we issued $400.0 million aggregate principal amount of 8.625% Senior Notes in a private placement exempt from the registration requirements ofthe Securities Act. W e 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. W e subsequently purchased the $300.0 million of convertible senior notes in the tender of fer with a combination of cash on hand and borrowings under our prior credit facility

. In June 201 1, we completed an exchange of fer and issued new notes and guarantees having substantially identical terms, but registered with the SEC, in exchange for all such privately issued 8.625% Senior Notes.
In December 2010, we sold 3.975million shares of our common stock in an underwritten public of fering at a price to the underwriter of $28.90 per share. W e used the net proceeds of approximately $1 14.9 million to repay a portion ofthe outstanding borrowings under our prior credit facility

. InApril 2010,we sold 3.22 million shares ofour common stock in anunderwrittenpublic of fering at apricetotheunderwriter of$23.00per share.W

eused the netproceeds ofapproximately $73.8 million to repay aportion ofthe then-outstandingborrowings under a prior credit facility

. Lease Purchase OptionArrangements From time to time, we have entered into lease purchase option arrangements with third parties. In 201 1, 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 suf ficient capital to directly acquire such oil and gas leases. W

e may continue to use these arrangements as a strategic alternative in the future.
On November 24, 2009, we entered into a land agreement pursuant to which the Company was able to acquire up to $20.0 million of oil, gas and mineral interests or leases in certain specified areas in the Barnett Shale from an unrelated third party and its af filiate. The land agreement expired by its terms on May 31, 201 1

. In consideration ofour receipt ofan option to purchase the leases acquired by the third party (as described below), we issued to the third party’s af filiate warrants to purchase a certain number ofshares ofour common. See “Item 5. Market for Registrant’s Common Stock, Related Shareholder Matters and Issuer Purchases ofEquity Securities” for additional information about these warrants, including their conversion price.
Effects of Inflation and Changes in Price Our results of operations and cash flows are af fected by changing oil and gas prices. Although natural gas prices have significantly declined since mid-2008 and the price ofnatural gas remains depressed, our revenue per unit ofproduction increased in 2012 as a result ofincreased crude oil production and oil prices. Historically , inflation has had a minimal ef fect on us. However, with interest rates at historic lows and the government attempting to stimulate the economy through rapid expansion ofthe money supply in recent years, inflation could become a significant issue in the future.55

Summary of Critical Accounting Policies The following summarizes our critical accounting policies. See a complete list of significant accounting policies in “Note 2. Summary of Significant Accounting Policies” ofthe Notes to our Consolidated Financial Statements.
Use ofEstimates The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that af fect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date ofthe financial statements and the reported amounts ofrevenues and expenses during the periods reported.Actual results could dif fer from these estimates. W e evaluate subsequent events through the date the financial statements are issued. Significant estimates include volumes ofproved oil and gas reserves which are used in calculating the amortization ofproved oil and gas property costs, the present value offuture net revenues included in the full cost ceiling test, estimates offuture taxable income used in assessing the realizability of deferred tax assets, and asset retirement obligations. Other significant estimates include the, impairment ofunproved properties, fair values ofderivative instruments, stock-based compensation, the collectability of outstanding receivables, and contingencies. Proved oil and gas reserve estimates have numerous inherent uncertainties. The accuracy ofany reserve estimate is a function ofthe quality and quantity ofavailable data and the application ofengineering and geological interpretation andjudgment to available data. Subsequent drilling results, testing and production mayjustify revisions of such estimates. Accordingly , proved oil and gas reserve estimates are often dif ferent from the quantities ofoil 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 af fected by changes to future economic conditions such
as the market prices ofoil and gas, the credit worthiness ofcounterparties, interest rates and the market value and volatility ofour common stock. Future changes in these assumptions may af fect these significant estimates materially in the near term.
Discontinued Operations On December 27, 2012, we agreed to sell Carrizo UK, a wholly owned subsidiary ofthe Company , and all ofits interest in the Huntington Field discovery , where Carrizo UK owned a 15% non-operated working interest and certain overriding royalty interests. The sale closed on February 22, 2013. W e classified all our U.K. North Sea assets and associated liabilities as current and long-term assets held for sale and current and long-term liabilities associated with assets held for sale in our consolidated balance sheets along with the related results ofthe operations and cash flows as discontinued operations, net of income taxes, in
our consolidated statements of income, statements of cash flows and condensed consolidating financial information. Unless otherwise indicated, the information included relates to our continuing operations. Information related to assets held for sale and discontinued operations is included in “Note 3. Assets Held for Sale and Discontinued Operations”, “Note 14. Condensed Consolidating Financial Information” and “Note 15. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited)” ofthe Notes to our Consolidated Financial Statements.
Oil and Gas Properties Oil andgasproperties are accounted forusingthe fullcostmethodofaccountingunderwhichallproductiveandnonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to costs centers established on a country-by-countrybasis. Internal costs directly identifiedwith acquisition, exploration and development activities
are capitalized and totaled $1 1.8 million, $9.6 million and $5.3 million for the years ended December 31, 2012, 201 1 and 2010, 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 ofone barrel ofoil 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 ofthe 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 ofestimated salvage values.A verage DD&A per Boe was $17.55, $1 1.26 and $7.67 for the years ended December 31, 2012, 201 1 and 2010, respectively

. Costs not subject to amortization include unevaluated leasehold and seismic costs associated with specific unevaluated properties, the cost ofexploratory wells in progress, and related capitalized interest. 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
we consider in our impairment assessment include drilling results by us and other operators, the terms of oil and gas leases not56

held by production and drilling capital expenditure plans. W e expect to complete the evaluation ofthe 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 ofthe properties. W e capitalized interest costs associated with our unevaluated leasehold and seismic costs and exploratory wells in progress of $24.8 million, $23.4 million and $20.7 million for the years ended December 31, 2012, 201 1 and 2010, 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

. Through December 31, 2012, 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 ef fects. Ifthe net capitalized costs exceed the cost center ceiling, the excess is recognized as an impairment ofoil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even ifhigher oil and gas prices increase the cost center ceiling applicable to the subsequent period.
The table below presents results of the U.S. full cost ceiling test along with various pricing scenarios to demonstrate the sensitivity of our U.S. cost center ceiling to changes in 12 month average oil and gas prices. The prices included represent the unweighted averagerealizedmarketprices onthe first calendar day ofeachmonth duringthe 12-monthperiod ended December 31, 2012

. This sensitivity analysis is as of December 31, 2012 and, accordingly , does not consider drilling results, production and prices subsequent to December 31, 2012 that may require revisions to our proved reserve estimates.

12 Month A

verage Cushion/(Impairment) U.S. Full Cost Pool Scenarios Oil Price ($/Bbl) Gas Price ($/Mcf) (in millions) December 31, 2012 Actual $101.35 $1.95 $191
Oil and Gas Price Sensitivity Oil and Gas +10% $110.81 $2.23 $344 Oil and Gas -10% $91.90 $1.68 $14
Oil Price Sensitivity Oil +10% $110.81 $1.95 $313 Oil -10% $91.90 $1.95 $64
Gas Price Sensitivity Gas +10% $101.35 $2.23 $222 Gas -10% $101.35 $1.68 $160

The cost center ceiling exceeded our net capitalized costs for the U.K. cost center at December 31, 2012 by approximately $135.8 million and was based on crude oil and condensate prices of $1 1 1.21 per barrel and natural gas prices of $13.32 per Mcf, representing the unweighted average realized market prices on the first calendar day of each month during the 12-month period ended December 31, 2012

. A ten percent increase in average market prices at December 31, 2012 would have increased the cost center ceiling by approximately $20.4 million and a ten percent decrease in average market prices would have decreased the cost center ceiling by approximately $18.5 million. This sensitivity analysis is as of December 31, 2012 and, accordingly , does not consider drilling results, production and prices subsequent to December 31, 2012 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, 201 1 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, representing the unweighted average realized market prices on the first calendar day of each month during the 12-month period ended December 31, 201 1. A ten percent increase in average market prices at December 31, 201 1 would have increased the cost center ceiling by approximately $163.4 million and a ten percent decrease in57

average market prices would have caused an impairment of approximately $24.4 million. This sensitivity analysis is as of December 31, 201 1 and, accordingly , does not consider drilling results, production and prices subsequent to December 31, 201 1 that may require revisions ofproved reserve estimates.
The cost center ceiling exceeded our net capitalized costs for the U.K. cost center at December 31, 201 1 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, representing the unweighted average realized market prices on the first calendar day of each month during the 12-month period ended December 31, 201 1. A ten percent increase in average market prices at December 31, 201 1 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, 201 1 and, accordingly , does not consider drilling results, production and prices subsequent to December 31, 201 1 that may require revisions of proved reserve estimates.
W e have a significant amount of proved undeveloped reserves. W e had 62.5 MMBoe, 79.9 MMBoe and 73.0 MMBoe of proved undeveloped reserves, representing 52%, 51% and 52% ofour total proved reserves at December 31, 2012, 201 1 and 2010, respectively

.Approximately 34.5MMBoe, or 55%, and22.5MMBoe, or 36%, ofourprovedundevelopedreserves atDecember 31, 2012, are attributable to the Eagle Ford Shale and Barnett Shale, respectively

. W e currently expect to drill wells associated with these undeveloped reserves within the next five years. Because our depletion rate is based on the ratio ofproduction 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 or the significant addition of proved developed reserves through acquisition or exploration. Ifour level oftotal proved reserves and future development costs were to remain constant and average market prices
were to decline, a lower depletion rate would result in an impairment of oil and gas properties earlier or to a larger extent than would a higher depletion rate.
Oil and Gas Reserve Estimates Over 99% ofthe proved oil and gas reserve estimates as ofDecember 31, 2012 included in this document have been prepared byR yder ScottCompanyPetroleumEngineersandLaRochePetroleumConsultants,Ltd.,independentthirdpartyreserveengineers. Reserve engineering is a subjective process of estimating underground accumulations ofhydrocarbons 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 ofthis data can vary
. The process also requires assumptions regarding drilling and operating costs, taxes and availability offunds. The oil and gas reserve estimation and disclosure requirements mandate certain ofthese 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 Of

ficer and Chief Operating Of ficer

. Because these estimates depend on many assumptions, all of which may dif fer from actualresults,reserve quantities actuallyrecoveredmaybe significantly dif ferentthan estimated. Materialrevisionstoreserve estimates may be made depending on the results of drilling, testing, and production.
Y ou 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, 2012, would have decreased or increased our DD&A expense by approximately 8.9% or 10.9%, respectively , for the fourth quarter of2012

. Derivative Instruments W e use derivative instruments, typically fixed-rate swaps, costless collars, puts, calls and basis dif ferential swaps, to manage commodity price risk associated with a portion ofour 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 ofour 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 ofchanges in the fair value ofderivative instruments are recognized as gain (loss) on derivative instruments, net in the consolidated statements of income. Realized gains and losses as a result of cash settlements with counterparties to our derivative instruments are also58

recorded as gain (loss) on derivative instruments, net in the consolidated statements of income. W e of fset fair value amounts recognized for derivative instruments executed with the same counterparty and subject to master netting agreements.
Our Board ofDirectors establishes risk management policies and reviews derivative instruments, including volumes, types ofinstruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only by the President or ChiefFinancial Of ficer after consultationwith and concurrencebythePresident, ChiefFinancial Of ficer and Chairman of the Board. The master contracts with approved counterparties identify the President and Chief Financial Of ficer as the only Company representatives authorized to execute trades.
Income T axes Deferred income taxes are recognized at each reporting period for the future tax consequences of dif ferences 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 dif

ferences are expected to af fect taxable income. W

e routinely assess the realizability of our deferred tax assets and consider our estimate of future taxable income based on production ofproved reserves at estimated future pricing in making such assessments. Ifwe conclude that it is more likely than not that some portion or all ofthe deferred tax assets will not be realized, the deferred tax assets are reduced by a valuation allowance. W e classify interest and penalties associated with income taxes as interest expense. Commitments and Contingencies 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.
V olatility of Oil and Gas Prices Our revenues, future rate ofgrowth, results ofoperations, financial position and ability to borrow funds or obtain additional capital are substantially dependent upon prevailing prices of oil and gas. W e review the carrying value ofour oil and gas properties on a quarterly basis using the full cost method ofaccounting. See “ —Summary of Critical Accounting Policies—Oil and Gas Properties.”
W e use 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 typically used are fixed-rate swaps, costless collars,puts, calls andbasis dif ferential swaps.Underthese derivative instruments,payments arereceived
or made based on the dif

ferential 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, butvarying,portion offorecastedproductionupto 60 months.The derivative instruments are carried at fairvalue inthe consolidated balance sheets, with changes in fair value recognized as gain (loss) on derivative instruments, net in the consolidated statements of income for the period in which the changes occur
. The fair value ofderivative instruments at December 31, 2012 and 201 1 was a net asset of$29.2 million and $37.5 million, respectively

. The following sets forth a summary ofthe net fair value of our derivative instruments by counterparty:

Counterparty December 31, 2012 December 31, 2011 Credit Suisse 40% 68% BNP Paribas 33% 19% Societe Generale 22% 2% BBVA Compass 3%

—% Wells Fargo 2%

—% Shell Energy North America (US) LP

—% 6% Credit Agricole

—% 5% T otal 100% 100%

Master netting agreements are in place with each ofthese 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 donot currentlyrequire our counterpartiestopost collateralto supportthe assetpositions ofour derivative instruments. As such,we are exposedto creditriskto the extent ofnonperformanceby the counterparties to our derivative instruments.Although
we do not currently anticipate such nonperformance, we continue to monitor the financial viability ofour counterparties. Because59

Credit Suisse, CreditAgricole, BBV A Compass, W

ells Fargo, and Societe Generale are lenders under our revolving credit facility , we are not required to post collateral with respect to derivative instruments in a net liability position with these counterparties, as the contracts are secured by our revolving credit facility

. The following sets forth a summary ofourU.S.natural gas derivativepositions at averageNYMEXprices as ofDecember 31, 2012

.

Period V olume (in MMBtu) W eighted A verage Floor Price ($/MMBtu) W eighted A verage Ceiling Price ($/MMBtu) 2013 18,250,000 $ 4.63 $ 4.63 2014 3,650,000 $

— $ 5.50

The following sets forth a summary ofour U.S. crude oil derivative positions at average NYMEX prices as ofDecember 31, 2012

.

Period V olume (in Bbls) W eighted A verage Floor Price ($/Bbls) W eighted A verage Ceiling Price ($/Bbls) 2013 2,774,000 $ 88.91 $ 102.43 2014 2,555,000 $ 90.06 $ 98.51 2015 1,441,750 $ 89.54 $ 96.49 2016 244,000 $ 85.00 $ 104.00

In connection with the crude oil derivative instruments above, we entered into protective put spreads. For 2014, at market prices below the short put price of $65.00, the floor price becomes the market price plus the put spread of $20.00 on 182,500 of the 2,555,000 Bbls and the remaining 2,372,500 Bbls would have a floor price of $90.06

.

Period V olume (in Bbls) W eighted A verage Short Put Price ($/Bbls) W eighted A verage Put Spread ($/Bbls) 2014 182,500 $ 65.00 $ 20.00 2015 365,000 $ 65.00 $ 20.00 2016 244,000 $ 65.00 $ 20.00

For the years ended December 31, 2012, 201 1 and 2010, we recorded the following related to our oil and gas derivative instruments:
Year Ended December 31, 2012 2011 2010

(In thousands) Realized gain (loss) on derivative instruments, net $ 41,122 $ 35,452 $ 33,218 Unrealized gain (loss) on derivative instruments, net (9,751) 12,971 14,564 Gain (loss) on derivative instruments, net $ 31,371 $ 48,423 $ 47,782
Item 7A. Qualitative and Quantitative Disclosures about Market Risk Commodity Risk Our primary market risk exposure is the commodity pricing applicable to our oil and gas production. The prices we realize
on the sale of such production are primarily driven by the prevailing worldwide price for oil and spot prices ofnatural gas. The ef fects 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 $35.8 million impact on our revenues for the year ended December 31, 2012

. W e use 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 expenditureprogram.The derivative instrumentswetypicallyuse include fixed-rate swaps, costless collars, puts, calls and basis dif ferential swaps. Our current long-term strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to 60 months. W e do not hold or issue derivative instruments60

for trading purposes. W

e recorded gains on derivative instruments, net of $31.4 million, $48.4 million and $47.8 million for the years ended December 31, 2012, 201 1 , and 2010, respectively

. Financial Instruments and Debt Maturities In addition to our derivative instruments, our other financial instruments include cash and cash equivalents, receivables, payables and long-term debt. The carrying amounts ofcash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature ofthese instruments. The fair values ofborrowings under our revolving credit facility approximate the carrying amounts as of December 31, 2012, and were based upon interest rates currently available to us for borrowings with similar terms. The fair values of our convertible senior notes, 8.625% Senior Notes, and 7.50% Senior Notes at December 31, 2012 were estimated at approximately $73.8 million, $645.0 million, and $308.3 million, respectively , and were based on quoted market prices. As ofDecember 31, 2012, scheduled maturities oflong-term debt are $595.2 million in 2018 and $300.0 million in 2020.
Item 8. Financial Statements and Supplementary Data The financial statements and information required by this Item appears on pages F-1 through F-40 ofthis Annual Report on Form 10-K.
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosures None. Item 9A. Controls and Procedures (a) Disclosure Controls and Procedures W e 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 Of ficer and Chief Financial Of ficer, 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 ofmanagement, including our ChiefExecutive Of ficer and ChiefFinancial Of ficer, ofthe ef fectiveness ofour disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as ofthe end oftheperiod coveredbythisAnnualReport onForm 10-K.As describedbelowunderparagraph (b) withinManagement’s Annual Report on Internal Control over Financial Reporting, our Chief Executive Of ficer and Chief Financial Of ficer have concluded that, as ofthe end ofthe period covered by this Annual Report on Form 10-K, our disclosure controls and procedures
were ef fective 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 Of

ficer and ChiefFinancial Of ficer, as appropriate to allow timely decisions regarding required disclosure.
The audit report ofKPMG, 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
Ourmanagement 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 assuranceregardingthereliability offinancialreporting andthepreparation offinancial statements for externalpurposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that:

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

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

• provide reasonable assurance regarding prevention or timely detection ofunauthorized acquisition, use, or disposition of our assets that could have a material ef fect on the financial statements.61

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 offraud. Controls
are susceptible to manipulation, especially in instances of fraud caused by collusion oftwo or more people, including our senior management.Also, projections ofany evaluation ofef fectiveness 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.
Underthe supervision andwith theparticipation ofour ChiefExecutive Of ficer and ChiefFinancial Of ficer, ourmanagement conducted an evaluation ofthe ef fectiveness of our internal control over financial reporting as ofDecember 31, 2012

. In making this evaluation, management used the Internal Contr ol – Integrated Framework issued by the Committee of Sponsoring Organizations ofthe T

readway Commission (“COSO”). Based on the results of our evaluation, our management concluded that
our internal control over financial reporting was ef fective as ofDecember 31, 2012

. KPMG LLP

, our independent registered public accounting firm that audited our consolidated financial statements, has also issued its own attestation report on the ef fectiveness of our internal control over financial reporting as of December 31, 2012, which is filed with this Annual Report on Form 10-K. (c) Changes in Internal Control over Financial Reporting
Therehavenotbeen any changes in our internal control over financialreporting during the fiscal quarter ended December 31, 2012 that have materially af fected, or are reasonably likely to materially af fect, our internal control over financial reporting.
Item 9B. Other Information None.62

P AR T III Item 10. Directors, Executive Officers and Corporate Governance The information required by this item is incorporated herein by reference to our definitive Proxy Statement (the “2013 Proxy Statement”) for our 2013 annual meeting ofshareholders. The 2013 Proxy Statement will be filed with the SEC not later than 120 days subsequent to December 31, 2012

. Item 11. Executive Compensation The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012

. 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 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012

. Item 13. Certain Relationships and Related T ransactions, and Director Independence The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012

. Item 14. Principal Accountant Fees and Services The information required by this item is incorporated herein by reference to the 2013 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2012

.63

P AR T IV
Item 15. Exhibits and Financial Statement Schedules (a)(1) Financial Statements The response to this item is submitted in a separate section ofthis Annual Report on Form 10-K. (a)(2) Financial Statement Schedules None. (a)(3) Exhibits EXHIBIT INDEX
Exhibit Number Description †2.1

— Purchase and Sale Agreement, dated as of March 15, 2012, among ARP Barnett, LLC and Carrizo Oil & Gas, Inc., CLLR, Inc., Hondo Pipeline, Inc. and Mescalero Pipeline, Inc. (incorporated herein by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on May 2, 2012). †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 ofAmendment 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 W ells 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 W ells 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 W

ells 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 W ells 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 W ells 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, 201 1 among Carrizo Oil & Gas, Inc. the subsidiary

guarantors named therein and W ells 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, 201 1). †4.7

— Seventh Supplemental Indenture dated May 4, 201 1 among Carrizo Oil & Gas, Inc. the subsidiary

guarantors named therein and W ells 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, 201 1). †4.8

— Eighth Supplemental Indenture dated August 5, 201 1 among Carrizo Oil & Gas, Inc. the subsidiary

guarantors named therein and W ells 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, 201 1). †4.9

— Ninth Supplemental Indenture dated August 5, 201 1 among Carrizo Oil & Gas, Inc. the subsidiary

guarantors named therein and W ells 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, 201 1).64

†4.10

— T

enth Supplemental Indenture among Carrizo Oil & Gas, Inc., the Subsidiary Guarantors named therein and W ells Fargo Bank, National Association, as trustee, dated as of September 10, 2012 (incorporated herein by reference to Exhibit 4.2 to the Company Current Report on Form 8-K filed on September 13, 2012). †4.11

— Eleventh Supplemental Indenture dated November 6, 2012 among Carrizo Oil & Gas, Inc., the

subsidiary guarantors named therein and W ells 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 September 30, 2012). †4.12

— T

welfth Supplemental Indenture dated November 6, 2012 among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and W ells 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 September 30, 2012). †4.13

— Thirteenth Supplemental Indenture dated November 6, 2012 among Carrizo Oil & Gas, Inc., the

subsidiary guarantors named therein and W ells 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 September 30, 2012). †4.14

— Fourteenth Supplemental Indenture dated November 6, 2012 among Carrizo Oil & Gas, Inc., the

subsidiary guarantors named therein and W ells 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 September 30, 2012). †4.15

— Of

ficers’Certificate of the Company dated as of November 17, 201 1 (incorporated herein by reference to Exhibit 4.5 to the Company’s Current Report on Form 8-K filed on November 17, 201 1). †4.16

— Form ofW arrant 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, 201 1) *†10.1

— Amended and Restated Incentive Plan of the Company ef fective as ofApril 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

— First Amendment dated May 16, 2012 to Amended and Restated 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 May 22, 2012). *†10.3

— 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). *†10.4

— 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). *†10.5

— 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). *†10.6

— 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). *†10.7

— 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). *†10.8

— 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). *†10.9

— Form of Stock Option A ward 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). *†10.10

— Form of Director Restricted Stock A ward 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).65

*†10.11

— Form of Director Restricted Stock A ward 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). *†10.12

— Form of Employee Restricted Stock A ward 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). *†10.13

— Form of 2010 Employee Restricted Stock Unit A ward 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). *†10.14

— Form of 2009 Employee Restricted Stock Unit A ward 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). *†10.15

— Form of 2010 Employee Cash Settled Stock Appreciation Rights A ward 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). *†10.16

— Form of 2009 Employee Cash or Stock Settled Stock Appreciation Rights A ward 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). *†10.17

— 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). *†10.18

— Form of 2009 Employee Cash-Settled Stock Appreciation Rights A ward Agreement pursuant to the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (incorporated herein by reference to Exhibit 10.1 1 to the Company’s Current Report on Form 8-K filed on June 9, 2009). *†10.19

— Form of Independent Contractor Restricted Stock A ward Agreement (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on May 30, 2006). *†10.20

— Form of Employee Restricted Stock A ward 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). †10.21

— S Corporation T ax Allocation, Payment and Indemnification Agreement among the Company and Messrs. Loyd, W

ebster, Johnson, Hamilton and W ojtek (incorporated herein by reference to Exhibit 10.8 to the Company’s Registration Statement on Form S-1 (Registration No. 333-29187)). †10.22

— S Corporation T ax Allocation, Payment and Indemnification Agreement among Carrizo Production, Inc. and Messrs. Loyd, W ebster, Johnson, Hamilton and W ojtek (incorporated herein by reference to Exhibit 10.9 to the Company’s Registration Statement on Form S-1 (Registration No. 333-29187)). †10.23

— Amended and Restated Registration Rights Agreement dated December 15, 1999 among the Company , Paul B. Loyd Jr., Douglas A. P . Hamilton, Steven A. W

ebster, S.P

. Johnson IV

, Frank A. W

ojtek and DAPHAM Partnership, L.P . (incorporated herein by reference to Exhibit 99.5 to the Company’s Current Report on Form 8-K filed December 22, 1999). †10.24

— Registration Rights Agreement dated February 20, 2002 among the Company , Mellon V

entures, L.P

. and Steven A. W

ebster (incorporated herein by reference to Exhibit 99.5 to the Company’s Current Report on Form 8-K filed February 27, 2002). †10.25

— Credit Agreement dated as of January 27, 201 1 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, 201 1). †10.26

— First Amendment, dated as of March 26, 2012, to Credit Agreement dated as of January 27, 201 1,

among Carrizo Oil & Gas, Inc., BNP Paribas as administrative agent, and the Lenders party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012).66

†10.27

— Second Amendment to Credit Agreement, dated as of September 4, 2012, among Carrizo Oil & Gas,

Inc., as borrower, W

ells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 5, 2012). †10.28

— Third Amendment to Credit Agreement, dated as of September 27, 2012, among Carrizo Oil & Gas,

Inc., as borrower, W

ells Fargo Bank, National Association, as administrative agent, and the lender parties thereto (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012). †10.29

— Senior Secured Multicurrency Credit Facility Agreement dated as of January 28, 201 1 among Carrizo

UK Huntington Ltd., as Borrower, Carrizo Oil & Gas, Inc., as Parent, and BNP Paribas and Societe Generale as Lead Arrangers, Bookrunners and Original Lenders (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 2, 201 1). †10.30

— First Amendment, entered into as ofApril 17, 2012, to Senior Secured Multicurrency Credit Facility

Agreement dated as of January 28, 201 1, among Carrizo U.K. Huntington Ltd., as Borrower, Carrizo Oil & Gas, Inc., as Parent, and BNP Paribas and Societe Generale as Lead Arrangers, Bookrunners and Original Lenders (incorporated herein by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2012). †10.31

— Form of Indemnification Agreement between the Company and each of its directors and executive

of ficers (incorporated herein by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10- K for the year ended December 31, 1997). †10.32

— Form ofAmendment to Director Indemnification Agreement (incorporated herein by reference to

Exhibit 99.8 to the Company’s Current Report a Form 8-K filed February 27, 2002). †10.33

— Omnibus Amendment among Carrizo (Marcellus) LLC, Carrizo Oil & Gas, Inc., A vista 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). †10.34

— Amended and Restated Participation Agreement, dated as of November 16, 2010, and ef fective as of October 1, 2010, among Carrizo (Marcellus) WV LLC, Carrizo Oil & Gas, Inc., A vista 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 LaRoche Petroleum Consultants, Ltd. 23.3

— Consent of R yder Scott Company

, L.P . (U.S.). 23.4

— Consent of R yder Scott Company

, L.P . (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 LaRoche Petroleum Consultants, Ltd. as of December 31,

2012. 99.2

— Summary of Reserve Report and Report of R yder Scott Company

, L.P . as of December 31, 2012 (U.S.). 99.3

— Summary of Reserve Report and Report of R yder Scott Company

, L.P . as of December 31, 2012 (U.K.).

† Incorporated by reference as indicated. * Management contract or compensatory plan or arrangement.F-1 INDEX TO CONSOLIDA TED FINANCIAL

ST A TEMENTS

PAGE Reports of Independent Registered Public Accounting Firm Consolidated Balance Sheets, December 31, 2012 and 201 1 Consolidated Statements of Income for the Y ears Ended December 31, 2012, 201 1 and 2010 Consolidated Statements of Shareholders’Equity for the Y ears Ended December 31, 2012, 201 1 and 2010 Consolidated Statements of Cash Flows for the Y ears Ended December 31, 2012, 201 1 and 2010 Notes to Consolidated Financial Statements F-2 F-4 F-5 F-6 F-7 F-8F-2 Report of Independent Registered Public Accounting Firm
The Board ofDirectors and Shareholders Carrizo Oil & Gas, Inc.:
W e have audited the accompanying consolidated balance sheets of Carrizo Oil & Gas, Inc. and subsidiaries (the Company) as of December 31, 2012 and 201 1, and the related consolidated statements ofincome, shareholders’ equity , and cash flows for each of the years in the three-year period ended December 31, 2012. These consolidated financial statements are the responsibility ofthe Company’smanagement. Ourresponsibility isto express an opinion onthese consolidated financial statementsbased on our audits.
W e conducted our audits in accordance with the standards ofthe 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 ofmaterial 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. W e 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, 2012 and 201 1, and the results oftheir operations and their cash flows for each ofthe years in the three-year period ended December 31, 2012, in conformity with generally accepted accounting principles.
W e 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 financialreporting as ofDecember 31, 2012,based on criteria established inInternal Contr ol – Integrated Framework issued by the Committee of Sponsoring Organizations of the T readway Commission (COSO), and our report dated February 27, 2013 expressed an unqualified opinion on the ef fectiveness ofthe Company’s internal control
over financial reporting.
/s/ KPMG LLP Houston, T

exas February 27, 2013F-3 Report of Independent Registered Public Accounting Firm
The Board ofDirectors and Shareholders Carrizo Oil & Gas, Inc.:
W e have audited Carrizo Oil & Gas Inc.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Contr ol – Integrated Framework issued by the Committee of Sponsoring Organizations ofthe T readway Commission (COSO). Carrizo Oil & Gas Inc.’s management is responsible formaintaining ef fective internal control over financial reporting and for its assessment of the ef fectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting as presented within Item 9A. Contr ols and Pr

ocedur es
. Our responsibility is to express an opinion on Carrizo Oil & Gas, Inc.’s internal control over financial reporting based on our audit.
W e 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 ef fective internal control
over financial reporting was maintained in all material respects. Our audit included obtaining an understanding ofinternal control
over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating ef fectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. W e believe that our audit provides a reasonable basis for our opinion.
Acompany’s internal control over financialreporting is aprocess designedtoprovidereasonable assuranceregardingthereliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.Acompany’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance ofrecords that, in reasonable detail, accurately and fairly reflect the transactions and dispositions ofthe 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 ef

fect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections ofany evaluation ofef fectiveness 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, ef fective internal control over financial reporting as ofDecember 31, 2012, based on criteria established in Internal Contr ol – Integrated Framework issued by the COSO.
W e also have audited, in accordance with the standards ofthe Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Carrizo Oil & Gas, Inc. and subsidiaries as of December 31, 2012 and 201 1, and the related consolidated statements of income, shareholders’ equity , and cash flows for each of the years in the three-year period ended December 31, 2012, and our report dated February 27, 2013 expressed an unqualified opinion on those consolidated financial statements. /s/ KPMG LLP Houston, T

exas February 27, 2013F-4 CARRIZO OIL

& GAS, INC. CONSOLIDA

TED BALANCE SHEETS

December 31, 2012 2011 (In thousands, except per share amounts) ASSETS CURRENT ASSETS Cash and cash equivalents $ 52,095 $ 26,397 Accounts receivable, net Oil and gas sales 48,754 21,988 Joint interest billing 60,561 31,050 Related party 9,815

— Other 3,506 1,740 Current assets held for sale 1,882 3,874 Advances to operators 3,784 97 Fair value of derivative instruments 23,981 27,877 Prepaids and other current assets 4,327 7,374 Total current assets 208,705 120,397 PROPER TY AND EQUIPMENT, NET Oil and gas properties using the full cost method of accounting Proved oil and gas properties, net 1,152,548 837,750 Unproved properties, not being amortized 323,688 394,429 Other property and equipment, net 11,438 8,738 TOT AL PROPER

TY AND EQUIPMENT, NET 1,487,674 1,240,917 LONG-TERM ASSETS HELD FOR SALE 132,626 78,731 DEFERRED FINANCING COSTS, NET 23,914 20,321 INVESTMENT 2,523 2,523 FAIR V ALUE OF DERIV

A TIVE INSTRUMENTS 5,180 9,617 DEFERRED INCOME T AXES 21,272 53,517 OTHER ASSETS 2,102 1,657 TOT AL ASSETS $ 1,883,996 $ 1,527,680 LIABILITIES AND SHAREHOLDERS’ EQUITY CURRENT LIABILITIES Accounts payable, trade $ 44,775 $ 25,672 Revenue and royalties payable 82,300 54,600 Current taxes payable 765 1,048 Accrued drilling costs 60,729 89,152 Accrued interest 18,012 11,607 Other accrued liabilities 27,680 21,139 Advances forjoint operations 8,069 54,179 Deferred income taxes 7,925 9,685 Current liabilities associated with assets held for sale 48,663 4,238 Total current liabilities 298,918 271,320 LONG-TERM DEBT, NET OF DEBT DISCOUNT 967,808 711,486 LONG-TERM LIABILITIES ASSOCIA TED WITH ASSETS HELD FOR SALE 23,547 22,429 ASSET RETIREMENT OBLIGA TIONS 4,489 7,399 OTHER LIABILITIES 4,218 5,191 COMMITMENTS AND CONTINGENCIES SHAREHOLDERS’ EQUITY Common stock, $0.01 par value (90,000 shares authorized, 40,165 and 39,563 shares issued and outstanding at December 31, 2012 and 201 1, respectively) 402 395 Additional paid-in capital 667,096 647,429 Accumulated deficit (82,482) (137,969) T otal shareholders’ equity 585,016 509,855 TOT AL LIABILITIES AND SHAREHOLDERS’ EQUITY $ 1,883,996 $ 1,527,680

The accompanying notes are an integral part of these consolidated financial statements.F-5 CARRIZO OIL

& GAS, INC. CONSOLIDA

TED ST A TEMENTS OF

INCOME

For the Years Ended December 31, 2012 2011 2010 (In thousands, except per share amounts) OIL AND GAS REVENUES $ 368,180 $ 202,167 $ 138,123 COSTS AND EXPENSES Lease operating 31,471 28,314 23,659 Production tax 13,542 5,697 3,648 Ad valorem tax 9,813 3,625 3,707 Depreciation, depletion and amortization 165,621 84,606 47,030 General and administrative (inclusive of stock-based compensation expense of $11,689, 11,864 and $16,608 for the years ended December 31, 2012, 2011 and 2010, respectively) 48,708 41,539 35,906 Accretion related to asset retirement obligations 372 235 216 TOTAL COSTS AND EXPENSES 269,527 164,016 114,166 OPERATING INCOME 98,653 38,151 23,957 OTHER INCOME AND EXPENSES Gain (loss) on derivative instruments, net 31,371 48,423 47,782 Loss on extinguishment of debt

— (897) (31,023) Interest expense (73,006) (50,998) (43,264) Capitalized interest 24,848 23,369 20,746 Other income (expense), net 267 97 212 INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 82,133 58,145 18,410 INCOME TAX EXPENSE (30,956) (25,611) (6,685) NET INCOME FROM CONTINUING OPERATIONS $ 51,177 $ 32,534 $ 11,725 NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES 4,310 4,095 (1,775) NET INCOME $ 55,487 $ 36,629 $ 9,950

NET INCOME PER COMMON SHARE - BASIC Net income from continuing operations $ 1.29 $ 0.83 $ 0.34 Net income (loss) from discontinued operations 0.11 0.11 (0.05) Net income $ 1.40 $ 0.94 $ 0.29

NET INCOME PER COMMON SHARE - DILUTED Net income from continuing operations $ 1.28 $ 0.82 $ 0.34 Net income (loss) from discontinued operations 0.11 0.10 (0.05) Net income $ 1.39 $ 0.92 $ 0.29

WEIGHTED A

VERAGE COMMON SHARES OUTST ANDING Basic 39,591 39,077 33,861 Diluted 40,026 39,668 34,305

The accompanying notes are an integral part of these consolidated financial statements.F-6 CARRIZO OIL

& GAS, INC. CONSOLIDA

TED ST A TEMENTS OF

SHAREHOLDERS’EQUITY

Common Stock Additional Paid-in Capital Accumulated

Deficit Total

Shareholders’ Equity Shares Amount (In thousands, except share amounts) BALANCE, January 1, 2010 31,100,433 $ 311 $ 431,846 $ (184,548) $ 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

— — 661

— 661 Net income

— — — 9,950 9,950 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 Net income

— — — 36,629 36,629 BALANCE, December 31, 2011 39,562,676 $ 395 $ 647,429 $ (137,969) $ 509,855 Stock options exercised for cash 20,500 1 106

— 107 Stock-based compensation

— — 17,396

— 17,396 Restricted stock awards and units issued, net of forfeitures 488,052 5 (85)

— (80) Other 93,289 1 2,250

— 2,251 Net income

— — — 55,487 55,487 BALANCE, December 31, 2012 40,164,517 $ 402 $ 667,096 $ (82,482) $ 585,016

The accompanying notes are an integral part of these consolidated financial statements.F-7 CARRIZO OIL

& GAS, INC. CONSOLIDA

TED ST A TEMENTS OF

CASH FLOWS
For the Years Ended December 31,

2012 2011 2010

(In thousands) CASH FLOWS FROM OPERA TING ACTIVITIES Net income from continuing operations $ 51,177 $ 32,534 $ 11,725 Adjustments to reconcile net income from continuing operations to net cash provided by operatingactivities-continuing operationsDepreciation, depletion and amortization 165,621 84,606 47,030 Unrealized (gain) loss on derivative instruments, net 9,751 (12,971) (14,564) Accretion related to asset retirement obligations 372 235 216 Loss on extinguishment of debt

— 897 31,023 Stock-based compensation, net of amounts capitalized 11,689 11,864 16,608 Allowance for doubtful accounts (337) 31 485 Deferred income taxes 30,142 24,546 2,449 Amortization of debt discount and deferred financing costs, net of amounts capitalized 4,584 3,061 7,716 Other, net 4,175 3,105 3,097Changes in operating assets and liabilitiesAccounts receivable (67,120) (23,910) (10,040) Accounts payable 26,942 33,457 913 Accrued liabilities 21,832 9,354 (69) Other, net (5,757) (11,298) (2,173) Net cash provided by operating activities - continuing operations 253,071 155,511 94,416 Net cash used in operating activities - discontinued operations (845) (1,173)

— Net cash provided by operating activities 252,226 154,338 94,416 CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures - oil and gas properties (735,711) (516,004) (340,784) Capital expenditures - other property and equipment (4,176) (1,363) (843) Increase (decrease) in capital expenditure payables and accruals (9,880) 49,346 22,540 Proceeds from sales of oil and gas properties, net 341,597 167,265 54,217 Advances to operators (3,687) 390 53 Advances for joint operations (46,110) 50,772 1,668 Other, net (7,184) (474) (966)

Net cash used in investing activities - continuing operations (465,151) (250,068) (264,115) Net cash used in investing activities - discontinued operations (42,265) (35,930) (6,181) Net cash used in investing activities (507,416) (285,998) (270,296) CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from borrowings and issuances 1,040,772 879,061 910,127 Debt repayments (796,000) (752,660) (917,148) Payments of debt issuance and retirement costs (7,101) (9,622) (12,213) Proceeds from common stock offerings, net of offering costs

— — 188,534 Proceeds from stock options exercised 107 47 690

Net cash provided by financing activities - continuing operations 237,778 116,826 169,990 Net cash provided by financing activities - discontinued operations 41,914 38,818 6,181 Net cash provided by financing activities 279,692 155,644 176,171 NETINCREASE IN CASH AND CASH EQUIV ALENTS FROM CONTINUING OPERA TIONS 25,698 22,269 291 NETINCREASE (DECREASE) IN CASH AND CASH EQUIV ALENTS FROM DISCONTINUED OPERA TIONS (1,196) 1,715

— CASH AND CASH EQUIV ALENTS, beginning ofyear - continuing operations 26,397 4,128 3,837 CASH AND CASH EQUIV ALENTS, end ofyear - continuing operations $ 52,095 $ 26,397 $ 4,128
CASH AND CASH EQUIV ALENTS, beginning ofyear - discontinued operations 1,715

— — CASH AND CASH EQUIV ALENTS, end ofyear - discontinued operations $ 519 $ 1,715 $

— SUPPLEMENT

AL CASH FLOW DISCLOSURES Cash paid for interest, net of amounts capitalized $ 43,629 $ 26,077 $ 24,218 Cash paid for income taxes $ 587 $ 4,156 $ 95

The accompanying notes are an integral part of these consolidated financial statements.F-8 CARRIZO OIL

& GAS, INC. NOTES TO CONSOLIDA TED FINANCIAL

ST A TEMENTS
1. Nature of Operations Carrizo Oil & Gas, Inc. is a Houston-based energy company which, together with its subsidiaries (collectively , the “Company”), is actively engaged in the exploration, development, and production of oil and gas primarily from resource plays located in the United States. The Company’s current operations are principally focused in proven, producing oil and gas plays primarily in the Eagle Ford Shale in South T exas, the Niobrara Formation in Colorado, the Marcellus Shale in Pennsylvania, the Barnett Shale in North T exas, and the Utica Shale in Ohio.
2. Summary of Significant Accounting Policies Basis ofPresentation and Principles ofConsolidation The consolidated financial statements include the accounts of the Company 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 limited liability companies where the Company , as a partner or member, has undivided interests in the oil and gas properties. Reclassifications Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications had no ef fect on total assets, total liabilities, total shareholders’ equity , net income or net cash provided by or used in operating, investing or financing activities.
Discontinued Operations On December 27, 2012, the Company agreed to sell Carrizo UK Huntington Ltd, a wholly owned subsidiary of the Company (“Carrizo UK”), and all ofits interest in the Huntington Field discovery , where Carrizo UK owned a 15% non-operated working interest and certain overriding royalty interests. The sale closed on February 22, 2013. Accordingly , the Company classified the U.K. North Sea assets and associated liabilities as current and long-term assets held for sale and current and long-term liabilities associated with assets held for sale in the consolidated balance sheets. The related results ofoperations and cash flows have been classified as discontinued operations, net ofincome taxes, in the consolidated statements ofincome, statements ofcash flows and condensed consolidating financial information. Unless otherwise indicated, the information in these notes relate to the Company’s continuing operations. Information related to assets held for sale and discontinued operations is included in “Note 3. Assets Held for Sale and Discontinued Operations”, “Note 14. Condensed Consolidating Financial Information” and “Note 15. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited).”
Use ofEstimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that af fect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date ofthe financial statements and the reported amounts ofrevenues and expenses during the periods reported. Actual results could dif fer from these estimates. The Company evaluates subsequent events through the date the financial statements are issued.
V olumes of proved oil and gas reserves, which include significant estimates, are used in calculating the amortization of proved oil and gas property costs, the present value offuture net revenues included in the full cost ceiling test, estimates offuture taxable income used in assessing the realizability of deferred tax assets, and asset retirement obligations. Other significant estimates include the impairment ofunproved properties, fair values ofderivative instruments, stock-based compensation, the collectability of outstanding receivables, and contingencies. Proved oil and gas reserve estimates have numerous inherent uncertainties. The accuracy ofany reserve estimate is a function ofthe quality and quantity ofavailable data and the application ofengineering and geological interpretation andjudgment to available data. Subsequent drilling results, testing and production mayjustify revisions of such estimates. Accordingly , proved oil and gas reserve estimates are often dif ferent from the quantities ofoil 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 af fected 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 af fect these significant estimates materially in the near term.F-9

Cash and Cash Equivalents Cash and cash equivalents include highly liquid investments with original maturities ofthree months or less.
Accounts Receivable andAllowancefor DoubtfulAccounts The Company establishes an allowance for doubtful accounts when it determines that it will not collect all or a part ofan accounts receivablebalance.The Company assessesthe collectability ofits accountsreceivable on a quarterlybasis and adjuststhe allowance
as necessary using the specific identification method. A roll forward ofthe allowance for doubtful accounts is as follows:

Amount (In thousands) January 1, 2010 $ 2,036 Charged to general and administrative 485 Amounts written of

f (51) December 31, 2010 2,470 Charged to general and administrative 31 Amounts written of

f (197) December 31, 2011 2,304 Recoveries included in general and administrative (737) Amounts written of

f (208) December 31, 2012 $ 1,359

Concentration ofCredit Risk Substantially all ofthe Company’s accounts receivable result from oil and gas sales,joint interest billings to third-party working interest owners in the oil and gas industry or development advances to third-party operators for drilling and completion costs of wells in progress. This concentration ofcustomers andjoint interest owners may impact the Company’s overall credit risk in that these entities may be similarly af fected by changes in economic and other industry conditions. The Company does not require collateral from its customers. The Company generally has the right to of fset revenue against relatedbillings tojoint interest owners. Derivative instruments subject the Company to a concentration of credit risk. See “Note 12. Derivative Instruments” for further discussion of concentration of credit risk related to the Company’s derivative instruments. Major Customers For the year ended December 31, 2012, two customers accounted for approximately 53% and 10% ofthe Company’s oil and gas revenues. Fortheyears endedDecember 31,201 1 and2010, one customer accounted for approximately43% and 63%,respectively , ofthe Company’s oil and gas revenues. Oil and Gas Properties Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to costs centers established on a country-by-country basis. Internal costs, including payroll and stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized and totaled $1 1.8 million, $9.6 million, and $5.3 million for the years ended December 31, 2012, 201 1 and 2010, respectively

. Internal 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 ofone barrel ofoil or natural gas liquids to six thousand cubic feet ofgas, which represents their approximate relative energy content. The equivalent unit-of-production rate is computed on a quarterly basisby dividingproductionbyproved oil and gas reserves at thebeginning ofthe 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 ofestimated salvage values.A verage depreciation, depletion and amortization (“DD&A”) per Boe was $17.55, $1 1.26, and $7.67 for the years ended December 31, 2012, 201 1 and 2010, respectively

. Unprovedproperties,whicharenotamortized,includeunevaluatedleaseholdand seismiccostsassociatedwith specificunevaluated properties, the cost of exploratory wells in progress, and related capitalized interest. Significant costs of unevaluated propertiesF-10

and exploratory wells in progress 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 leasehold and seismic costs within the next two to five years and exploratory wells in progress within the next year
. Individually insignificant costs of unevaluated properties 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 and exploratorywells inprogress of$24.8million, $23.4million, and $20.7million fortheyears ended December 31, 2012, 201 1 and 2010, respectively

. Interest is capitalized on the average balance ofunevaluated leasehold and seismic costs and the average balance ofexploratory wells in progress 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

. Through December 31, 2012, the Company has 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 (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 ofproperties not subject to amortization, and (C) the lower of cost or estimated fair value ofunproved properties included in the costs being amortized; less (ii) related income tax ef fects. 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 ifhigher 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 ofeach month during the preceding 12-month period prior to the end ofthe current reporting period. Prices are held constant indefinitely and are not changed except where dif ferent prices are fixed and determinable from applicable contracts fortheremainingterm ofthose contracts.Pricesused inthe ceilingtest computation donot includethe impact ofderivative instruments because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. Depreciation ofother property and equipment is recognized using the straight-line method based on estimated useful lives ranging from five to ten years. Deferred Financing Costs Deferred financing costs were $23.9 million (net of $3.5 million of accumulated amortization) and $20.3 million (net of $2.8 million of accumulated amortization) as of December 31, 2012 and 201 1 , respectively and include legal fees, accounting fees, underwriting fees, printing costs, and other direct costs associated with the issuance of the debt securities and costs associated withrevolving credit facilities.The capitalized costs are amortizedto interest expense,net ofamounts capitalizedusingthe ef fective interest method over the terms ofthe debt securities or credit facilities.
Investment 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.
Financial Instruments The Company’s financial instruments consist ofcash and cash equivalents, receivables, payables, derivative instruments and longterm debt. The carrying amounts ofcash and cash equivalents, receivables and payables approximate fair value due to the highly liquid or short-term nature ofthese instruments. The fair values ofderivative 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 amounts of long-term debt under the Company’s revolving credit facility approximate fair value as the borrowingsbear interest at variable rates ofinterest. The carrying amounts ofthe Company’s senior notes and convertible senior notes may not approximate fair value because the notes bear interest at fixed rates of interest. See “Note 7. Long-T erm Debt” and “Note 13. Fair V alue Measurements.”
Asset Retirement Obligations The Company’s oil and gas properties require expenditures to plug and abandon wells after the reserves have been depleted. The asset retirement obligation is recognized as a liability at its fair value when the well is drilled with an associated increase in oilF-1 1

and gas property costs. Asset retirement obligations require estimates ofthe 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 obligations are discounted using a credit-adjusted risk-free interest rate which is accreted over the estimated productive lives of the oil and gas properties to their expected settlement values. Estimated costs consider historical experience, third party estimates and state regulatory requirements and do not consider salvage values. At least annually , the Company reassesses its asset retirement obligations to determine whether a change in the estimated obligation is necessary
. Revisions in estimated liabilities can result from changes in estimated inflation rates, changes in estimated costs to plug and abandon wells and changes in estimated timing ofoil and gaspropertyretirement.Upon settlement ofthe liability , the Company either settles the obligation for itsrecorded amount or incurs a gain or lossupon settlement,which is included in oil and gasproperty costs. On an interimbasis,the Companyreassesses the estimated cash flows underlying the obligation when indicators suggest the estimated cash flows underlying the obligation have materially changed and updates its estimated obligation ifnecessary
. Commitments and Contingencies 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.
Revenue Recognition 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 ofits remaining proved oil and gas reserves. Oil and gas sales volumes are not significantly dif ferent from the Company’s share ofproduction and as of December 31, 2012 and 201 1 , the Company did not have any material production imbalances.
Derivative Instruments The Company uses derivative instruments, typically fixed-rate swaps, costless collars, puts, calls and basis dif ferential 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 income. Realized gains and losses as a result ofcash settlements with counterparties to the Company’s derivative instruments are also recorded as gain (loss) on derivative instruments, net in the consolidated statements of income. The Company of fsets fair value amounts recognized for derivative instruments executed with the same counterparty and subject to master netting agreements. The Company’s Board ofDirectors establishes risk management policies and reviews derivative instruments, including volumes, types ofinstruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only by the President or ChiefFinancial Of ficer after consultation with and concurrence by the President, ChiefFinancial Of ficer and Chairman ofthe Board. The master contracts with approved counterparties identify the President and ChiefFinancial Of ficer as the only Company representatives authorized to execute trades. See “Note 12. Derivative Instruments” for further discussion of the Company’s derivative instruments.F-12

Stock-Based Compensation The Company grants stock options, stock appreciation rights (“SARs”) that may be settled in cash or common stock at the option ofthe Company

, SARs that may only be settled in cash, restricted stock awards and units to directors, employees and independent contractors. The Companyrecognizedthe following stock-based compensation expense fortheperiods indicatedwhich isreflected
as general and administrative expense in the consolidated statements of income:
Year Ended December 31, 2012 2011 2010

(In thousands) Stock Appreciation Rights $ (2,116) $ 1,546 $ 6,649 Restricted Stock A

wards and Units 17,049 13,965 9,959 14,933 15,511 16,608 Less: amounts capitalized (3,244) (3,647)

— T otal Stock-Based Compensation Expense $ 11,689 $ 11,864 $ 16,608 Income T ax Expense $ 4,449 $ 4,342 $ 6,152

Stock Options and SARs. For stock options and 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 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 ofthe 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 ofgrant. 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:

• The risk-free interest rate is based on the zero-coupon United States T reasury yield for the expected term at date ofgrant.

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

• The volatility ofthe Company’s common stock is based on daily , historical volatility ofthe marketprice ofthe Company’s common stock over a period oftime equal to the expected term and ending on the grant date.

• The expectedterm isbased onhistorical exercises forvarious groups ofdirectors, employees and independent contractors. RestrictedStockAwar

ds and Units

. For restricted stock awards and units, stock-based compensation expense is based on the grantdate fair value and recognized over the vesting period (generally one to three years) using the straight-line method, except for award orunitswithperformance conditions, inwhich casethe Companyusesthe gradedvestingmethod. The fairvalue ofrestricted stock awards and units is based on the price ofthe 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.
Income T axes Deferred income taxes are recognized at each reporting period for the future tax consequences ofdif ferences between the tax bases ofassets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the dif

ferences are expected to af fect taxable income. The Company routinely assesses the realizability of its deferred tax assets and considers its estimate of future taxable income based on production ofproved reserves at estimated future pricing in making such assessments by taxingjurisdiction. Ifthe Company concludes that it is more likely than not that some portion or all ofthe 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.F-13

Net Income From Continuing Operations Per Common Share Supplemental net income from continuing operations per common share information is provided below:
Year Ended December 31, 2012 2011 2010 (In thousands, except per share amounts) Net income from continuing operations $ 51,177 $ 32,534 $ 11,725 Basic weighted average common shares outstanding 39,591 39,077 33,861 Ef fect of dilutive instruments 435 591 444 Diluted weighted average shares outstanding 40,026 39,668 34,305 Net income from continuing operations per common share Basic $ 1.29 $ 0.83 $ 0.34 Diluted $ 1.28 $ 0.82 $ 0.34

Basic net income per common share is based on the weighted average number of shares ofcommon stock outstanding during the period. Diluted net income 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, SARs expected to be settled in common stock, warrants and convertible debt. The Company excludes shares related to restricted stock awards, units and stock options from the calculation of diluted weighted average shares outstanding when the grant prices are greater than the average market prices ofthe common shares for the period as the ef fect would be antidilutive to the computation. The shares excluded for the years ended December 31, 2012, 201 1 and 2010 were not significant. Shares ofcommon stock subject to issuance upon the conversion of the Company’s convertible senior notes did not have an ef fect on the calculation of dilutive shares for the years ended December 31, 2012, 201 1 and 2010 because the conversion price was in excess ofthe market price of the common stock for those periods.
3. Assets Held for

Sale and Discontinued Operations On December 27, 2012, the Company agreed to sell Carrizo UK, and all ofits interest in the Huntington Field discovery , including
a 15% non-operated working interest and certain overriding royalty interests, to a subsidiary ofIona Energy Inc. (“Iona Energy”) for net proceeds ofapproximately $1 16.5 million, subject to final post-closing adjustments, which represents an agreed upon price of$184.0million, includingthe assumption of$55.0million in debt andnetpurchaseprice adjustments.Purchaseprice adjustments primarilyrelatetoworking capital and otheradjustments,transaction costs and accrual ofotherobligationsrelatedtothetransaction. The sale closed on February 22, 2013

. Carrizo UK’s senior secured multicurrency credit facility agreement that was secured by substantially all of Carrizo UK’s assets with limited recourse to the Company (the “Huntington Facility”) was repaid by Iona Energy in connection with the sale transaction described above. As of December 31, 2012 and February 22, 2013, borrowings outstandingundertheHuntingtonFacilitywere $52.0million and $55.0million,respectively

.Additionally ,thenetproceeds include non-refundable deposits of $8.0 millionreceivedbythe Company ,in accordancewiththe sale andpurchase agreement, as amended, and approximately $18.5 million in deferred consideration that the Company expects to receive as of the earlier of six months from the agreement closing date or when Iona Energy receives payment for its first lifting of production from the Huntington Field.
The U.K. North Sea assets and associated liabilities have been classified as current and long-term assets held for sale and current and long-term liabilities associated with assets held for sale in the consolidated balance sheets. The related results of operations and cash flows have been classified as discontinued operations, net ofincome taxes, in the consolidated statements ofincome and cash flows. For the years ended December 31, 2012, 201 1 and 2010, the Company’s U.K. North Sea assets had no production or revenues.F-14

The following table summarizes the amounts included in current and long-term assets held for sale and liabilities associated with assets held for sale in the consolidated balance sheets as ofDecember 31, 2012 and 201 1:
December 31, 2012 2011 (In thousands) ASSETS HELD FOR SALE CURRENT ASSETS Cash and cash equivalents $ 519 $ 1,715 Prepaids and other current assets 1,363 2,159 Total current assets held for sale 1,882 3,874 LONG-TERM ASSETS Property and equipment, net 120,732 69,597 Deferred income taxes 11,245 6,238 Other assets 649 2,896 Total long-term assets held for sale $ 132,626 $ 78,731

LIABILITIES ASSOCIATED WITH ASSETS HELD FOR SALE CURRENT LIABILITIES Accrued drilling costs $ 3,800 $ 3,027 Current maturities of long-term debt 33,800

— Other accrued liabilities 11,063 1,211 Total current liabilities associated with assets held for sale 48,663 4,238 LONG-TERM LIABILITIES Long-term debt, net of current maturities 18,200 17,814 Asset retirement obligations 5,243 3,843 Other liabilities 104 772 Total long-term liabilities associated with assets held for sale $ 23,547 $ 22,429F-15

The following table summarizes the amounts included in net income (loss) from discontinued operations, net of income taxes presented in the consolidated statements of income for the years ended December 31, 2012, 201 1 and 2010: For the Years Ended December 31, 2012 2011 2010 (In thousands) OIL AND GAS REVENUES $

— $

— $

— COSTS AND EXPENSES Impairment of oil and gas properties

— — 2,731 General and administrative 62 242

— Accretion related to asset retirement obligations 363 76

— TOTAL COST AND EXPENSES 425 318 2,731 OPERATING LOSS (425) (318) (2,731) OTHER INCOME AND EXPENSES Gain (loss) on derivative instruments, net 258 (1,432)

— Interest expense (3,556) (1,805)

— Capitalized interest 3,556

— — Other income (expense), net (591) 259

— LOSS BEFORE INCOME TAXES (758) (3,296) (2,731) DEFERRED INCOME T AX BENEFIT 5,068 7,391 956 NETINCOME (LOSS) FROM DISCONTINUED OPERA TIONS, NETOF INCOME T

AXES $ 4,310 $ 4,095 $ (1,775)

U.K. Huntington FieldDevelopment Project Credit Facility On January 28, 201 1, the Company and Carrizo UK, as borrower, entered into the Huntington Facility

. The Huntington Facility
was securedby substantially all ofCarrizo UK’s assets and was limited recourse to the Company

. The Huntington Facilityprovided financing for a substantial portion ofCarrizo UK’s share ofcosts associated with the Huntington Field development project in the U.K. North Sea.
As ofDecember 31, 2012, borrowings outstanding under the Huntington Facility were $52.0 million, ofwhich $33.8 million was classified as current, with a weighted average interest rate of 3.79% and no letters of credit had been issued. In connection with the sale ofCarrizo UK, which closed on February 22, 2013, the $55.0 million ofborrowings then outstanding under the Huntington Facility was repaid. DeferredIncome T

axes Carrizo UK is a disregarded entity for U.S. income tax purposes. Accordingly , included in the deferred income tax benefit for the U.K. North Sea is the Company's U.S. deferred income tax benefits of $0.1 million, $1.2 million, and $1.0 million for the years ended December 31, 2012, 201 1 and 2010 respectively

. The related U.S. deferred tax assets have been classified as deferred income taxes of continuing operations in the consolidated balance sheet. Foreign Currency The U.S. dollar is the functional currency for the Company’s operations in the U.K. North Sea. T ransaction gains or losses that
occur due to the realization ofassets and the settlement ofliabilities denominated in a currency other than the functional currency are recorded as Other income (expense), net. 4. Investment 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 forwarrants topurchase Oxane common stock and for certain exclusiveuse andpreferentialpurchase 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 of6%per annum. During the fourth quarter of2008, the Company converted the promissory note into 630,371 shares of Oxane preferred stock. As ofDecember 31, 2012 and 201 1 , the carrying amount ofthe investment in Oxane was $2.5 million

.F-16

5. Property and Equipment, Net At December 31, 2012 and 201 1 , property and equipment, net consisted ofthe following: December 31, 2012 2011 (In thousands) Proved oil and gas properties $ 1,713,827 $ 1,235,487 Accumulated depreciation, depletion and amortization (561,279) (397,737) Proved oil and gas properties, net 1,152,548 837,750 Unproved properties, not being amortized Unevaluated leasehold and seismic costs 238,833 277,425 Exploratory wells in progress 43,803 70,533 Capitalized interest 41,052 46,471 Total costs not subject to amortization 323,688 394,429 Other property and equipment 17,079 12,835 Accumulated depreciation (5,641) (4,097) Other property and equipment, net 11,438 8,738 T otal property and equipment, net $ 1,487,674 $ 1,240,917

Costs not subject to amortization totaling $323.7 million at December 31, 2012 were incurred in the following periods: $177.0 million in 2012, $1 10.0 million in 201 1 , $34.7 million in 2010 and $2.0 million in 2009 and prior years. Sale ofBarnett Shale Properties During the second quarter of201 1, the Company sold a substantial portion of its non-core area Barnett Shale properties to KKR Natural Resources (“KKR”), a partnership formedbetween an af filiate ofKohlberg Kravis Roberts & Co. L.P

. and PremierNatural Resources. Net proceeds received from the sale were approximately $98.0 million, which represents an agreed upon price of approximately $104.0million lessnetpurchaseprice adjustments. Purchaseprice adjustmentsprimarilyrelatetoproceedsreceived by the Company for sales ofhydrocarbons from such properties between the ef fective date ofJanuary 1, 201 1 and the closing date ofMay 17, 201 1. The proceeds from such sale were recognized as a reduction ofproved oil and gas properties. During the second quarter of2012, the Company sold a significant portion of its Barnett Shale properties to an af filiate ofAtlas Resource Partners, L.P

. (“Atlas”). Net proceeds received from the sale were approximately $187.4 million, which represents an agreed upon price of $190.0 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 ef fective date of January 1, 2012 and the closing date ofApril 30, 2012. The proceeds from such sale were recognized as a reduction ofproved oil and gas properties. Sale of Gulf Coast Properties During the third quarter of2012, the Company completed the sale ofsubstantially all ofits legacy producing properties along the onshore GulfofMexico located primarily in T exas and Louisiana. Net proceeds received from the sale were approximately $17.6 million, which represents an agreed upon price of $19.3 million less net purchase price adjustments. Purchase price adjustments primarily relate to proceeds received by the Company for sales ofhydrocarbons from such properties between the ef fective date ofJuly 1, 2012 and the closing date ofSeptember 27, 2012. The proceeds from such sale were recognized as a reduction ofproved oil and gas properties.
Sale ofUtica Properties In October 2012, the Company sold substantially all ofits interests in oil and gas properties dedicated to its Uticajoint venture in the northern portion ofthe Utica Shale play to a third party and received net cash proceeds of$51.7 million, after final post-closing adjustments. Theproceeds from such salewererecognized as areduction ofproved oil and gasproperties,net. Other assets included in the sale were an existing drilling pad and approved well drilling permits associated with the properties. The properties sold are located in Mercer and Crawford counties in Pennsylvania and T rumbull county in Ohio.F-17

In connection with and prior to the Utica sale transactions described above, the Company elected to exercise its option to increase itsparticipating interest from 10% to 50% in the same oil and gasproperties on a “netproceedsbasis” so that the Company received netproceeds withrespect to 50% oftheproperties subject to the sale ratherthan the 10% forwhich itheldrecord title. For additional information see “Note 1 1. Related Party T ransactions.”
Marcellus Shale Joint V

enture In connection with the formation ofACP II Marcellus LLC (“ACP II”), the Company’s partner in one ofits twojoint 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 ofcash distributions to af filiates ofA

vista Capital Partners, LP (together with its af filiates, “A

vista”), 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 A

vista’s investment in ACP II. During the second quarter of201 1, ACP II declared and paid cash distributions to A vista that exceeded A

vista’s internal rates-of-return and return-on-investment thresholds. Therefore, the Company received cash distributions of approximately $3.3 million in the second quarter of 201 1on its B Units, which were recognized as reductions of proved oil and gas properties.
In June 201 1, in accordance with the title and post-closing adjustment provisions of the sale and purchase agreements of the September 2010 sale by the Company ofcertain oil and gas properties to Reliance Marcellus II, LLC (“Reliance”), the Company provided additional interests in oil and gas properties in parts ofPennsylvania in the Marcellus Shale to Reliance in substitution ofproperties included in the sale that were af fected 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 of20% of its interest. Eagle Ford Joint V

enture On September 28, 201 1, 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 ofGAIL (India) Limited, ef fective September 1, 201 1. Under the purchase and participation agreement for this transaction, the Company received $63.7 million in cash which was recognized as a reduction ofproved oil and gas properties. As part ofthe 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, which
was fully utilized in 2012

. The agreement provides for an ongoingjoint venture between the Company and GAIL with respect to the interests purchased by GAIL. The Company serves as operator for the joint venture properties. The joint venture agreement also provides for an area ofmutual 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 ofmutual interest at a specified premium to the price paid by the Company

. Niobrara Joint V

entures OIL India (USA) Inc. and IOCL (USA) Inc. In October 2012, the Company completed the sale of 30% of substantially all of its interests in oil and gas properties in the Niobrara Formation to OIL India (USA) Inc. and IOCL (USA) Inc., subsidiaries of OIL India Ltd. and Indian Oil Corporation Ltd.,respectively , ef fective October 1, 2012. For convenience, intheseNotesto Consolidated Financial Statements the term “OIL JV Partners” is used to refer collectively to OIL India (USA) Inc. and IOCL (USA) Inc. Under the purchase and participation agreement for this transaction, the Company received approximately $41.25 million in cash and the OIL JV Partners have committed to pay a “development carry” of 50% ofcertain ofthe Company’s future development costs up to an aggregate of approximately $41.25 million, as further described below

. The proceeds from such sale was recognized as a reduction ofproved oil and gas properties.
The agreement also provides for an ongoing joint venture between the Company and the OIL JV Partners with respect to the interests purchased. The development carry obligation extends until the full utilization of the approximately $41.25 million development carry
. The Company operates the joint venture properties, and currently expects the development carry to be fully utilized by early 2014. The Niobrara Formation assets conveyed to the OIL JV Partners under the terms of the agreement are located primarily in W

eld and Adams counties, Colorado.
Haimo Oil & Gas LLC. In December 2012, the Company completed the sale ofa portion ofits remaining interest in the same oil and gas properties sold to the OIL JV Partners in the transaction described above to Haimo Oil & Gas LLC (“Haimo”), a subsidiary of Lanzhou Haimo T

echnologies Co. Ltd., ef

fective October 1, 2012, for a cash payment of $27.5 million

. The proceeds from such sale were recognized as a reduction of proved oil and gas properties. The purchase and participation agreement for this transaction provides for an ongoing joint venture between the Company and Haimo, with respect to the interests purchased. The Company will operate the joint venture properties. Following the closing of the Haimo transaction late in the fourth quarter of 2012, the Company

, the OIL JV Partners , and Haimo own 60%, 30% and 10% ofthejoint venture acreage, respectively

.F-18

6. Income T

axes The components of income tax expense from continuing operations were as follows:

Year Ended December 31, 2012 2011 2010

(In thousands) Current income tax expense U.S. Federal $ (411) $ (404) $

— State (403) (661) (4,236) Total current income tax expense (814) (1,065) (4,236) Deferred income tax (expense) benefit U.S. Federal (28,723) (23,254) (5,893) State (1,419) (1,292) 3,444 T otal deferred income tax expense (30,142) (24,546) (2,449) T otal income tax expense from continuing operations $ (30,956) $ (25,611) $ (6,685)

The Company’s income tax expense from continuing operations dif fers from the income tax expense computed by applying the U.S. federal statutory corporate income tax rate of 35% to income from continuing operations before income taxes as follows: Year Ended December 31, 2012 2011 2010

(In thousands) Income from continuing operations before income taxes $ 82,133 $ 58,145 $ 18,410 Income tax expense at the statutory rate (28,747) (20,350) (6,444) State income taxes, net of U.S. federal income tax benefit (1,681) (1,722) (792) Adjustment to prior period state income taxes, net of U.S. federal income tax benefit

— (4,735)

— Previously unbenefitted capital loss associated with investment 1,171 Nondeductible expenses (93) 25 (46) Other (435)

— 597 T otal income tax expense from continuing operations $ (30,956) $ (25,611) $ (6,685)F-19

Deferred income taxes reflect the impact of temporary dif ferences between the amount of assets and liabilities recognized for financial reporting purposes and such amounts recognized for tax purposes. At December 31, 2012 and 201 1 , deferred tax assets and liabilities are comprised ofthe following: December 31, 2012 2011 (In thousands) Deferred income tax assets Net operating loss carryforward - Federal and State $ 53,648 $ 42,442 Property and equipment 20,425 55,307 Stock-based compensation 4,245 4,469 Allowance for doubtful accounts 476 806 Fair value of derivative instruments

— 75 V aluation allowance (1,188) (681) Other 1,755 1,335 79,361 103,753 Deferred income tax liabilities Unamortized discount on 4.375% Convertible Senior Notes (382) (1,329) Capitalized interest (55,410) (45,469) Fair value of derivative instruments (10,222) (13,123) (66,014) (59,921) Net deferred income tax asset $ 13,347 $ 43,832

Deferred income tax assets and liabilities are classified as current or long term consistent with the classification of the related temporary dif

ference. At December 31, 2012 and 201 1 , the net deferred income tax asset is classified as follows: December 31, 2012 2011 (In thousands) Noncurrent deferred income tax asset $ 21,272 $ 53,517 Current deferred income tax liability (7,925) (9,685) Net deferred income tax asset $ 13,347 $ 43,832

As ofDecember 31, 2012, the Company had U.S. income tax loss carryforwards ofapproximately $176.9 million

. The U.S. loss carryforwards expire between 2019 and 2032 ifnot utilized in earlier periods. The realization ofthe deferred tax assets related to the U.S. loss carryforwards is dependent on the Company’s ability to generate suf ficient future taxable income in the U.S. within the applicable carryforward periods. As ofDecember 31, 201 1, the Company determined it was more likely than not that some of its state loss carryforwards would not be realized and accordingly , established a valuation allowance for which this totaled $1.2 million at December 31, 2012. The Company believes it will be able to generate suf ficient 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 except for those state loss carryforwards for which valuation allowance has been established.
The ability ofthe Company to utilize its U.S. loss 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 ofcertain ownership changes, including the purchase or sale ofstock by 5% shareholders and the of fering ofstock by the Company during any three-year period resulting in an aggregate change ofmore 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 the Company’s taxable income that can be of fset by these carryforwards. The limitation is generally equal to the product of (a) the fair market value ofthe equity ofthe 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, 2012, the Company believes an ownership change occurred in February 2005, which imposed
an annual limitation of$12.6 million ofthe Company’s taxable income that can be of fsetby thepre-change carryforwards. Because the Company’s aggregatepre-change loss carryforward is $9.8million,the Company doesnotbelieve ithas a Section 382 limitation
on the ability to utilize its U.S. loss carryforwards as of December 31, 2012. Future equity transactions involving the Company
or 5% shareholders ofthe 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 ofthe U.S. loss carryforwards.F-20

The Company receives a tax deduction during the period stock options are exercised, generally for the excess ofthe 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 ofU.S. loss carryforwards, the benefit ofthese tax deductions has not been reflected in the U.S. loss carryforward deferred tax asset. Stock-based compensation deductions included in the U.S. loss carryforwards of$176.9 million but not reflected in deferred tax assets were $29.2 million at December 31, 2012. The Companyplanstorecognizethe $10.2million deferredtaxassetassociatedwiththese stock-basedcompensationtaxdeductions when all other components ofthe U.S. loss carryforward deferred tax asset have been fully utilized. If and when the stock-based compensation deduction related U.S. loss 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, 2012, the Company had no material uncertain tax positions and the tax years since 1999 remain open to review by federal and various state taxjurisdictions.
7. Long-T

erm Debt At December 31, 2012 and 201 1 , long-term debt consisted ofthe following: December 31, 2012 2011 (In thousands) 8.625% Senior Notes $ 600,000 $ 600,000 Unamortized discount for 8.625% Senior Notes (4,849) (5,465) 7.50% Senior Notes 300,000

— 4.375% Convertible Senior Notes 73,750 73,750 Unamortized discount for 4.375% Convertible Senior Notes (1,093) (3,799) Senior Secured Revolving Credit Facility

— 47,000 $ 967,808 $ 711,486

8.625% Senior Notes and 7.50% Senior Notes On November 2, 2010, the Company issued $400.0 million aggregate principal amount of 8.625% Senior Notes due 2018 in a privateplacement. OnNovember 17,201 1,the Company issued an additional $200.0million aggregateprincipal amount of8.625% Senior Notes in a private placement. These notes were issued as “additional notes” under the indenture governing the 8.625% Senior Notes pursuant to which the Company had previously issued $400.0 million aggregate principal amount of 8.625% Senior Notes in November 2010, and under the indenture are treated as a single series with substantially identical terms as the 8.625% Senior Notes previously issued in November 2010. In June 201 1 and February 2012, the Company completed the exchange of registered 8.625% Senior Notes for any and all of its then unregistered $400.0 million and $200.0 million aggregate principal amount of 8.625% Senior Notes, respectively

. Except in certain circumstances described below , the Company may not redeem the 8.625% Senior Notes prior to October 15, 2014. On and after October 15, 2014, the Company may redeem all or a part of the 8.625% Senior Notes, at redemption prices decreasing from 104.313% ofthe principal amount to 100% ofthe principal amount on October 15, 2017, plus accrued and unpaid interest. In connection with certain equity of ferings by the Company

, the Company may at any time prior to October 15, 2013, subject to certain conditions, on one or more occasions, redeem up to 35% ofthe aggregate principal amount ofthe 8.625% Senior Notes at a redemption price of 108.625% ofthe principal amount, plus accrued and unpaid interest, ifany , to the redemption date using the net cash proceeds ofsuch equity of ferings. Prior to October 15, 2014, the Company may redeem all or part ofthe 8.625% Senior Notes at 100% of the principal amount thereof, plus accrued and unpaid interest and a make whole premium (as defined in the indenture governing the 8.625% Senior Notes). If a Change of Control (as defined in the indenture governing the 8.625% Senior Notes) occurs, the Company may be required by holders to repurchase the 8.625% Senior Notes for cash at a price equal to 101% ofthe aggregate principal amount, plus any accrued but unpaid interest.
On September 10, 2012, the Company issued in a public of fering $300.0 million aggregate principal amount of 7.50% Senior Notes due 2020. Except in certain circumstances described below , the Company may not redeem the 7.50% Senior Notes prior to September 15, 2016. On and after September 15, 2016, the Company may redeem all or a part of the 7.50% Senior Notes, at redemption prices decreasing from 103.750% of the principal amount to 100% of the principal amount on September 15, 2018, plus accrued and unpaid interest. In connection with certain equity of ferings by the Company

, the Company may at any time prior to September 15, 2015, subject to certain conditions, on one or more occasions, redeem up to 35% of the aggregate principal amount ofthe 7.50% Senior Notes at a redemption price of 107.500% ofthe principal amount, plus accrued and unpaid interest, if any , to the redemption date using the net cash proceeds of such equity of ferings. Prior to September 15, 2016, the CompanyF-21

may redeem all or part ofthe 7.50% Senior Notes at 100% ofthe principal amount thereof, plus accrued and unpaid interest and
a make whole premium (as defined in the indenture governing the 7.50% Senior Notes). Ifa Change ofControl (as defined in the indenture governing the 7.50% Senior Notes) occurs, the Company may be required by holders to repurchase the 7.50% Senior Notes for cash at a price equal to 101% ofthe aggregate principal amount, plus any accrued but unpaid interest.
The indentures governing the 8.625% Senior Notes and the 7.50% Senior Notes contain 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 ofthe 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 af filiates; and createunrestricted subsidiaries.At December 31, 2012, the 8.625% Senior Notes and the 7.50% Senior Notes were guaranteed by all ofthe Company’s existing subsidiaries (other than Carrizo UK Huntington Ltd, Monument Exploration LLC, and Carrizo UK Bardolph Ltd).
Convertible Senior Notes In May 2008, the Company issued $373.8 million aggregate principal amount of4.375% Convertible Senior Notes due 2028. The notes are convertible, using a net share settlement process, into a combination of cash and Company common stock that entitles holders ofthe convertible senior notes to receive cash up to the principal amount ($1,000 per note) and common stock in respect ofthe remainder, if any

, ofthe Company’s conversion obligation in excess of such principal amount.
In November 2010, the Company completed a tender of fer for $300.0 million aggregate principal amount outstanding of its convertible senior notes. Each holder received $1,000 for each $1,000 principal amount ofconvertible senior notes purchased in the tender of

fer, plus accrued and unpaid interest. The Company recognized a $31.0 million pre-tax loss on extinguishment of debt as aresult ofthepurchase ofthe convertible seniornotes inthetenderof fer, substantially all ofwhichwasnon-cashrepresenting the associated unamortized discount and deferred financing costs. After the Company’s purchase of $300.0 million aggregate principal amount ofconvertible senior notes, $73.8 million aggregateprincipal amount ofconvertible senior notes was outstanding
as ofDecember 31, 2012 and 201 1

. The convertible seniornotes are subjectto customarynon-financial covenants and events ofdefault, 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 ofthe Company and rank equal to the Company’s senior notes and all future senior unsecured debt of the Company but rank second in priority to the senior secured revolving credit facility

. 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, ifcertain 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 14.7406per $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 ifthe last reported sale price ofthe Company’s common stock exceeds 130% ofthe conversion price for at least 20 trading days in a period of 30 consecutive trading days ending on the last trading day ofthe 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 ofthe 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 ofbusiness on the business day preceding the redemption date ifthe notes are called for redemption or (e) on or after March 31, 2028 and prior to the close ofbusiness on the business day prior to the maturity date ofJune 1, 2028.
The holders ofthe 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% 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% ofthe principal amount ofthe notes to be redeemed plus accrued and unpaid interest, if any
. TheCompanyvaluedtheconvertible seniornotesatMay 21,2008,as $309.6millionofdebtand $64.2millionofequityrepresenting the fair value ofthe 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 ef fective 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 of fer discussed above was recognized as a component oftheF-22

loss on the extinguishment of debt in 2010. Amortization of the debt discount amounted to $2.7 million, $2.6 million and $1 1.6 million for the years ended December 31, 2012, 201 1 and 2010, respectively

. While the holders of the convertible senior notes may require the Company to repurchase the convertible senior notes in June 2013, the Company has the intent and ability to refinance the convertible senior notes on a long-term basis with the available capacity ofits senior secured revolving credit facility , and accordingly

, the convertible senior notes have been classified as longterm debt in the consolidated balance sheets as ofDecember 31, 2012.
Senior Secured Revolving Credit Facility The Company ispartyto a senior securedrevolving credit facilitywithW ellsFargoBank,NationalAssociation asthe administrative agent. The revolving credit facility provides for a borrowing capacity 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. The revolving credit facility is secured by substantially all ofthe Company’s U.S. assets and is guaranteed by the same subsidiaries that guarantee the Company’s 8.625% Senior Notes, 7.50% Senior Notes and convertible senior notes. The current borrowing base is $365.0 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 on or about May 1, 2013. 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

. The annual interest rate on each base rate borrowing is (a) the greatest of the Agent’s Prime Rate, the Federal Funds Ef fective 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 ofborrowing 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 ofborrowing base usage).
On March 26, 2012, the revolving credit facility was amended to, among other things, (1) extend by two quarters the dates on which the maximum ratio ofT otal Debt to EBITDA(each as defined in the credit agreement governing the revolving credit facility) steps down and (2) increase the basket available for redemptions of the Company’s convertible senior notes. On September 4, 2012 the revolving credit facility was further amended to increase the basket available for issuances of additional senior notes, including those issued in the September 2012 notes of fering. On September 27, 2012, the revolving credit facility was again amended to, among other things, extend the maximum permitted duration ofhedge agreements entered into by the Company and its restricted subsidiaries and to reflect the Fall 2012 borrowing base redetermination.
The Company is subject to certain covenants under the terms ofthe revolving credit facility which include the maintenance ofthe following financial covenants: (1) a ratio ofT otal Debt to EBITDA ofnot more than (a) 4.25 to 1.00 for the fiscal quarter ending December 31, 2012 and (b) 4.00 to 1.00 for fiscal quarters ending March 31, 2013 and thereafter; (2) a Current Ratio ofnot less than 1.00 to 1.00; (3) a ratio of Senior Debt to EBITDA of not more than 2.50 to 1.00; and (4) a ratio of EBITDA to Interest Expense ofnot less than 2.50 to 1.00 (each ofthe capitalized terms used in the foregoing clauses (1) through (4) being as defined in the credit agreement governing the revolving credit facility). At December 31, 2012, the ratio of T otal Debt to EBITDA was 2.97 to 1.00, the Current Ratio was 2.23 to 1.00, the ratio of Senior Debt to EBITDA was 0.00 to 1.00 and the ratio of EBITDA to Interest Expense was 5.19 to 1.00. T otal Debt and Senior Debt, as defined in the credit agreement governing the revolving credit facility , are net ofcash and cash equivalents ofthe Company

. Because the calculation ofthe financial ratios are made as ofa 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 ofcash flows related to operations, capital expenditures, sales ofoil and gas properties and securities of ferings.
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 ofthe Company’s common stock, redemptions ofseniornotes,investments, acquisitions,mergers, asset dispositions,transactionswith af filiates,hedgingtransactions 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). Ifan event ofdefault 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, 2012, the Company had no borrowings outstanding under the revolving credit facility

. At December 31, 2012, the Company also had $0.9 million in letters ofcredit 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 ofthe Company’sF-23

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 of ferings. The revolving credit facility may also be used to repurchase the convertible senior notes. 8. Asset Retirement Obligations The following table sets forth asset retirement obligations for the years ended December 31, 2012and 201 1 :
Y ear Ended December

31, 2012 2011 (In thousands) Asset retirement obligations at beginning ofperiod $ 8,324 $ 5,250 Liabilities incurred 1,573 757 Liabilities settled (1,666) (162) Reduction due to property sales (3,272) (368) Accretion expense 372 235 Revisions ofprevious estimates 828 2,612 Asset retirement obligations at end ofperiod 6,159 8,324 Asset retirement obligations due within one year included in "Other accrued liabilities" (1,670) (925) Long-term asset retirement obligations $ 4,489 $ 7,399
9. Commitments and Contingencies From time to time, the Company is party to certain legal actions and claims arising in the ordinary course ofbusiness. While the outcome ofthese events cannot be predicted with certainty , management does not expect these matters to have a materially adverse ef fect on the financial position or results of operations ofthe Company

. The results of operations and financial position ofthe Company continue to be af fected 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 ef fect 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, 2012, 201 1 and 2010 was $1.8 million, $1.7 million, and $1.0 million, respectively , and includes rent expense primarily for the Company’s corporate of fice and field of fices.
At December 31, 2012, total minimum commitments from long-term, non-cancelable operating leases, drilling rig, seismic and pipeline volume commitments are as follows:

Amount (In thousands) 2013 $ 81,548 2014 48,827 2015 27,215 2016 12,170 2017 5,411 2018 and thereafter 15,512 $ 190,683F-24

10. Shareholders’ Equity and Stock Incentive Plans Shareholders’Equity Common Stock

. In December 2010, the Company sold 3.975 million shares ofits common stock in an underwritten public of fering at a price to the underwriter of $28.90 per share. The Company used the net proceeds of approximately $1 14.9 million to repay a portion ofthe 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 of fering 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

. W arrants

. On November 24, 2009, the Company entered into a land agreement with an unrelated third party and its af filiate. The land agreement expiredpursuant to its terms on May 31, 201 1

.Underthe land agreement, the Company issuedwarrants topurchase 31,983, 28,576 and 57,641 shares of common stock in 2012, 201 1 and 2010, respectively

. The final issuance ofwarrants under the land agreement was granted in April 2012

. The warrants have an expiration date ofAugust 21, 2017, an exercise price of $22.09, which may be exercised on a “cashless” basis, and are subject to antidilution adjustments.
Stock Incentive Plans The Company has established the Incentive Plan ofCarrizo Oil & Gas, Inc., as amended (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 , restricted stock awards and restricted stock units to directors, employees and independent contractors. The Company may grant awards ofup to 7,245,000 shares (subject to certain limitations on restricted stock and restricted stock units) under the Incentive Plan and through December 31, 2012, has issued stock options, restricted stock awards and restricted stock units covering 5,070,325 shares, net of forfeitures and excluding SARs the Company has elected to settle in cash.
Stock Options and Stock SARs. The table below summarizes the activity for stock options and SARs the Company has elected to settle in common stock for the three years ended December 31, 2012, 201 1 and 2010:

Shares W

eightedA verage Exercise Prices W

eightedA verage Remaining Life (In years) Aggregate

Intrinsic V

alue (In millions) For the Y

ear Ended December31, 2010 Outstanding, beginning ofperiod 895,463 $ 8.43 Granted

— — Exercised (266,433) 2.59 Forfeited (2,493) 18.56 Other (211,683) 20.22 Outstanding, end ofperiod 414,854 $ 6.10 Exercisable, end ofperiod 414,854 $ 6.10 For the Y

ear Ended December31, 2011 Outstanding, beginning ofperiod 414,854 $ 6.10 Granted

— — Exercised (151,500) 4.36 Forfeited

— — Outstanding, end ofperiod 263,354 $ 7.11 Exercisable, end ofperiod 263,354 $ 7.11 For the Y ear Ended December

31, 2012 Outstanding, beginning ofperiod 263,354 $ 7.11 Granted

— — Exercised (20,500) 5.50 Forfeited

— — Outstanding, end ofperiod 242,854 $ 7.24 0.87 $ 3.21 Exercisable, end ofperiod 242,854 $ 7.24 0.87 $ 3.21F-25

No stock options or SARs were granted under the Incentive Plan during 2010, 201 1 or 2012

. All SARs issued by the Company contain performance and service conditions. The performance conditions have been met for all awards.
At December 31, 2012, the liability for SARs issued under the Incentive Plan that the Company has elected to be settled in cash
was $2.3 million, all of which are vested and are classified as other accrued liabilities. As these awards are fully vested and accounted for as liability awards, the liability is remeasured in earnings at each reporting period fair value until the awards are settled.
At December 31, 2012, all stock options were vested and accordingly , the Company had no unrecognized compensation costs related to outstanding stock options. The total intrinsic value (market price at date of exercise less the exercise price) of stock options exercised during the years ended December 31, 2012, 201 1 and 2010 was $0.4 million, $3.6 million, and $6.0 million, respectively

, and the Company received $0.1 million, $47,000, and $0.7 million in cash in connection with stock option exercises for the years ended December 31, 2012, 201 1 and 2010, respectively

. RestrictedStockAwar

ds 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, 2012, 201 1 and 2010:
Shares/ Units Grant-date

Fair V alue Unvested restricted stock awards and units at January 1, 2010 471,243 $ 25.01 Granted 640,207 18.60 V ested (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 V ested (452,585) 25.29 Forfeited (25,773) 23.30 Unvested restricted stock awards and units at December 31, 201 1 800,498 27.96 Granted 854,292 25.25 V ested (488,992) 25.63 Forfeited (19,524) 27.61 Unvested restricted stock awards and units at December 31, 2012 1,146,274 $ 26.95

As ofDecember 31, 2012,unrecognized compensation costsrelatedtounvestedrestricted stock awards andunitswas $18.6million and will be recognized as stock-based compensation expense over a weighted-average period oftwo years. The 2010, 201 1 and 2012 grants ofcertain restricted stock units contained performance and service conditions. The performance conditions have been met for all awards.F-26

Cash-Settled StockAppreciation Rights Plan The Company has also established the Carrizo Oil & Gas, Inc. Cash-Settled StockAppreciation Rights Plan (“Cash SARs Plan”). The Cash SARs Plan enables employees and independent contractors to share in the appreciation ofCarrizo’s common stock, but does not require the issuance of shares. During 2012 and 201 1 , the Company issued 193,336 and 153,801 SARs under the Cash SARs Plan, respectively

.At December 31, 2012 and 201 1 , the liability for such SARs was $4.9 million and $6.5 million, ofwhich, $4.2 million and $5.2 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 $0.7 million and $1.3 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 SARs issued under the Cash SARs Plan at December 31, 2012 and 201 1 , respectively:
2012 2011 Grant date fair value $ 12.23 $ 18.50 V olatility factor 48.2% 61.6% Dividend yield

— — Risk-free interest rate 0.4% 0.4% Expected term (in years) 3.0 2.9

As ofDecember 31, 2012, unrecognized compensation costs related to unvested SARs issued under the Cash SARs Plan was $0.9 million and will be recognized as stock-based compensation expense over a weighted-average period of 1.9 years. The 2012 grants of SARs under the Cash SARs Plan contained performance and service conditions. The performance conditions have been met for all awards.
11. Related Party T

ransactions T ransactions withAvista and af filiates Utica Shale Joint V

entur e. In September 201 1, the Company entered into a joint venture with af filiates ofA

vista to acquire and develop acreage in the liquids rich region ofthe Utica Shale. The Company serves as operator ofthejoint venture properties under joint operating agreements with ACP II and ACP III. The Company has also agreed to a management services agreement under which it will perform specified management services for ACP III on the same cost and reimbursement bases provided for in the joint operating agreements. A vista or its designee has the right to become a co-operator ofthejoint venture properties if(i) A vista sells substantially all of its interests in the A vista Utica joint venture or (ii) the Company defaults under the terms of any pledge ofits interest in theproperties. In addition to the Company's share in theproduction and saleproceeds fromjoint ventureproperties, the Company also acquired B Units in ACP III at the formation ofthe A vista Uticajoint venture.
In the fourth quarter of 2012, the Company sold substantially all of its interests in oil and gas properties dedicated to its Utica joint venture in the northern portion of the Utica Shale play to an unrelated third party

. Simultaneously with the closing of this transaction, ACP II sold substantially all of its interests in the same oil and gas properties.
In connection with these sale transactions, the Company elected to exercise its first option granted by A vista to increase its participating interest in the same oil and gas properties on a “net proceeds basis” so that the Company received net proceeds with respect to 50% ofthe properties subject to the sale rather than the 10% for which it held record title. Pursuant to thejoint venture agreements, as amended, the Company paid $24.0 million for the 40% additional interest in the acreage subject to the sale and certain other A

vista Utica joint venture properties. Subsequently , on October 24, 2012, the Company and A vista amended their Utica Shale joint venture agreements to provide that the expiration date of the Company’s remaining option to increase its participating interest in the A vista Utica joint venture properties was accelerated from March 2013 to January 15, 2013. The Company exercised this option on January 15, 2013 by paying $63.1 million for an additional 40% in the remaining A vista Utica joint venture properties. The Company and A vista also agreed that after the option was exercised, the Company’s participating interest in subsequently acquired properties within an area of mutual interest continued to be 10%, and A vista’s participating interest is 90%, and the Company was granted an additional option to increase its 10% ownership in such subsequently acquired properties to 50% at 8.625% above A vista’s acreage cost and associated improvements (compounded monthly following A vista’s contribution ofpurchase proceeds). This additional option will expire May 31, 2013.Additionally , the Company andA

vista agreed to increase the cap onACP III’s contribution right to an aggregate of$170.0 million from an initial $130.0 million

. The Company's right to receive distributions associated with the properties owned by ACP II in the A vista Uticajoint venture through its B Units in ACP II was terminated upon the consummation ofthe Company’s exercise of its option with respect to 50% ofthe properties subject to the sale described above. The Company's right to receive distributions associated with the properties owned by ACP III through its B Units in ACP III terminated upon the consummation of the Company’s January 15, 2013 option to increase its interest in the A

vista Utica joint venture properties.F-27

StevenA. W

ebster, Chairman ofthe Company’s Board ofDirectors, serves as Co-Managing Partner and President ofA vista Capital Holdings, LP

, which has the ability to controlA vista and its af

filiates.ACP II’s and III’s Boards ofManagers have the sole authority for determining whether, when and to what extent any cash distributions will be declared and paid to members ofACP II or ACP III, respectively

. Mr

. W

ebster is not a member of either entity’s Board ofManagers.
Mar cellus Shale Joint V

entur es. Ef fective August 1, 2008, Carrizo (Marcellus) LLC, a wholly owned subsidiary ofthe Company , entered into ajoint venture arrangement with ACP II, an af filiate ofA

vista. 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 A vista joint venture to Reliance. 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 ofapproximately $327.0 million

. At the time ofentering into the agreements for these transactions, the Company and A vista agreed that B Unit distributions to the Company with respect to A vista’s sale ofproperties to Reliance would be principally based upon A vista’s internal rates-of-return and return-on-investment thresholds associated with such properties, subject to amounts withheld from distribution by ACP II’s board. In connection with these sales transactions, the Company and A

vista amended the participation agreement and other joint venture agreements with A vista to provide that the properties that the Company andA vista sold to Reliance, as well as the properties the Company committed to the newjoint venture with Reliance, are not subject to the terms ofthe A vista Marcellusjoint venture, and that the A vista Marcellusjoint venture’s area of mutual interest will generally not include Pennsylvania, the state in which those properties are located. The Company’s joint venture withA

vista continues and now covers approximately 71,774 net acres, primarily in W est V irginia and New Y

ork. Pursuant to the terms ofthe A

vista area ofmutual interest, ef fective December 31, 2010, the initial area ofmutual interest was reduced to specified halos in which the A vista Marcellusjoint venture was active.
In December 2010, the Company entered into a settlement agreement with Reliance providing for the resolution ofdefects in title that Reliance alleged with respect to the properties it acquired from the Company andA vista in September 2010. In the agreement, the Company agreed to undertake specified curative measures with respect to the properties it and A vista sold to Reliance, and to indemnify Reliance on its own behalf and on behalf ofA vista 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 A vista by which A

vista agreed to indemnify the Company for amounts paid on A vista’s behalfby the Company under the settlement agreement, if any
. On November 16, 2010, Carrizo Marcellus assigned, via distribution and subsequent contribution, its interests in the A vista Marcellus joint venture 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 relatedjoint operating agreement, pursuant to which operatorship ofthe A vista Marcellusjoint venture was assumedby CarrizoWV

.In addition, CarrizoWVandtheotherpartiesthereto amendedandrestatedtheparticipation agreement onNovember 16,2010,ef fectiveasofOctober 1,2010.Thisamendedandrestatedparticipationagreementamendstheparticipation 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 ofthe properties covered by theA vista Marcellusjoint venture under ajoint operating agreement withA vista and also performs specified management services forACP II.An operating committee composed ofone representative of each party provides overall supervision and direction ofjoint operations. A vista or its designee has the right to become a cooperator of the properties if all of its membership interests or substantially all of its assets are sold to an unaf filiated third party or ifthe Company defaults under the terms of any pledge of its interest in the properties.
The Company has agreed to jointly market A vista’s share ofthe production from the properties with its own until the cash flows and sale proceeds are allocated in accordance with the parties’ participating interests under thejoint operating agreement. Each party now has ability to transfer its interest in the A vista Marcellusjoint 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.
StevenA. W

ebster, Chairman ofthe Company’s Board ofDirectors, serves as Co-Managing Partner and President ofA vista Capital Holdings, LP

, which has the ability to controlA vista.ACP II’s Board ofManagers have the sole authority for determining whether, when and to what extent any cash distributions will be declared and paid to members ofACP II. Mr

. W ebster is not a member of ACP II’s Board ofManagers. As disclosed elsewhere, the Company has been and is a party to prior arrangements with af filiates ofA vista Capital Holdings, LP in respect ofthe Company’sjoint venture with af filiates ofA

vista in the Utica Shale.
ACP II Distribution. During the third and fourth quarters of 2010 the Company received cash distributions aggregating approximately $38.8 million and during the second quarter of 201 1 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. As described in “Utica Shale JointF-28

V enture” above, the Company’s right to receive distributions associated with the properties owned by ACP II in the A vista Utica joint venture through its B Units in ACP II was terminated upon the consummation ofthe Company’s exercise of its option with respect to certain A

vista Utica joint venture properties in October 2012.
Advances to andfr

om Avista andAffiliates

. At December 31, 2012, related party receivables on the consolidated balance sheets included $9.8 million, representing the net amounts A vista owes the company related to activity within the Utica and Marcellus Shalejointventures.At December 31, 201 1 , advances forjoint operations on the consolidatedbalance sheets included $9.5million, representing the net amount A vista had advanced the Company related to activity within the Utica and Marcellus Shale joint ventures. 12. Derivative Instruments The Company uses various types ofderivative 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 andbasis dif ferential swaps.Underthese derivative instruments,payments arereceived
or made based on the dif

ferential 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 60 months. The derivative instruments are carried at fair value in theconsolidatedbalance sheets,withchangesinfairvaluerecognizedasgain(loss)onderivativeinstruments,netintheconsolidated statements of income for the period in which the changes occur
. The fair value of derivative instruments at December 31, 2012 and 201 1 was a net asset of $29.2 million and $37.5 million, respectively

. The following sets forth a summary ofthe distribution ofthe net fair value ofthe Company’s derivative instruments by counterparty: Counterparty December 31, 2012 December 31, 2011

Credit Suisse 40% 68% BNP Paribas 33% 19% Societe Generale 22% 2% BBVA Compass 3%

—% Wells Fargo 2%

—% Shell Energy North America (US) LP

—% 6% Credit Agricole

—% 5% Total 100% 100%

Master netting agreements are in place with each ofthese 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 ofnonperformance 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, Credit Agricole, BBV A Compass, W

ells Fargo and Societe Generale are lenders in the Company’s revolving credit facility , the Company is not required to post collateral with respect to derivative instruments in a net liability position with these counterparties as the contracts are secured by the revolving credit facility

. The following sets forth a summaryofthe Company’snaturalgasderivativepositions at averageNYMEXprices as ofDecember 31, 2012

.

Period V olume (in MMBtu) W eighted A verage Floor Price ($/MMBtu) W eighted A verage Ceiling Price ($/MMBtu) 2013 18,250,000 $ 4.63 $ 4.63 2014 3,650,000 $

— $ 5.50F-29

The following sets forth a summary ofthe Company’s crude oil derivative positions at averageNYMEX prices as ofDecember 31, 2012

.

Period V olume (in Bbls) W eighted A verage Floor Price ($/Bbls) W eighted A verage Ceiling Price ($/Bbls) 2013 2,774,000 $ 88.91 $ 102.43 2014 2,555,000 $ 90.06 $ 98.51 2015 1,441,750 $ 89.54 $ 96.49 2016 244,000 $ 85.00 $ 104.00

In connection with the crude oil derivative instruments above, the Company has entered into protective put spreads. For 2014, at marketpricesbelow the shortputprice of$65.00, the floorpricebecomes the marketpriceplus theput spread of$20.00 on 182,500 ofthe 2,555,000 Bbls and the remaining 2,372,500 Bbls would have a floor price of $90.06

.

Period V olumes (in Bbls) W eighted A verage Short Put Price ($/Bbl) W eighted A verage Put Spread ($/Bbl) 2014 182,500 $ 65.00 $ 20.00 2015 365,000 $ 65.00 $ 20.00 2016 244,000 $ 65.00 $ 20.00

For the years ended December 31, 2012, 201 1 and 2010, the Company recorded the following related to its oil and gas derivative instruments:
Year Ended December 31, 2012 2011 2010

(In thousands) Realized gain (loss) on derivative instruments, net $ 41,122 $ 35,452 $ 33,218 Unrealized gain (loss) on derivative instruments, net (9,751) 12,971 14,564 Gain (loss) on derivative instruments, net $ 31,371 $ 48,423 $ 47,782
13. Fair V

alue Measurements Accountingguidelines formeasuring fairvalue establish athree-levelvaluationhierarchy fordisclosure offairvaluemeasurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one ofthree dif ferent levels depending on the observability ofthe 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 ofthe 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.F-30

Assets and Liabilities Measured at Fair V alue on a Recurring Basis The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as ofDecember 31, 2012 and 201 1 , and indicate the fair value hierarchy ofthe valuation techniques utilized by the Company to determine such fair value: December 31, 2012 December 31, 2011 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total (In thousands) Assets: Derivative instruments $

— $ 36,452 $

— $ 36,452 $

— $ 61,063 $

— $ 61,063 Liabilities: Derivative instruments

— (7,291)

— (7,291)

— (23,569)

— (23,569)

Total $

— $ 29,161 $

— $ 29,161 $

— $ 37,494 $

— $ 37,494

The fairvalues ofthe Company’s derivative instruments arebased on apricing model thatuses market data obtained from reputable independent sources and are considered Level 2 inputs, including (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 also compared to the values provided by the counterparty for reasonableness and are adjusted for the counterparties’ credit quality for derivative assets and the Company’s credit quality for derivative liabilities. T o date, adjustments for credit quality have not had a material impact on the fair values.
The fair values reported in the consolidated balance sheets are as of a particular point in time and subsequently change as these estimates arerevised toreflect actualresults, changes inmarket conditions and other factors. The assets and liabilities for derivative instruments included in the tables above arepresented on a grossbasis. 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 ofLevels 1 or 2 for the years ended December 31, 2012 and 201 1

. Fair V alue ofOther Financial Instruments The Company’s other financial instruments consist ofcash and cash equivalents, receivables, payables and long-term debt which
are classified as Level 1 under the fair value hierarchy

. The carrying amounts of cash and cash equivalents, receivables, and payables approximate fair value due to the highly liquid or short-term nature ofthese instruments. The carrying amounts oflongterm debt under the Company’s revolving credit facility approximate fair value as these borrowings bear interest at variable rates ofinterest. The following table presents the carrying amounts and fair values ofthe Company’s senior notes and convertible senior notes, based on quoted market prices, as ofDecember 31, 2012 and 201 1

. December 31, 2012 December 31, 2011 Carrying Amount Fair Value Carrying Amount Fair Value (In thousands) 8.625% Senior Notes $ 595,151 $ 645,000 $ 594,535 $ 606,000 7.50% Senior Notes 300,000 308,250

— — 4.375% Convertible Senior Notes 72,657 73,842 69,951 73,013
14. Condensed Consolidating Financial Information In November 2010 and November 201 1, the Company and certain ofthe 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 ofthe Company’s 8.625% Senior Notes. Certain, but not all, ofthe Company’s wholly owned subsidiaries have issued full, unconditional andjoint and several guarantees ofthe 8.625% Senior Notes and may guarantee future issuances ofdebt securities. In June 201 1 and February 2012, the Company completed the exchange ofregistered 8.625% Senior Notes for any and all of its unregistered $400.0 million and $200.0 million aggregate principal amount of 8.625% Senior Notes, respectively

. In September 2012, the Company and certain ofthe Company’s wholly owned subsidiaries issued in a public of fering $300.0 million aggregate principal amount ofthe Company’s 7.50% Senior Notes.
The rules ofthe SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public of fering, where the guarantee is full, unconditional andjoint and several and where the voting interest ofthe subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidatingF-31

financial information as ofDecember 31, 2012 and December 31, 201 1 , and for each ofthe three years ended December 31, 2012, 201 1 and 2010 on a parent company , combined guarantor subsidiaries, combined non-guarantor subsidiaries, 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 ofoperations ofsubsidiaries arethereforereflected intheparent company’s investment accounts and earnings. Theprincipal elimination entries set forthbelow eliminate investments in subsidiaries and intercompanybalances and transactions. T ypically in a condensed consolidating financial statement, the net income and equity ofthe 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&Aare calculated and recorded on a countryby countrybasis. However, when calculated separately on a legal entity basis, the combined totals ofparent company and subsidiary impairments and DD&A can be more or less than the consolidated total as a result of dif ferences 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 dif ferences between consolidated and parent company and subsidiary company combined impairments and DD&A.F-32 CARRIZO OIL

& GAS, INC. CONDENSED CONSOLIDA TING BALANCE SHEETS

December 31, 2012

Parent Company Combined

Guarantor Subsidiaries Combined

NonGuarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets $ 1,689,430 $ 130,487 $

— $ (1,613,094) $ 206,823 Current assets held for sale

— — 1,882

— 1,882 Property and equipment, net 23,041 1,443,064

— 21,569 1,487,674 Investment in subsidiaries 14,588

— — (14,588)

— Long-term assets held for sale 24,488

— 108,138

— 132,626 Other assets 35,095 16,928 11,818 (8,850) 54,991 Total assets $ 1,786,642 $ 1,590,479 $ 121,838 $ (1,614,963) $ 1,883,996

LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities $ 179,221 $ 1,631,887 $

— $ (1,560,853) $ 250,255 Current liabilities associated with assets held for sale 9,880

— 38,783

— 48,663 Long-term liabilities 973,003 3,512

— — 976,515 Long-term liabilities associated with assets held for sale

— — 23,547

— 23,547 Shareholders’ equity 624,538 (44,920) 59,508 (54,110) 585,016 T otal liabilities and shareholders’ equity $ 1,786,642 $ 1,590,479 $ 121,838 $ (1,614,963) $ 1,883,996

December 31, 2011

Parent Company Combined

Guarantor Subsidiaries Combined

NonGuarantor Subsidiaries Eliminations Consolidated (In thousands) ASSETS Current assets $ 1,349,841 $ 71,018 $

— $ (1,304,336) $ 116,523 Current assets held for sale

— — 3,874

— 3,874 Property and equipment, net 100,329 1,131,672

— 8,916 1,240,917 Investment in subsidiaries (58,764)

— — 58,764

— Long-term assets held for sale 687

— 78,044

— 78,731 Other assets 38,852 54,062

— (5,279) 87,635 Total assets $ 1,430,945 $ 1,256,752 $ 81,918 $ (1,241,935) $ 1,527,680

LIABILITIES AND SHAREHOLDERS’ EQUITY Current liabilities $ 150,793 $ 1,368,456 $ 128 $ (1,252,295) $ 267,082 Current liabilities associated with assets held for sale

— — 4,238

— 4,238 Long-term liabilities 724,801 2,183

— (2,908) 724,076 Long-term liabilities associated with assets held for sale

— — 22,429

— 22,429 Shareholders’ equity 555,351 (113,887) 55,123 13,268 509,855 T otal liabilities and shareholders’ equity $ 1,430,945 $ 1,256,752 $ 81,918 $ (1,241,935) $ 1,527,680F-33 CARRIZO OIL

& GAS, INC. CONDENSED CONSOLIDA TING ST A TEMENTS OF

INCOME

For The Year Ended December 31, 2012

Parent Company Combined

Guarantor Subsidiaries Combined

NonGuarantor Subsidiaries Eliminations Consolidated (In thousands) Oil and gas revenues $ 20,195 $ 347,985 $

— $

— $ 368,180 Costs and expenses 76,839 205,341

— (12,653) 269,527 Operating income (loss) (56,644) 142,644

— 12,653 98,653 Other income (expense), net 20,022 (36,542)

— — (16,520) Income (loss) fromcontinuingoperationsbeforeincometaxes (36,622) 106,102

— 12,653 82,133 Income tax (expense) benefit 12,658 (37,136)

— (6,478) (30,956) Equity in income (loss) of subsidiaries 73,150

— — (73,150)

— Net income (loss) from continuing operations 49,186 68,966

— (66,975) 51,177 Net income from discontinued operations,net ofincometaxes 126

— 4,184

— 4,310 Net income (loss) $ 49,312 $ 68,966 $ 4,184 $ (66,975) $ 55,487

For The Year Ended December 31, 2011

Parent Company Combined

Guarantor Subsidiaries Combined

NonGuarantor Subsidiaries Eliminations Consolidated (In thousands) Oil and gas revenues $ 31,875 $ 170,292 $

— $

— $ 202,167 Costs and expenses 68,652 100,255

— (4,891) 164,016 Operating income (loss) (36,777) 70,037

— 4,891 38,151 Other income (expense), net 41,182 (21,188)

— — 19,994 Income from continuing operations before income taxes 4,405 48,849

— 4,891 58,145 Income tax (expense) benefit (1,209) (22,612)

— (1,790) (25,611) Equity in income (loss) of subsidiaries 29,319

— — (29,319)

— Net income (loss) from continuing operations 32,515 26,237

— (26,218) 32,534 Net income from discontinued operations,net ofincometaxes 1,013 3,082 4,095 Net income (loss) $ 33,528 $ 26,237 $ 3,082 $ (26,218) $ 36,629

For The Year Ended December 31, 2010

Parent Company Combined

Guarantor Subsidiaries Combined

NonGuarantor Subsidiaries Eliminations Consolidated (In thousands) Oil and gas revenues $ 33,203 $ 104,920 $

— $

— $ 138,123 Costs and expenses 62,375 55,815

— (4,024) 114,166 Operating income (loss) (29,172) 49,105

— 4,024 23,957 Other income (expense), net 4,974 (10,521)

— — (5,547) Income (loss) fromcontinuingoperationsbeforeincometaxes (24,198) 38,584

— 4,024 18,410 Income tax (expense) benefit 8,308 (13,542)

— (1,451) (6,685) Equity in income (loss) of subsidiaries 25,042

— — (25,042)

— Net income (loss) from continuing operations 9,152 25,042

— (22,469) 11,725 Net loss from discontinued operations, net of income taxes (1,775)

— — — (1,775) Net income (loss) $ 7,377 $ 25,042 $

— $ (22,469) $ 9,950F-34 CARRIZO OIL

& GAS, INC. CONDENSED CONSOLIDA TING ST A TEMENTS OF

CASH FLOWS

For The Year Ended December 31, 2012

Parent Company Combined

Guarantor Subsidiaries Combined

NonGuarantor Subsidiaries Eliminations Consolidated (In thousands) Net cash provided by operating activities - continuing operations $ 75,546 $ 177,525 $

— $

— $ 253,071 Net cash used in investing activities - continuing operations (280,564) (493,145)

— 308,558 (465,151) Net cash provided by financing activities - continuing operations 237,778 308,558

— (308,558) 237,778 Net increase (decrease) in cash and cash equivalents from continuing operations 32,760 (7,062)

— — 25,698 Net increase (decrease) in cash and cash equivalents from discontinued operations

— — (1,196)

— (1,196) Cash and cash equivalents, beginning of year - continuing operations 19,134 7,263

— — 26,397 Cash and cash equivalents, end of year - continuing operations $ 51,894 $ 201 $

— $

— $ 52,095 Cash and cash equivalents, beginning of year - discontinued operations

— — 1,715

— 1,715 Cash and cash equivalents, end of year - discontinued operations $

— $

— $ 519 $

— $ 519

For The Year Ended December 31, 2011

Parent Company Combined

Guarantor Subsidiaries Combined

NonGuarantor Subsidiaries Eliminations Consolidated (In thousands) Net cash provided by operating activities - continuing operations $ 56,563 $ 98,948 $

— $

— $ 155,511 Net cash used in investing activities - continuing operations (194,689) (356,168)

— 300,789 (250,068) Net cash provided by financing activities - continuing operations 155,842 261,773

— (300,789) 116,826 Net increase (decrease) in cash and cash equivalents from continuing operations 17,716 4,553

— — 22,269 Net increase (decrease) in cash and cash equivalents from discontinued operations 1,715 1,715 Cash and cash equivalents, beginning ofyear - continuing operations 1,418 2,710

— — 4,128 Cash and cash equivalents, end of year - continuing operations $ 19,134 $ 7,263 $

— $

— $ 26,397 Cash and cash equivalents, beginning of year - discontinued operations

— — — — — Cash and cash equivalents, end of year - discontinued operations $

— $

— $ 1,715 $

— $ 1,715

For The Year Ended December 31, 2010

Parent Company Combined

Guarantor Subsidiaries Combined

NonGuarantor Subsidiaries Eliminations Consolidated (In thousands) Net cash provided by operating activities - continuing operations $ 24,781 $ 69,635 $

— $

— $ 94,416 Net cash used in investing activities - continuing operations (194,690) (268,069)

— 198,644 (264,115) Net cash provided by financing activities - continuing operations 169,990 198,644

— (198,644) 169,990 Net increase (decrease) in cash and cash equivalents from continuing operations 81 210

— — 291 Net increase (decrease) in cash and cash equivalents from discontinued operations

— — — — — Cash and cash equivalents, beginning of year - continuing operations 1,337 2,500

— — 3,837 Cash and cash equivalents, end of year - continuing operations $ 1,418 $ 2,710 $

— $

— $ 4,128 Cash and cash equivalents, beginning of year - discontinued operations

— — — — — Cash and cash equivalents, end of year - discontinued operations $

— $

— $

— $

— $

—F-35

15. Supplemental Disclosures about Oil and Gas Producing Activities (Unaudited) At December 31, 2012, the Company’s oil and gas properties are located in the U.S. and U.K.North Sea.All information presented
as "U.K." in this footnote relates to the U.K. North Sea discontinued operations. For additional information see “Note 3. Assets Held for Sale and Discontinued Operations.” Costs Incurred Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below: Year Ended December 31, 2012 2011 2010

(In thousands) U.S. Unproved property acquisition costs $ 139,344 $ 108,212 $ 126,783 Exploration costs 557,523 374,366 134,487 Development costs 25,756 19,769 62,952 Asset retirement obligations 2,401 3,369 1,031 Total costs incurred $ 725,024 $ 505,716 $ 325,253 U.K. Unproved property acquisition costs $ 11,135 $ 1,004 $ 806 Exploration costs

— — — Development costs 35,225 38,775 5,375 Asset retirement obligations 1,036 2,649

— Total costs incurred $ 47,396 $ 42,428 $ 6,181 T otal W orldwide Unproved property acquisition costs $ 150,479 $ 109,216 $ 127,589 Exploration costs 557,523 374,366 134,487 Development costs 60,981 58,544 68,327 Asset retirement obligations 3,437 6,018 1,031 T otal costs incurred $ 772,420 $ 548,144 $ 331,434
Costs incurred excludes capitalized interest on U.S. unproved properties of $24.8 million, $23.4 million, and $20.7 million for the years ended December 31, 2012, 201 1 and 2010, respectively

. Proved Oil and Gas Reserve Quantities Provedreserves are generallythose quantities ofoil and gas,whichby analysis ofgeoscience and engineering data, canbe estimated withreasonable certainty tobe economicallyproducible in futureyears fromknownreservoirsunder 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 ofa new well. Provedundeveloped reserves are generallyprovedreserves 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, 2012, 201 1 and 2010, and the related discounted future net cash flows before income taxes are based on estimates prepared by LaRoche Petroleum Consultants, Ltd. and R yder Scott Company Petroleum Engineers. Such estimates have been prepared in accordance with guidelines established by the SEC.F-36

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: Crude Oil, Condensate and Natural Gas Liquids (MBoe) U.S. U.K. Worldwide Proved reserves: January 1, 2010 14,803

— 14,803 Extensions and discoveries 10,961 5,263 16,224 Revisions of previous estimates (2,102)

— (2,102) Production (452)

— (452) December 31, 2010 23,210 5,263 28,473 Extensions and discoveries 17,404

— 17,404 Revisions of previous estimates (71) 174 103 Sales of reserves in place (10,310)

— (10,310) Production (1,011)

— (1,011) December 31, 2011 29,222 5,437 34,659 Extensions and discoveries 17,153

— 17,153 Revisions of previous estimates 2,500 (196) 2,304 Sales of reserves in place (1,250)

— (1,250) Production (3,167)

— (3,167) December 31, 2012 44,458 5,241 49,699

Proved developed reserves: December 31, 2010 7,387

— 7,387 December 31, 201 1 7,989 2,719 10,708 December 31, 2012 14,295 5,241 19,536

Proved undeveloped reserves: December 31, 2010 15,823 5,263 21,086 December 31, 201 1 21,233 2,718 23,951 December 31, 2012 30,163

— 30,163 Crude oil, condensate and natural gas liquids extensions and discoveries are primarily attributable to the following:
2012 Additions ofU.S. proved developed and undeveloped reserves as a result of drilling and of fset locations in the Eagle Ford Shale and the Niobrara Formation. 2011 Additions ofU.S. proved developed and undeveloped reserves as a result of drilling and of fset locations in the Eagle Ford Shale and the Niobrara Formation; Transfer ofU.K. proved undeveloped reserves to proved developed reserves as a result of drilling. 2010 Additions ofU.S. proved developed and undeveloped reserves as a result of drilling and of fset locations in the Eagle Ford Shale; Additions of U.K. proved undeveloped reserves as a result of the approval of the Huntington Field Development Plan by the Company and its joint venture partners and the U.K. Department of Energy and Climate Change in November 2010. Crude oil, condensate and natural gas liquids sales of reserves in place are primarily attributable to the following:
2011 Sales ofproperties to KKR during the second quarter and GAIL during the third quarter

.F-37 Natural Gas (MMcf) U.S. U.K. Worldwide Proved reserves: January 1, 2010 513,047

— 513,047 Extensions and discoveries 240,347 4,684 245,031 Revisions of previous estimates (54,132)

— (54,132) Production (34,095)

— (34,095) December 31, 2010 665,167 4,684 669,851 Extensions and discoveries 221,544

— 221,544 Revisions of previous estimates (41,990) 154 (41,836) Sales of reserves in place (82,884)

— (82,884) Production (38,990)

— (38,990) December 31, 2011 722,847 4,838 727,685 Extensions and discoveries 72,916

— 72,916 Revisions of previous estimates (20,996) (174) (21,170) Sales of reserves in place (313,483)

— (313,483) Production (37,612)

— (37,612) December 31, 2012 423,672 4,664 428,336

Proved developed reserves: December 31, 2010 358,543

— 358,543 December 31, 201 1 389,795 2,419 392,214 December 31, 2012 229,539 4,664 234,203

Proved undeveloped reserves: December 31, 2010 306,624 4,684 311,308 December 31, 201 1 333,052 2,419 335,471 December 31, 2012 194,134

— 194,134
Natural gas extensions and discoveries are primarily attributable to the following:
2012 Additions ofU.S. proved developed and undeveloped reserves as a result ofdrilling and of fset locations in the Barnett Shale, Marcellus Shale, and Eagle Ford Shale. 2011 Additions ofU.S. proved developed and undeveloped reserves as a result ofdrilling and of fset locations in the Barnett Shale, Marcellus Shale, and Eagle Ford Shale. Transfer of U.K. proved undeveloped reserves to proved developed reserves as a result of drilling. 2010 Additions ofU.S. proved developed and undeveloped reserves as a result ofdrilling and of fset locations in the Barnett Shale and Eagle Ford Shale, as well as an increase in previously estimated proved undeveloped reserves based on operational performance;Additions ofU.K. proved undeveloped reserves as a result ofthe approval ofthe Huntington Field Development Plan by the Company and itsjoint venture partners and the U.K. Department ofEnergy and Climate Change in November 2010.

Natural gas revisions ofprevious estimates are primarily attributable to the following:
2012 Negative price revisions primarily in the Barnett Shale. 2011 Negative price revisions primarily in the Barnett Shale. 2010 Positive price revisions of fset by negative quantity revisions due to a planned shift in future drilling priorities focusing more on drilling in the core ofthe Barnett Shale, which resulted in removing natural gas reserves previously classified as proved undeveloped in the Barnett Shale. Natural gas sales of reserves in place are primarily attributable to the following:
2012 Sales ofproperties to Atlas during the second quarter and sale of Gulf Coast properties during the third quarter

. 2011 Sales ofproperties to KKR during the second quarter and GAIL during the third quarter

.F-38

StandardizedMeasure The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:
U.S. U.K. Worldwide

(In thousands) 2010 Future cash inflows $ 3,514,978 $ 432,230 $ 3,947,208 Future production costs (952,148) (96,782) (1,048,930) Future development costs (597,444) (78,439) (675,883) Future income taxes (415,021) (128,618) (543,639) Future net cash flows 1,550,365 128,391 1,678,756 Less 10% annual discount to reflect timing of cash flows (895,681) (34,289) (929,970) Standard measure of discounted future net cash flows $ 654,684 $ 94,102 $ 748,786 2011 Future cash inflows $ 4,834,725 $ 617,667 $ 5,452,392 Future production costs (1,212,722) (95,229) (1,307,951) Future development costs (1,163,377) (43,954) (1,207,331) Future income taxes (477,824) (246,273) (724,097) Future net cash flows 1,980,802 232,211 2,213,013 Less 10% annual discount to reflect timing of cash flows (1,124,339) (47,638) (1,171,977) Standard measure of discounted future net cash flows $ 856,463 $ 184,573 $ 1,041,036 2012 Future cash inflows $ 4,960,687 $ 623,678 $ 5,584,365 Future production costs (1,009,850) (87,727) (1,097,577) Future development costs (982,101) (11,194) (993,295) Future income taxes (511,790) (252,493) (764,283) Future net cash flows 2,456,946 272,264 2,729,210 Less 10% annual discount to reflect timing of cash flows (1,277,463) (33,352) (1,310,815) Standard measure of discounted future net cash flows $ 1,179,483 $ 238,912 $ 1,418,395

Reserve estimates and future cash flows are 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 2012, 201 1 and 2010 were $102.03, $95.28, and $74.39 per barrel, respectively

, for crude oil and condensate, $32.12, $44.90 and $35.18 per barrel, respectively , for natural gas liquids, and $2.08, $3.24 and $3.50 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 offuture net cash flows. The standardized measure ofdiscounted future net cash flows is not intended to represent the replacement cost or fair value ofthe Company’s oil and gas properties. An estimate of fair value would also take into account, among other things, the recovery ofreserves 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.F-39

Changes in StandardizedMeasure Changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are summarized below:
U.S. U.K. Worldwide (In thousands) Standardized measure — January 1, 2010 $ 382,093 $

— $ 382,093 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production 263,663

— 263,663 Net change in estimated future development costs 83

— 83 Net change due to revisions in quantity estimates (25,451)

— (25,451) Accretion of discount 39,833

— 39,833 Changes in production rates (timing) and other 49,806

— 49,806 T otal revisions 327,934

— 327,934 Net change due to extensions and discoveries, net of estimated future development and production costs 157,846 193,985 351,831 Net change due to sales of minerals in place

— — — Sales of oil and gas produced, net of production costs (115,800)

— (115,800) Previously estimated development costs incurred 43,940

— 43,940 Net change in income taxes (141,329) (99,883) (241,212) Net change in standardized measure of discounted future net cash flows 272,591 94,102 366,693 Standardized measure — December 31, 2010 $ 654,684 $ 94,102 $ 748,786 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production 134,952 128,525 263,477 Net change in estimated future development costs (509) (4,144) (4,653) Net change due to revisions in quantity estimates (64,860) 13,078 (51,782) Accretion of discount 81,225 19,399 100,624 Changes in production rates (timing) and other (78,199) (16,094) (94,293) Total revisions 72,609 140,764 213,373 Net change due to extensions and discoveries, net of estimated future development and production costs 508,558

— 508,558 Net change due to sales of minerals in place (150,437)

— (150,437) Sales of oil and gas produced, net of production costs (173,853)

— (173,853) Previously estimated development costs incurred 5,381 39,779 45,160 Net change in income taxes (60,479) (90,072) (150,551) Net change in standardized measure of discounted future net cash flows 201,779 90,471 292,250 Standardized measure — December 31, 2011 $ 856,463 $ 184,573 $ 1,041,036 Revisions to reserves proved in prior years: Net change in sales prices and production costs related to future production (55,249) 49,719 (5,530) Net change in estimated future development costs 91,404

— 91,404 Net change due to revisions in quantity estimates (77,919) (46,803) (124,722) Accretion of discount 107,451 37,453 144,904 Changes in production rates (timing) and other (3,369) (6,061) (9,430) Total revisions 62,318 34,308 96,626 Net change due to extensions and discoveries, net of estimated future development and production costs 599,544

— 599,544 Net change due to sales of minerals in place (212,910)

— (212,910) Sales of oil and gas produced, net of production costs (313,354)

— (313,354) Previously estimated development costs incurred 202,187 32,760 234,947 Net change in income taxes (14,765) (12,729) (27,494) Net change in standardized measure of discounted future net cash flows 323,020 54,339 377,359 Standardized measure — December 31, 2012 $ 1,179,483 $ 238,912 $ 1,418,395F-40

16. Selected Quarterly Financial Data (Unaudited) The following table presents selected quarterly financial data for the years ended December 31, 2012 and 201 1 : 2012 First Second Third Fourth (In thousands, except per share amounts) Oil and gas revenues $ 80,715 $ 83,818 $ 96,197 $ 107,450 Operating income 22,379 14,808 24,315 37,151 Net income (loss) from continuing operations $ 10,676 $ 25,900 $ (1,860) $ 16,461 Net income (loss) $ 9,423 $ 28,504 $ (930) $ 18,490

Net income (loss) per share - basic Net income (loss) from continuing operations $ 0.27 $ 0.65 $ (0.05) $ 0.41 Net income (loss) per share $ 0.24 $ 0.72 $ (0.02) $ 0.47
Net income (loss) per share - diluted Net income (loss) from continuing operations $ 0.27 $ 0.65 $ (0.05) $ 0.41 Net income (loss) per share $ 0.24 $ 0.71 $ (0.02) $ 0.46

2011 First Second Third Fourth (In thousands, except per share amounts) Oil and gas revenues $ 44,058 $ 50,672 $ 51,668 $ 55,769 Operating income 9,765 6,281 16,941 5,164 Net income from continuing operations $ 735 $ 5,607 $ 21,491 $ 4,702 Net income $ 735 $ 7,742 $ 21,643 $ 6,510

Net income per share - basic Net income from continuing operations $ 0.02 $ 0.14 $ 0.55 $ 0.12 Net income per share $ 0.02 $ 0.20 $ 0.56 $ 0.17

Net income per share - diluted Net income from continuing operations $ 0.02 $ 0.14 $ 0.55 $ 0.12 Net income per share $ 0.02 $ 0.20 $ 0.55 $ 0.16

The sum ofthe quarterly net income per common share may not agree with the total year net income per common share as each quarterly computation is based on the weighted average common shares outstanding during that period. Previously reported amounts have been reclassified to reflect the U.K. North Sea as discontinued operations.S-1 SIGNA TURES
Pursuant to the requirements of Section 13 or 15(d) ofthe Securities Exchange Act of 1934, the registrant has caused this report to be signed on its behalfby the undersigned, thereunto duly authorized.

CARRIZO OIL & GAS, INC.
By: /s/ Paul F. Boling

Paul F. Boling Chief Financial Officer, Vice President, Secretary and Treasurer
Date: February 27, 2013
Pursuant to the requirements ofthe Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf ofthe registrant and in the capacities and on the dates indicated.

Name Capacity Date
/s/ S.P . Johnson IV President, ChiefExecutive Of ficer and Director February 27, 2013 S. P. Johnson IV (Principal Executive Of ficer)
/s/ Paul F. Boling ChiefFinancial Of ficer, V ice President, February 27, 2013 Paul F . Boling Secretary and T reasurer (Principal Financial Of

ficer)
/s/ David L. Pitts V ice President and ChiefAccounting Of ficer February 27, 2013 David L. Pitts (Principal Accounting Of ficer)
/s/ Steven A. W

ebster Chairman ofthe Board February 27, 2013 Steven A. W

ebster

/s/ Thomas L. Carter, Jr

. Director February 27, 2013 Thomas L. Carter

, Jr
.

/s/ Robert F. Fulton Director February 27, 2013 Robert F . Fulton

/s/ F. Gardner Parker Director February 27, 2013 F. Gardner Parker

/s/ Roger A. Ramsey Director February 27, 2013 Roger A. Ramsey

/s/ Frank A. W

ojtek Director February 27, 2013 Frank A. W

ojtekExhibit 21.1 Subsidiaries of the Company The Company

, Carrizo Oil & Gas, Inc., has the following wholly owned Subsidiaries: Subsidiary Bandelier Pipeline Holding, LLC Carrizo (Eagle Ford) LLC Carrizo Marcellus Holding Inc. Carrizo (Marcellus) LLC Carrizo (Marcellus) WV

LLC Carrizo (Niobrara) LLC Carrizo (Utica) LLC Carrizo UK Bardolph Ltd Carrizo UK Huntington Ltd CLLR, Inc. Hondo Pipeline, Inc. Mescalero Pipeline, LLC Monument Exploration, LLC
The Company

, Carrizo Oil & Gas, Inc., also has less than a 10% interest in the following entity: Oxane Materials, Inc.Exhibit 23.1 Consent of Independent Registered Public Accounting Firm
The Board of Directors Carrizo Oil & Gas, Inc.:
W e consent to the incorporation by reference in the registration statement (No. 333-173821) on and the registration statements (Nos. 333-181585, 16528, and on ofCarrizo Oil & Gas, Inc. of our reports dated February 27, 2013, with respect to the consolidated balance sheets of Carrizo Oil & Gas, Inc. as ofDecember 31, 2012 and 201 1, and the related consolidated statements ofincome, shareholders’ equity , and cash flows, for each ofthe years in the period ended December 31, 2012, and the ef fectiveness of internal control over financial reporting
as ofDecember 31, 2012, which reports appear in the December 31, 2012 annual report on ofCarrizo Oil & Gas, Inc.
/s/ KPMG LLP Houston, T

exas February 27, 2013Exhibit 23.2

CONSENTOF

INDEPENDENTPETROLEUM ENGINEERS

W e hereby consent to the incorporation by reference in the registration statements on Form S-8 (Registration Nos. 333-181585, 333-162888, 333-137273, 333-1 16528, 333-55838 and 333-35245) andtheregistration statement onForm S-3 (RegistrationNo. 333-173821) ofCarrizo Oil & Gas, Inc. ofour letter dated February 25, 2013, relating to estimates ofproved reserves attributable to certain interests of Carrizo Oil & Gas, Inc. as ofDecember 31, 2012. LaRoche Petroleum Consultants, Ltd.
/s/ W illiam M. Kazmann W illiam M. Kazmann Senior Partner

Houston, T

exas February 27, 2013Exhibit 23.3

CONSENTOF

INDEPENDENTPETROLEUM ENGINEERS

W e hereby consent to the incorporation by reference in the registration statements on Form S-8 (Registration Nos. 333-181585, 333-162888, 333-137273, 333-1 16528, 333-55838 and 333-35245) and the registration statement on Form S-3 (Registration No. 333-173821) of Carrizo Oil & Gas, Inc. of our letter dated February 6, 2013, relating to estimates of proved reserves attributable to certain interests of Carrizo Oil & Gas, Inc. as of December 31, 2012.

/s/ R YDER SCOTTCOMP

ANY , L.P

. R YDER SCOTTCOMP

ANY , L.P
. TBPE Firm Registration No. F-1580 Houston, T

exas February 27, 2013Exhibit 23.4

CONSENTOF

INDEPENDENTPETROLEUM ENGINEERS

W e hereby consent to the incorporation by reference in the registration statements on Form S-8 (Registration Nos. 333-181585, 333-162888, 333-137273, 333-1 16528, 333-55838 and 333-35245) and the registration statement on Form S-3 (Registration No. 333-173821) of Carrizo Oil & Gas, Inc. of our letter dated February 15, 2013, relating to estimates of proved reserves attributable to certain interests of Carrizo Oil & Gas, Inc. as of December 31, 2012.

/s/ R YDER SCOTTCOMP

ANY , L.P

. R YDER SCOTTCOMP

ANY , L.P
. TBPE Firm Registration No. F-1580 Houston, T

exas February 27, 2013Exhibit 31.1
CER TIFICA TION
PRINCIP AL EXECUTIVE OFFICER I, S.P

. Johnson, IV

, certify that: 1. I have reviewed this Annual Report on Form 10-K of Carrizo Oil & Gas, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light ofthe circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying of ficer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act and for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. evaluated the ef

fectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the ef

fectiveness ofthe disclosure controls and procedures, as ofthe end ofthe period covered by this report based on such evaluation; and d. disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially af

fected, or is reasonably likely to materially af fect the registrant's internal control over financial reporting; and 5. The registrant’s other certifying of ficer and I have disclosed, based on our most recent evaluation ofinternal control over financial reporting, to the registrant’s auditors and the audit committee ofthe registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely af fect the registrant's ability to record, process, summarize and report financial information; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 27, 2013 /s/ S.P

. Johnson, IV S.P

. Johnson, IV President and ChiefExecutive Of ficerExhibit 31.2
CER TIFICA TION
PRINCIP AL FINANCIAL

OFFICER I, Paul F

. Boling, certify that: 1. I have reviewed this Annual Report on Form 10-K of Carrizo Oil & Gas, Inc.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light ofthe circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying of ficer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act and for the registrant and have:

a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. evaluated the ef

fectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the ef

fectiveness ofthe disclosure controls and procedures, as ofthe end ofthe period covered by this report based on such evaluation; and d. disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially af

fected, or is reasonably likely to materially af fect the registrant's internal control over financial reporting; and 5. The registrant’s other certifying of ficer and I have disclosed, based on our most recent evaluation ofinternal control over financial reporting, to the registrant’s auditors and the audit committee ofthe registrant’s board of directors (or persons performing the equivalent functions):

a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely af fect the registrant's ability to record, process, summarize and report financial information; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 27, 2013 /s/ Paul F

. Boling Paul F

. Boling V ice President, ChiefFinancial Of ficer and SecretaryExhibit 32.1
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, S.P

. Johnson, IV

, President and ChiefExecutive Of ficer ofCarrizo Oil & Gas, Inc., a T exas corporation (the “Company”), hereby certify , to my knowledge, that: 1. the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) ofthe Securities Exchange Act of 1934; and 2. information containedintheReport fairlypresents, in allmaterialrespects,the financial condition andresults ofoperations ofthe Company

.
Date: February 27, 2013 /s/ S.P

. Johnson, IV S.P

. Johnson, IV President and ChiefExecutive Of ficer
The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) ofSection 1350, Chapter 63 ofTitle 18, United States Code) and is not being filed as part ofthe Report or as a separate disclosure document.
A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staf fupon request.Exhibit 32.2
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)
Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, Paul F

. Boling, V ice President, Chief Financial Of ficer and Secretary of Carrizo Oil & Gas, Inc., a T exas corporation (the “Company”), hereby certify , to my knowledge, that: 1. the Company’s Annual Report on Form 10-K for the year ended December 31, 2012 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) ofthe Securities Exchange Act of 1934; and 2. information containedintheReport fairlypresents, in allmaterialrespects,the financial condition andresults ofoperations ofthe Company

.
Date: February 27, 2013 /s/ Paul F

. Boling Paul F

. Boling V ice President, ChiefFinancial Of ficer and Secretary
The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) ofSection 1350, Chapter 63 ofTitle 18, United States Code) and is not being filed as part ofthe Report or as a separate disclosure document.
A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staf fupon request.R YDER SCOTTCOMP

ANY PETROLEUM CONSUL T ANTS 

### Exhibit 99.2



## Carrizo Oil & Gas, Inc.

Estimated
Future Reserves and Income
Attributable to Certain
Leasehold Interests

SEC Parameters

As of December 31, 2012

/s/ Michael F. Stell /s/ Lucas E. Smith Michael F. Stell, P.E. Lucas E. Smith, P.E. TBPE License No. 56416 TBPE License No. 105168 Advising Senior Vice President Senior Petroleum Engineer [SEAL] [SEAL]
R YDER SCOTT COMP

ANY , L.P

. TBPE Firm Registration No. F-1580SUITE 600, 1015 4TH STREET, S.W

. CALGAR

Y , ALBER T A T2R 1J4 TEL (403) 262-2799 F AX (403) 262-2790 621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 F AX (303) 623-4258 

### [Ryder Scott Company L.P

. logo]

TBPE REGISTERED ENGINEERING FIRM F-1580 F AX (713) 651-0849 1 100 LOUISIANA

SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191



### February 6, 2013

Carrizo Oil & Gas, Inc. 500 Dallas Street, Suite 2300 Houston, TX 77002

Gentlemen:
At your request, Ryder Scott Company, L.P

. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Carrizo Oil & Gas, Inc. (Carrizo) as of December 31, 2012. The subject properties are located in the states of Alabama, Colorado, Louisiana, New Y ork, Pennsylvania and T exas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on February 1, 2013 and presented herein, was prepared for public disclosure by Carrizo in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.
The properties evaluated by Ryder Scott account for a portion of Carrizo’s total net proved reserves as of December 31, 2012. Based on information provided by Carrizo, the third party estimate conducted by Ryder Scott addresses 68 percent of the total proved developed net liquid hydrocarbon reserves, 26 percent of the total proved developed net gas reserves, 100 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 31 percent of the total proved undeveloped net gas reserves of Carrizo.
The estimated reserves and future net income amounts presented in this report, as of December 31, 2012, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in ef fect on the first-day-ofthe-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may dif

fer significantly from the estimated quantities presented in this report. The results of this study are summarized below

.Carrizo Oil & Gas, Inc.

February 6, 2013 Page 2

R YDER SCOTTCOMP

ANY PETROLEUM CONSUL T ANTS 

### SEC P ARAMETERS Estimated Net Reserves and Income Data Certain Leasehold Interests of Carrizo Oil & Gas, Inc. As of December 31, 2012

Proved Developed Total Producing Non-Producing Undeveloped Proved Net Remaining Reserves Oil/Condensate – Barrels 11,696,223 657 26,399,929 38,096,809 Plant Products – Barrels 1,619,681 0 3,763,188 5,382,869 Gas – MMCF 60,139 794 59,269 120,202

Income Data (M$) Future Gross Revenue $1,305,566 $1,774 $2,787,462 $4,094,802 Deductions 254,430 754 1,190,887 1,446,071 Future Net Income (FNI) $1,051,136 $1,020 $1,596,575 $2,648,731

Discounted FNI @ 10% $ 627,785 $ 606 $ 680,415 $1,308,806



### Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the of ficial temperature and pressure bases of the areas in which the gas reserves are located.
The estimates ofthe reserves, future production, and income attributable to properties in this report were prepared using the economic software package AriesTM 

### System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used at the request of Carrizo. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding dif ferences are not material.
The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Liquid hydrocarbon reserves account for approximately 94 percent and gas reserves account for the remaining 6 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly

. Future net income was discounted at four other discount rates which were also compounded monthly

. These results are shown in summary form as follows.Carrizo Oil & Gas, Inc.

February 6, 2013 Page 3

R YDER SCOTTCOMP

ANY PETROLEUM CONSUL T ANTS Discounted Future Net Income As of December 31, 2012 Discount Rate Total Percent Proved M$ 5 $1,769,349 15 $1,029,789 20 $843,261 25 $709,894



### The results shown above are presented for your information and should not be construed as our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.
No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes presented herein do not include volumes of gas consumed in operations as 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.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability

. At Carrizo’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.
Proved oil and gas reserves are “those 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.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available oras economic conditions change. For proved reserves,the SEC statesthat “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR isCarrizo Oil & Gas, Inc.

February 6, 2013 Page 4

R YDER SCOTTCOMP

ANY PETROLEUM CONSUL T ANTS 

### much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, ef fects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.
Carrizo’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to dif fer significantly from the estimated quantities.
The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Carrizo owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Estimates of Reserves
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy

. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must selectthe method or combination of methodswhich intheir professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property

. In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator

. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator

. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.Carrizo Oil & Gas, Inc.

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### Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities andtheirassociated reserve categories may also be revised dueto otherfactors such as changes in economic conditions, results of future operations, ef fects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, or a combination of methods. All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods

. The performance methods, such as decline curve analysis, utilized extrapolations of historical production and pressure data available through December 2012 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Carrizo or obtained from public data sources and were considered suf ficient for the purpose thereof.
All of the proved developed non-producing reserves included herein were estimated by the volumetric method. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Carrizo orwhichwe have obtained from public data sources thatwere available through December 2012. All of the proved undeveloped reserves utilized data from analogs as the basis for the proved reserves estimates included herein. The data utilized from the analogs as well as well and seismic data incorporated into our volumetric analysis were considered suf ficient for the purpose thereof.
T o estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts offuture production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
Carrizo has informed us that they have furnished us all ofthe material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Carrizo with respect to property interests, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or dif ferentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Carrizo. We consider the factual data used in this report appropriate and suf ficient for the purpose of preparing the estimates of reserves and future net revenues herein.
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion,Carrizo Oil & Gas, Inc.

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### the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
Future Production Rates
For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the ef fects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.
T est data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Carrizo. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/ or constraints set by regulatory bodies.
The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. Hydrocarbon Prices
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in ef fect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.
Carrizo furnished us with the above mentioned average prices in ef fect on December 31, 2012. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for dif ferentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.
The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “dif ferentials.” The dif

ferentials used in the preparation of this report were furnished to us by Carrizo. The dif ferentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Carrizo to determine these dif ferentials.Carrizo Oil & Gas, Inc.

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### In addition, the table below summarizes the net volume weighted benchmark prices adjusted for dif ferentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area Product Price Reference A

verage Benchmark Prices A

verage Realized Prices
North America United States Oil/Condensate WTI Cushing $94.71/Bbl $101.47/Bbl

NGLs WTI Cushing $94.71/Bbl $32.12/Bbl Gas Henry Hub $2.76/MMBTU $2.09/MCF

The ef fects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations
Costs Operating costs for the leases and wells in this report are based on the operating expense reports of Carrizo and include only those costs directly applicable to the leases or wells. The operating costs include a portion ofgeneral and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COP AS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells. Development costswerefurnished to us by Carrizo and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by Carrizo were accepted without independent verification.
The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with Carrizo’s plans to develop these reserves as of December 31, 2012. The implementation of Carrizo’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Carrizo’s management. As the result of our inquiries during the course of preparing this report, Carrizo has informed us that the development activities included herein have been subjected to and received the internal approvals required by Carrizo’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Carrizo. Additionally, Carrizo has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.
Current costs used by Carrizo were held constant throughout the life of the properties.Carrizo Oil & Gas, Inc.

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### Standards of Independence and Professional Qualification Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years. Ryder Scott is employeeowned and maintains of fices in Houston, T

exas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staf f. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as of ficers or directors of any privately-owned or publiclytraded oil and gas company and are separate and independentfrom the operating and investment decisionmaking process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services. Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staf f have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staf f to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an of ficer of the Company, Ryder Scott requires that staf f engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.
We are independent petroleum engineers with respect to Carrizo

. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.
The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical persons primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter

. T erms of Usage
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Carrizo.
Carrizo makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Carrizo has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Carrizo of the references to our name as well as to the references to our third party report for Carrizo, which appears in the December 31, 2012 annual report on Form 10-K of Carrizo. Ourwritten consent for such use is included as a separate exhibit to the filings made with the SEC by Carrizo.
We have provided Carrizo with a digital version of the original signed copy of this report letter

. In the event there are any dif ferences between the digital version included in filings made by Carrizo and the original signed report letter, the original signed report letter shall control and supersede the digital version.Carrizo Oil & Gas, Inc.

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### The data and work papers used in the preparation of this report are available for examination by authorized parties in our of fices. Please contact us if we can be of further service.
V ery truly yours,
R YDER SCOTT COMP

ANY , L.P

. TBPE Firm Registration No. F-1580

/s/ Michael F

. Stell

Michael F

. Stell, P.E. TBPE License No. 56416 Advising Senior Vice President [SEAL]

/s/ Lucas E. Smith

Lucas E. Smith, P.E. TBPE License No. 105168 Senior Petroleum Engineer [SEAL] MFS (DPR)/plR YDER SCOTTCOMP

ANY PETROLEUM CONSUL T ANTS 

### Professional Qualifications of Primary T echnical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P

. Mr

. Michael F

. Stell was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.
Mr

. Stell, an employee of Ryder Scott Company L.P

. (Ryder Scott) since 1992, is an Advising Senior Vice President and is responsibleforcoordinating and supervising staf fand consulting engineers ofthe company in ongoing reservoir evaluation studies worldwide. Beforejoining Ryder Scott, Mr

. Stell served in a number ofengineering positionswith Shell Oil Company and Landmark Concurrent Solutions. For more information regarding Mr

. Stell’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.
Mr

. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of T exas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
In addition to gaining experience and competency through prior work experience, the T exas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr

. Stell fulfills. As part of his 2009 continuing education hours, Mr

. Stell attended an internally presented 13 hours of formalized training as well as a day-long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register

. Mr

. Stell attended an additional 15 hours offormalized in-house training as well as an additional five hours offormalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. As part of his 2010 continuing education hours, Mr

. Stell attended an internally presented six hours of formalized training and ten hours of formalized external training covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, evaluation of enhanced oil recovery reserves, and ethics training. For 201 1 and 2012, as of the date of this report, Mr

. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.
Based on his educational background, professional training and over 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr

. Stell has attained the professional qualifications for a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.R YDER SCOTTCOMP

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### PETROLEUM RESER

VES DEFINITIONS
As Adapted From: RULE 4-10(a) of REGULA TION S-X P

ART 210 UNITED ST

A TES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take ef fectfor allfilings madewith the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part orwhollyfrom the aforementioned SEC document are denoted in italics herein).
Reserves are estimated remaining quantities ofoil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability

. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery

. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature oftheir in-place characteristics, extraction method applied, or degree of processing prior to sale. ExamplesPETROLEUM RESER VES DEFINITIONS Page 2

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### of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basincentered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory

. Because ofthe dif

ferences in uncertainty, caution should be exercised when aggregating quantities of petroleum from dif

ferent reserves categories.

RESER VES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves. Reserves are estimated remaining quantities ofoil 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.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major , potentially sealing, faults until those reservoirs are penetrated and evaluated as economicallyproducible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e., absence of reservoir , structurally low reservoir , or negative test results). Such areas may contain prospective resources ( i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESER

VES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves. Proved oil and gas reserves are those quantities ofoil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economicallyproducible—from a given date forward, from known reservoirs, and underexisting economic conditions, operating methods, and government regulations—priorto 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 the 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. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any , and (B)Adjacent undrilledportions ofthe reservoirthat can, with reasonable certainty , bejudged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.PETROLEUM RESER VES DEFINITIONS Page 3

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### PROVED RESER

VES (SEC DEFINITIONS) CONTINUED (ii) In the absence ofdata on fluid contacts, proved quantities in a reservoirare limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty

. (iii) Where directobservation from wellpenetrations has defineda highestknown oil (HKO) 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

. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) 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 reservoiroran analogous reservoir , orotherevidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoiris to be determined. The price shall be the average price during the 12-month periodprior 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.R YDER SCOTTCOMP

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### PETROLEUM RESER

VES ST A TUS DEFINITIONS AND GUIDELINES
As Adapted From: RULE 4-10(a) of REGULA TION S-X P

ART 210 UNITED ST

A TES SECURITIES AND EXCHANGE COMMISSION (SEC)

and PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by: SOCIETY

OF PETROLEUM ENGINEERS (SPE) WORLD PETROLEUM COUNCIL(WPC) AMERICAN ASSOCIA TION OF PETROLEUM GEOLOGISTS (AAPG) SOCIETY

OF PETROLEUM EV

ALUA TION ENGINEERS (SPEE)



### Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10 (a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESER

VES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows: Developed oil andgas reserves are reserves ofany 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 ofthe reserves estimate if the extraction is by means not involving a well. Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or NonProducing. Developed Producing Reserves Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.PETROLEUM RESER VES ST A TUS DEFINITIONS AND GUIDELINES Page 2

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### Developed Non-Producing Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
Shut-In Shut-in Reserves are expected to be recovered from: (1) completion intervals which are open at the time of the estimate, but which have not started producing; (2) wells which were shut-in for market conditions or pipeline connections; or (3) wells not capable of production for mechanical reasons. Behind-Pipe Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start ofproduction.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESER VES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows: Undeveloped oil and gas reserves are reserves ofany 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 shall be 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 at greater distances. (ii) Undrilled locations can be 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 shall estimates for undeveloped reserves be attributable to any acreage for which an application offluid injection orotherimproved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoiroran analogous reservoir , as defined in paragraph (a)(2) ofthis section, or by other evidence using reliable technology establishing reasonable certainty

.R YDER SCOTTCOMP

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### Exhibit 99.3



## Carrizo Oil & Gas, Inc.

Estimated
Future Reserves and Income
Attributable to

Certain Leasehold and Royalty Interests in the

Huntington (Forties) Field

SEC Parameters

As of December 31, 2012

/s/ Michael F. Stell Michael F. Stell, P.E. TBPE License No. 56416 Advising Senior Vice President [SEAL] R YDER SCOTT COMP

ANY , L.P

. TBPE Firm Registration No. F-1580TBPE REGISTERED ENGINEERING FIRM F-1580 F AX (713) 651-0849

SUITE 600, 1015 4TH STREET, S.W

. CALGAR

Y , ALBER T A T2R 1J4 TEL (403) 262-2799 F AX (403) 262-2790 621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 F AX (303) 623-4258 

### [Ryder Scott Company , L.P

. logo]

TBPE REGISTERED ENGINEERING FIRM F-1580 F AX (713) 651-0849 1 100 LOUISIANA

SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191



### February 15, 2013

Carrizo Oil & Gas, Inc. 1000 Louisiana Street, Suite 1500 Houston, T

exas 77002

Gentlemen:
At your request, Ryder Scott Company, L.P

. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests in the Huntington (Forties) Field of Carrizo Oil & Gas, Inc. (Carrizo) as of December 31, 2012. The subject property is located in the North Sea of fshore United Kingdom (UK). The reserves and income data were estimated based on the definitions and disclosure guidelines ofthe United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on February 15, 2013 and presented herein, was prepared for public disclosure by Carrizo in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.
The property evaluated by Ryder Scott accounts for a portion of Carrizo’s total net proved reserves as of December 31, 2012. The property evaluated by Ryder Scott represent 12 percent of the total net proved liquid hydrocarbon reserves and one percent of the total net proved gas reserves of Carrizo as of December 31, 2012. Based on information provided by Carrizo, the third party estimate conducted by Ryder Scott addresses 27 percent of the total proved developed net liquid hydrocarbon reserves and two percent of the total proved developed net gas reserves. There are no undeveloped reserves in Huntington Field.
The estimated reserves and future net income amounts presented in this report, as of December 31, 2012, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in ef fect on the first-day-ofthe-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may dif

fer significantly from the estimated quantities presented in this report. The results of this study are summarized below

.Carrizo Oil & Gas, Inc.

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### SEC P ARAMETERS Estimated Net Reserves and Income Data Attributable to Certain Leasehold and Royalty Interests in the

Huntington (Forties) Field Carrizo Oil & Gas, Inc. As of December 31, 2012

Total Proved Developed Non-Producing Net Remaining Reserves Oil/Condensate – Barrels 5,240,944 Gas – MMCF 4,664

Income Data Future Gross Revenue $623,677,688 Deductions 98,920,641 Future Net Income (FNI) $524,757,047

Discounted FNI @ 10% $441,596,781



### Liquid hydrocarbons are expressed in standard 42 gallon barrels. Gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the of ficial temperature and pressure bases of the areas in which the gas reserves are located.
The estimates of the reserves, future production, and income attributable to property in this report were prepared using the economic software package AriesTM 

### System Petroleum Economic Evaluation Software, a copyrighted program of Halliburton. The program was used at the request of Carrizo. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the property being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same property, also due to rounding. The rounding dif ferences are not material.
The deductions incorporate the normal direct costs of operating the wells, planned workover costs, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of U.S. state and federal or foreign income taxes and after general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. The costs associated with fuel usage and oil and gas tarif fs are shown as negative revenue in the “Other Revenue” column of the tables. Liquid hydrocarbon reserves account for approximately 93 percent and gas reserves account for the remaining 7 percent of total future gross revenue from proved reserves.
The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly

. Future net income was discounted at four other discount rates which were also compounded monthly

. These results are shown in summary form as follows.Carrizo Oil & Gas, Inc.

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ANY PETROLEUM CONSUL T ANTS Discounted Future Net Income As of December 31, 2012 Discount Rate Total Percent Proved

8 $456,126,750 12 $427,942,781 15 $408,949,375 20 $380,755,281



### The results shown above are presented for your information and should not be construed as our estimate of fair market value.
Reserves Included in This Report
The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.
The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved developed non-producing reserves included herein consist of the behind pipe category

. 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.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability

. At Carrizo’s request, this report addresses only the proved reserves attributable to the property evaluated herein.
Proved oil and gas reserves are “those 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.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”
Proved reserve estimates will generally be revised only as additional geologic or engineering data become available oras economic conditions change. For proved reserves,the SEC statesthat “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, ef fects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates onlyCarrizo Oil & Gas, Inc.

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### and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts. Ryder Scott did not evaluate country and geopolitical risks in the UK where Carrizo has interests. Carrizo’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to dif fer significantly from the estimated quantities.
The estimates ofproved reserves presented hereinwere based upon a detailed study ofthe property in which Carrizo owns an interest; however, we have not made any field examination of the property

. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.
Estimates of Reserves
The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy

. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must selectthe method or combination of methodswhich intheir professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property

. In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator

. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator

. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.
Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities andtheirassociated reserve categories may also be revised dueto otherfactors such as changesCarrizo Oil & Gas, Inc.

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### in economic conditions, results of future operations, ef fects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.
The proved non-producing reserves included herein were estimated by the volumetric method since the subject property is not yet on production. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by Carrizo or which we have obtained from public data sources that were available through December 2012. The data utilized from the well and seismic data incorporated into our volumetric analysis were considered suf ficient for the purpose thereof.
T o estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts offuture production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.
Carrizo has informed us that they have furnished us all ofthe material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Carrizo with respect to property interests, production and well tests, normal direct costs, other costs such as transportation and/ or processing fees, recompletion and development costs, abandonment costs after salvage, product prices adjustments, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Carrizo. We consider the factual data used in this report appropriate and suf ficient for the purpose of preparing the estimates of reserves and future net revenues herein.
In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.
Future Production Rates
T est data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Carrizo. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/ or constraints set by regulatory bodies.Carrizo Oil & Gas, Inc.

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### The future production rates from wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies. Hydrocarbon Prices
The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in ef fect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.
Carrizo furnished us with the above mentioned average prices in ef fect on December 31, 2012. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for dif ferentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report.
The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “dif ferentials.” The dif

ferentials used in the preparation of this report were furnished to us by Carrizo. The dif ferentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Carrizo to determine these dif ferentials.
In addition, the table below summarizes the net volume weighted benchmark prices adjusted for dif ferentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

Geographic Area Product Price Reference A verage Benchmark Prices A verage Realized Prices United Kingdom North Sea Oil/Condensate Brent $111.21/Bbl $111.21/Bbl

Gas UK $9.54/MMBTU $13.32/MCF



### The ef fects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.Carrizo Oil & Gas, Inc.

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### Costs Operating costs for the leases and wells in this report are based on binding third party bids for the FPSO vessel as provided by Carrizo. The monthly costs to lease and operate the FPSO vessel are contractually reduced over the first five years of the project life, and our forecast cost assumptions are based on those contracted costs. The operating costs also include general and administrative costs as provided by the operator

. No deduction was made for loan repayments, interest expenses, and exploration and development prepayments that are not charged directly to the leases or wells. Development costs were furnished to us by Carrizo and are based on binding third party bids, most recent estimates, and/or approved authorizations for expenditure (AFE’s) for the proposed work. The estimated net cost of abandonment after salvage was also furnished by Carrizo and was accepted without independent verification.
The proved non-producing reserves in this report have been incorporated herein in accordance with Carrizo’s plans to develop these reserves as of December 31, 2012. The implementation of Carrizo’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Carrizo’s management. As the result of our inquires during the course of preparing this report, Carrizo has informed us that the development activities included herein have been subjected to and received the internal approvals required by Carrizo’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Carrizo. Additionally, Carrizo has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.
Current costs were held constant throughout the life of the property

. Standards of Independence and Professional Qualification Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years. Ryder Scott is employeeowned and maintains of fices in Houston, T

exas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staf f. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as of ficers or directors of any privately-owned or publiclytraded oil and gas company and are separate and independentfrom the operating and investment decisionmaking process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services. Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staf f have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staf f to maintain and enhance their professional skills by actively participating in ongoing continuing education.
Prior to becoming an of ficer of the Company, Ryder Scott requires that staf f engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. We are independent petroleum engineers with respect to Carrizo

. Neither we nor any of our employees have any interest in the subject property and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the property which were reviewed.Carrizo Oil & Gas, Inc.

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### The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter

. T erms of Usage
The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Carrizo.
Carrizo makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Carrizo has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Carrizo of the references to our name as well as to the references to our third party report for Carrizo, which appears in the December 31, 2012 annual report on Form 10-K of Carrizo. Ourwritten consent for such use is included as a separate exhibit to the filings made with the SEC by Carrizo
We have provided Carrizo with a digital version of the original signed copy of this report letter

. In the event there are any dif ferences between the digital version included in filings made by Carrizo and the original signed report letter, the original signed report letter shall control and supersede the digital version.
The data and work papers used in the preparation of this report are available for examination by authorized parties in our of fices. Please contact us if we can be of further service.
V ery truly yours,
R YDER SCOTT COMP

ANY , L.P

. TBPE Firm Registration No. F-1580

/s/ Michael F

. Stell

Michael F

. Stell, P.E. TBPE License No. 56416 Advising Senior Vice President [SEAL] MFS (DPR)/plR YDER SCOTTCOMP

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### Professional Qualifications of Primary T echnical Person
The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P

. Mr

. Michael F

. Stell was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.
Mr

. Stell, an employee of Ryder Scott Company L.P

. (Ryder Scott) since 1992, is an Advising Senior Vice President and is responsibleforcoordinating and supervising staf fand consulting engineers ofthe company in ongoing reservoir evaluation studies worldwide. Beforejoining Ryder Scott, Mr

. Stell served in a number ofengineering positionswith Shell Oil Company and Landmark Concurrent Solutions. For more information regarding Mr

. Stell’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.
Mr

. Stell earned a Bachelor of Science degree in Chemical Engineering from Purdue University in 1979 and a Master of Science Degree in Chemical Engineering from the University of California, Berkeley, in 1981. He is a licensed Professional Engineer in the State of T exas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
In addition to gaining experience and competency through prior work experience, the T exas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr

. Stell fulfills. As part of his 2009 continuing education hours, Mr

. Stell attended an internally presented 13 hours of formalized training as well as a day-long public forum relating to the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register

. Mr

. Stell attended an additional 15 hours offormalized in-house training as well as an additional five hours offormalized external training during 2009 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. As part of his 2010 continuing education hours, Mr

. Stell attended an internally presented six hours of formalized training and ten hours of formalized external training covering such topics as updates concerning the implementation of the latest SEC oil and gas reporting requirements, reserve reconciliation processes, overviews of the various productive basins of North America, evaluations of resource play reserves, evaluation of enhanced oil recovery reserves, and ethics training. For 201 1 and 2012, as of the date of this report, Mr

. Stell has 20 hours of continuing education hours relating to reserves, reserve evaluations, and ethics.
Based on his educational background, professional training and over 30 years of practical experience in the estimation and evaluation of petroleum reserves, Mr

. Stell has attained the professional qualifications for a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.R YDER SCOTTCOMP

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### PETROLEUM RESER

VES DEFINITIONS
As Adapted From: RULE 4-10(a) of REGULA TION S-X P

ART 210 UNITED ST

A TES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE
On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take ef fectfor allfilings madewith the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part orwhollyfrom the aforementioned SEC document are denoted in italics herein).
Reserves are estimated remaining quantities ofoil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability

. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.
Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.
Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery

. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.
Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature oftheir in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-PETROLEUM RESER VES DEFINITIONS Page 2

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### centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.
Reserves do not include quantities of petroleum being held in inventory

. Because ofthe dif

ferences in uncertainty, caution should be exercised when aggregating quantities of petroleum from dif

ferent reserves categories.

RESER VES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:
Reserves. Reserves are estimated remaining quantities ofoil 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.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major , potentially sealing, faults until those reservoirs are penetrated and evaluated as economicallyproducible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir ( i.e., absence of reservoir , structurally low reservoir , or negative test results). Such areas may contain prospective resources ( i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESER

VES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:
Proved oil and gas reserves. Proved oil and gas reserves are those quantities ofoil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economicallyproducible—from a given date forward, from known reservoirs, and underexisting economic conditions, operating methods, and government regulations—priorto 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 the 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. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any , and (B)Adjacent undrilledportions ofthe reservoirthat can, with reasonable certainty , bejudged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.PETROLEUM RESER VES DEFINITIONS Page 3

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### PROVED RESER

VES (SEC DEFINITIONS) CONTINUED (ii) In the absence ofdata on fluid contacts, proved quantities in a reservoirare limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty

. (iii) Where directobservation from wellpenetrations has defineda highestknown oil (HKO) 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

. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) 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 reservoiroran analogous reservoir , orotherevidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoiris to be determined. The price shall be the average price during the 12-month periodprior 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.R YDER SCOTTCOMP

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### PETROLEUM RESER

VES ST A TUS DEFINITIONS AND GUIDELINES
As Adapted From: RULE 4-10(a) of REGULA TION S-X P

ART 210 UNITED ST

A TES SECURITIES AND EXCHANGE COMMISSION (SEC)

and PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by: SOCIETY

OF PETROLEUM ENGINEERS (SPE) WORLD PETROLEUM COUNCIL(WPC) AMERICAN ASSOCIA TION OF PETROLEUM GEOLOGISTS (AAPG) SOCIETY

OF PETROLEUM EV

ALUA TION ENGINEERS (SPEE)



### Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10 (a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESER

VES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows: Developed oil andgas reserves are reserves ofany 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 ofthe reserves estimate if the extraction is by means not involving a well. Developed Producing (SPE-PRMS Definitions)
While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or NonProducing. Developed Producing Reserves Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.PETROLEUM RESER VES ST A TUS DEFINITIONS AND GUIDELINES Page 2

R YDER SCOTTCOMP

ANY PETROLEUM CONSUL T ANTS 

### Developed Non-Producing Developed Non-Producing Reserves include shut-in and behind-pipe reserves.
Shut-In Shut-in Reserves are expected to be recovered from: (1) completion intervals which are open at the time of the estimate, but which have not started producing; (2) wells which were shut-in for market conditions or pipeline connections; or (3) wells not capable of production for mechanical reasons. Behind-Pipe Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start ofproduction.
In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESER VES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows: Undeveloped oil and gas reserves are reserves ofany 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 shall be 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 at greater distances. (ii) Undrilled locations can be 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 shall estimates for undeveloped reserves be attributable to any acreage for which an application offluid injection orotherimproved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoiroran analogous reservoir , as defined in paragraph (a)(2) ofthis section, or by other evidence using reliable technology establishing reasonable certainty

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### [LaRoche Petroleum Consultants, Ltd. logo] Exhibit 99.1 February 25, 2013
Mr

. Andrew R. Agosto Vice President Carrizo Oil & Gas, Inc. 1000 Louisiana Street, Suite 1500 Houston, T

exas 77002
Dear Mr

. Agosto:
At your request, LaRoche Petroleum Consultants, Ltd. (LPC) has estimated the proved reserves and future cash flow, as of December 31, 2012, to the Carrizo Oil & Gas, Inc. (Carrizo) interest in certain properties located in T arrant County, T

exas. This report was completed as of the date of this letter

. This report was prepared to provide Carrizo with Securities and Exchange Commission (SEC) compliant reserve estimates. It is our understanding that the properties evaluated by LPC comprise forty-two percent (42%) of Carrizo’s total proved reserves. We believe that the assumptions, data, methods, and procedures used in preparing this report, as set out below, are appropriate for the purpose of this report. This report has been prepared using constant prices and costs and conforms to our understanding of the SEC guidelines, reserves definitions, and applicable financial accounting rules.
Summarized below are LPC’s estimates of net reserves and future net cash flow

. Future net revenue is prior to deducting estimated production and ad valorem taxes. Future net cash flow is after deducting these taxes, operating expenses, and future capital expenditures but before consideration of federal income taxes. The discounted cash flow values included in this report are intended to represent the time value of money and should not be construed to represent an estimate of fair market value. We estimate the net reserves and future net cash flow to the Carrizo interest, as of December 31, 2012, to be:


### Net Reserves Future Net Cash Flow ($) Category Gas (Mcf) T

otal Present Worth

at 10% Proved Developed Producing 162,144,641 $ 179,088,078 $ 87,400,062 Non-Producing 6,461,328 $ 5,547,392 $ 2,077,371 Proved Undeveloped 134,863,641 $ 70,632,586 $ ( 7,600,174)
T otal Proved(1) 

### 303,469,610 $ 255,268,056 $ 81,877,259
(1) The total proved values above may or may not match those values on the total proved summary page and one line summaries that follow this letter due to rounding by the economics program. 

### Gas reserves are expressed in thousands of standard cubic feet (Mcf) at the contract temperature and pressure bases. The properties do not produce oil, condensate or NGL.
The estimated reserves and future cash flow shown in this report are for proved developed producing reserves and, for certain properties, proved developed non-producing and proved undeveloped reserves. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.LaRoche Petroleum Consultants, Ltd. 

### Estimates of reserves were prepared using standard geological and engineering methods generally accepted by the petroleum industry

. The reserves in this report have been estimated using deterministic methods. The method or combination of methods utilized in the evaluation of each reservoir included consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history

. Recovery from various reservoirs and leases was estimated after consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and reservoir and well performance. In some instances, comparisons were made to similar properties for which more complete data were available. We have used all methods and procedures that we considered necessary under the circumstances to prepare this report. We have excludedfrom our consideration all matters as towhich the controlling interpretation may be legal or accounting rather than engineering or geoscience.
The estimated reserves and future cash flow amounts in this report are related to hydrocarbon prices. Historical prices through December 2012 were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from the SEC prices. In addition, future changes in environmental and administrative regulations may significantly af

fect the ability of Carrizo to produce gas at the projected levels. Therefore, volumes of reserves actually recovered and amounts of cash flow actually received may dif fer significantly from the estimated quantities presented in this report.
Benchmark prices used in this report are based on the twelve-month un-weighted arithmetic average of the first day of the month price for the period January through December 2012. Gas prices are referenced to a W AHA physical price of $2.68 per MMBtu, as posted by Platts Daily Gas, and are adjusted for energy content, transportation fees, and regional price dif ferentials. The reference price is held constant in accordance with SEC guidelines. The weighted average price over the life of the properties is $1.899 per Mcf for gas.
Lease and well operating expenses are based on data obtained from Carrizo. Expenses for the properties operated by Carrizo include allocated overhead costs, direct lease and field level costs aswell as compression costs. Leases andwells operated by others include all direct expenses as well as general and administrative costs and overhead costs allowed under the specific joint operating agreements. Costs for all properties have been divided into fixed field operating costs and variable per-well costs. Lease and well operating costs are held constant in accordance with SEC guidelines. Capital costs and timing of all investments have been provided by Carrizo and are included as required for workovers, new development wells, and production equipment. Carrizo has represented to us that they have the ability and intent to implement their capital expenditure program as scheduled. Estimates ofthe cost to plug and abandon the wells net of salvage value are included and scheduled at the end ofthe economic life of individual properties. These costs are held constant.
Severance tax rates for all properties are calculated based on applicable State of T exas guidelines for High Cost Gas Exemption wells. Capital investments necessary to determine these severance tax rates have been provided by Carrizo.
LPC has made no investigation of possible gas volume and value imbalances that may have resulted from the overdelivery or underdelivery to the Carrizo interest. Our projections are based on the Carrizo interest receiving its net revenue interest share of estimated future gross gas production.LaRoche Petroleum Consultants, Ltd. 

### T echnical information necessary for the preparation of the reserve estimates herein was furnished by Carrizo or was obtained from state regulatory agencies and commercially available data sources. No special tests were obtained to assist in the preparation of this report. For the purpose of this report, the individual well test and production data as reported by the above sources were accepted as represented together with all other factual data presented by Carrizo including the extent and character of the interest evaluated.
An on-site inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined by LPC. In addition, the costs associated with the continued operation of uneconomic properties are not reflected in the cash flows.
The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this report. In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements. Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the projections presented herein.
The reserves included in this report are estimates only and should not be construed as exact quantities. They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. These estimates should be accepted with the understanding that future development, production history, changes in regulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations. A portion of these reserves are for behind-pipe zones, undeveloped locations, and producing wells that lack suf ficient production history to utilize performance-related reserve estimates. Therefore, these reserves are based on estimates of reservoir volumes and recovery ef

ficiencies alongwith analogiesto similar production. These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data. It may be necessary to revise these estimates up or down in the future as additional performance data become available. As in all aspects of gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions represent informed professional judgments only, not statements of fact.
The results of our third party study were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Carrizo.
Carrizo makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Carrizo has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Carrizo of the references to our name, together with the references to our third party report for Carrizo which appears in the December 31, 2012 annual report on Form 10-K and/or 10-K/A of Carrizo. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Carrizo.
We have provided Carrizo with a digital version of the original signed copy of this report letter

. In the event there are any dif ferences between the digital version included in filings made by Carrizo and the original signed report letter, the original signed report letter shall control and supersede the digital version.LaRoche Petroleum Consultants, Ltd. 

### The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating andAuditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. The technical person primarily responsible for overseeing the preparation of reserves estimates herein is William M. Kazmann. Mr

. Kazmann is a Professional Engineer licensed in the State of T exas who has thirty seven years of engineering experience in the oil and gas industry

. Mr

. Kazmann earned Bachelor of Science and Master of Science degrees in Petroleum Engineering from the University of T exas atAustin and has prepared reserves estimatesfor his employers and his own companiesthroughout his career

. He has prepared and overseen preparation of reports for public filings for LPC for the past sixteen years. LPC is an independent firm of petroleum engineers, geologists, and geophysicists and are not employed on a contingent basis. Data pertinent to this report are maintained on file in our of fice.

V ery truly yours, LaRoche Petroleum Consultants, Ltd. State of T

exas Registration Number F-1360

/s/ Al Iakovakis
Al Iakovakis Manager of Unconventional Resource Evaluations Senior Staf

f Engineer

/s/ William M. Kazmann
William M. Kazmann Licensed Professional Engineer State of T

exas No. 45012

AI:mk 12-918LaRoche Petroleum Consultants, Ltd. DEFINITION OF RESER VES 

### Adapted from United States Securities and Exchange Commission

Regulation S-X Rule 4-10(a) as Amended

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be recoverable, as of a given date, by application of development projects to known accumulations based on: analysis of geoscience and engineering data; the use of reliable technology; the legal right to produce; installed means of delivering the oil, gas, or related substances to markets, or the permits, financing, and the appropriate level of certainty (reasonable certainty, as likely as not, or possible but unlikely) to do so; and economic producibility at current prices and costs.
Proved reserves are those 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 the estimation. Existing economic conditions utilize current costs as ofthe ef fective date ofthe estimate and constant pricing utilizing the average price for the 12-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions

. Reasonable certainty is defined as having a high degree ofconfidencewhich means that the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geosciences (geological, geophysical and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is more likely to increase or remain constant than to decrease. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered and if probabilistic methods are used, there should be at least a 90% probability that quantities actually recovered will equal or exceed the estimate.
Reservoirs are considered proved if economic producibility is supported by actual production, a conclusive formation test, or other reliable technology

. The area of a reservoir considered proved includes (1) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (2) portions of the reservoir not yet drilled but which are reasonably certain to be economically producible on the basis of available geological and engineering data utilizing reliable technology

. In the absence of information and reliable technology to establish fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir

. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "prove" classification when support for the engineering analysis on which the project or program was based includes successful testing by a pilot project or the operation of an installed program in the reservoir or the use of techniques that have been proved ef

fective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty

. Proved developed oil and gas reserves are reserves, in projects that extract oil and gas through wells, that can be expected to be recovered through existing wells with existing equipment and operating methods; and, in projects that extract oil and gas in other ways, can be expected to be recovered through extraction technology installed and operational at the time of the reserves estimate. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms ofLaRoche Petroleum Consultants, Ltd.



### primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. Developed reserves are subcategorized as producing or non-producing

. Proved developed producing reserves are expected to be recovered from existing wells in completion intervals which are open and producing at the date of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Proved developed non-producing reserves include shut-in and behind-pipe reserves. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells which were shutinfor market conditions or pipeline connections, or (3)wells not capable of productionfor mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production.
Proved undeveloped oil and gas reserves are 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. Reserves on undrilled acreage shall be limited to those development spacing areas that are reasonably certain of economic producibility based on engineering, geosciences, and economic data and reliable technology, including actual drilling statistics in the area. Estimates for proved undeveloped reserves are not attributable to any acreage for which an application offluid injection or other improved recovery technique is contemplated unless supported by techniques that have been proved ef fective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty

. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, in sum with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will equal or exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there must be at least a 50% probability that the actual quantities recovered with equal or exceed the proved plus probable reserves estimates.
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable, and possible reserves. When probabilistic methods are used, there must be at least a 10% probability that the actual quantities recovered will equal or exceed the sum of proved, probable, and possible estimates.