UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Annual Report Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 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, Texas 77002

(Principal executive offices) (Zip Code)

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

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

Common Stock, $0.01 par value

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

YES 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) of the Securities 

Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), 

and (2) has been subject to such filing requirements for the past 90 days. YES NO 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every 

Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for 

such shorter period that the registrant was required to submit and post such files). YES NO 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will 

not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part 

III of this Form 10-K or any amendment to this Form 10-K. 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller 

reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of 

the Exchange Act. (Check one):

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 of the Act). YES NO 

At June 30, 2012, the aggregate market value of the registrant’s Common Stock held by non-affiliates 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 of the registrant’s Common Stock was 40,281,069.
DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement for the Registrant’s 2013 Annual Meeting of Shareholders are incorporated by reference 

in Part III of this Form 10-K. Such definitive proxy statement will be filed with the U.S. Securities and Exchange Commission not later 

than 120 days subsequent to December 31, 2012.
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TABLE OF CONTENTS

Forward-Looking Statements

PART I

Item 1. Business

Item 1A. Risk Factors

Item 1B. Unresolved Staff Comments

Item 2. Properties

Item 3. Legal Proceedings

Item 4. Mine Safety Disclosures

PART 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 of Financial 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 With Accountants on Accounting and Financial Disclosures

Item 9A. Controls and Procedures

Item 9B. Other Information

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Item 11. 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

PART IV

Item 15. Exhibits and Financial Statement Schedules

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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 of the Private Securities Litigation Reform Act 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 of the timing and number of wells we expect to drill and other exploration activities;

• our estimates regarding timing and levels of production;

• anticipated trends in our business;

• the effects 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.

You generally can identify our forward-looking statements by the words “anticipate,” “believe,” budgeted,” “continue,” 

“could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” 

“scheduled,” “should,” or other similar words. Such statements involve risks and uncertainties, including, but not limited to, those 

relating to the worldwide economic downturn, availability of financing, our dependence on our exploratory drilling activities, the 

volatility of and changes in oil and gas prices, the need to replace reserves depleted by production, operating risks of oil and gas 

operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business 

strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and 

impact of oil and gas reserve estimation and disclosure requirements, activities and approvals of our partners and parties with 

whom we have alliances, technological changes, capital requirements, borrowing base determinations and availability under our 

credit facilities, evaluations of us by lenders under our credit facilities, the potential impact of government regulations, including 

current and proposed legislation and regulations related to hydraulic fracturing, oil and natural gas drilling, air emissions and 

climate change, regulatory determinations, litigation, competition, the uncertainty of reserve information and future net revenue 

estimates, property acquisition risks, availability of equipment and crews, actions by our midstream and other industry partners, 

weather, availability of financing, actions by lenders, our ability to obtain permits and licenses, the results of audits and assessments, 

the failure to obtain certain bank and lease consents, the existence and resolution of title defects, new taxes and impact fees, delays, 

costs and difficulties relating to our joint ventures, actions by joint venture partners, results of exploration activities, the availability 

and completion of land acquisitions, completion and connection of wells, and other factors detailed in this annual report.

We have based our forward-looking statements on our management’s beliefs and assumptions based on information available 

to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and 

projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual 

results will not differ materially from those expressed or implied by our forward-looking statements.

Some of the factors that could cause actual results to differ from those expressed or implied in forward-looking statements 

are described under Part I, “Item 1A. Risk Factors” and in other sections of this annual report. Should one or more of these risks 

or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those 

indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly 

qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on our forward-looking 

statements. Each forward-looking statement speaks only as of the date of the particular statement, and, except as required by law, 

we undertake no duty to update or revise any forward-looking statement.

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

under Part I, “Item 1. Business.”
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PART 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 of oil 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 Texas, the Niobrara Formation in Colorado, the Marcellus Shale in Pennsylvania, 

the Barnett Shale in North Texas, and the Utica Shale in Ohio.

Since we began focusing a significant portion of our efforts in shale plays, particularly in the Barnett Shale in 2003 and 

Eagle Ford Shale in 2010, we have grown our reserves at a compounded annual growth rate (“CAGR”) of 30%, 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, and joint ventures in the Niobrara Formation, we added, net of production, 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 2011. 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 2011, respectively.

The following table provides details about the Company’s proved reserves as of the 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

Total U.S. 115.1 149.6

U.K. North Sea (discontinued operations) 6.0 6.3

Worldwide 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. We 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. We 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 of funding include proceeds from the possible selective sale of assets and offerings of securities.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

Total U.S. 624.0 695.8

U.K. North Sea (discontinued operations) — 46.4

Worldwide 624.0 742.2
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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, 2011. 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 of crude oil and liquids to our proved reserves (21.5 MMBoe including associated gas) during 2012, which 

was partially offset by the sale of an aggregate 40% of substantially all of our interest in oil and gas properties in the Niobrara 

formation to new joint venture partners (0.4 MMBoe of crude oil and liquids reserves as of December 31, 2011). See also “Niobrara 

Formation—OIL Joint Venture” and “—Haimo Joint Venture” below.

Eagle Ford 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 Texas. 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 of the Eagle Ford Shale. As of December 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. We operated all of these wells mentioned. During 2012, we drilled 59 gross (46.7 net) 

wells, all of which 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 2011 production of 644.0 MBoe (1,764.0 Boe/d). Total proved reserves for the Eagle Ford Shale were 49.0 MMBoe at 

December 31, 2012, approximately 85%, or 41.7 MMBoe, of which was crude oil (36.5 MMBbls) and liquids (5.2 MMBoe).

As of December 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. We currently expect our 2013 Eagle Ford Shale development efforts 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 Venture. In September 2011, 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 new joint venture with respect 

to the interests purchased by GAIL. Under the terms of the agreement, we generally retained a 80% working interest in the acreage 

and GAIL purchased a 20% working interest. We 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. We serve as operator of the properties covered by this 

joint venture. As of December 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 Weld and Adams counties, Colorado. During 2012, we 

drilled 26 gross wells (9.1 net), of which we operated 23 gross wells (8.9 net), and completed and brought on production 23 gross 

wells (8.0 net). As of December 31, 2012, we held interests in approximately 112,946 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. Of these 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 2011 production of 154.3 MBoe (422.7 Boe/d). Total proved reserves for the Niobrara were 

2.0 MMBoe at December 31, 2012, approximately 85%, or 1.7 MMBoe, of which was crude oil and liquids. 

OIL Joint Venture. 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’
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development carry is to be paid to us at the end of the development carry period. The Niobrara Formation assets conveyed to the 

OIL JV Partners under the terms of the agreement are located primarily in Weld 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. We also granted an option in favor of the OIL JV Partners to purchase a 30% share of 

acreage acquired by us after the effective 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.

Haimo Joint Venture. In December 2012, we completed the sale of an additional portion of our remaining interests in the same 

oil and gas properties sold to the OILJV Partners in the transaction described above to Haimo Oil & Gas LLC (“Haimo”), a wholly 

owned subsidiary of Lanzhou Haimo Technologies 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. We also granted an option in favor of Haimo to purchase a 10% share of acreage 

acquired by us after the effective date of the transaction in specified areas of the play, which areas are the same as the OIL joint 

venture described above. This option is exercisable at our cost plus a specified premium, and is subject to specified exceptions.

In 2013, we currently expect to invest approximately $35.0 million in drilling and completion costs for the Niobrara Formation, 

net of carry.

Utica Shale

In 2011, we commenced acquiring acreage in the Utica Shale located in eastern Ohio and northwestern Pennsylvania. Our 

activities in the Utica Shale are currently conducted through a joint venture described below.

Avista Utica Joint Venture. Effective September 2011, our wholly owned subsidiary, Carrizo (Utica) LLC, entered into a 

joint venture with ACP II Marcellus LLC (“ACP II”), which is also one of our joint venture partners in the Marcellus Shale, and 

ACPIII Utica LLC (“ACPIII”), both affiliates of Avista Capital Holdings, LP, a private equity firm (collectively with ACPII and 

ACP III, “Avista”). As of December 31, 2012, our Avista 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 of this joint venture, we and Avista have the right to contribute cash and properties to acquire and develop 

acreage in the Utica Shale play. The joint venture agreements established an area of mutual interest between us and Avista and 

provided us options on specified categories of properties to increase our participating interest in such properties to equal Avista’s. 

Under the joint venture agreements, we serve as operator of the Utica joint venture properties and have agreed to provide certain 

management services to Avista related to the Utica joint venture. Avista or its designee has the right to become a co-operator of 

the joint venture properties if (i) Avista sells substantially all of its interests in the Utica joint venture properties or (ii) we default 

under the terms of any pledge of our interest in the Utica joint venture properties. 

In October 2012, we sold substantially all of our interests in oil and gas properties dedicated to the Avista Utica joint 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 of this Utica Shale transaction, Avista sold substantially all of its 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% of the properties subject to the sale rather than the 10% we 

initially held. Pursuant to the terms of the Avista 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 Avista Utica joint venture properties. Concurrently with the 

exercise and closing of our option to increase our participating interest in such oil and gas properties, our right to receive distributions 

associated with properties owned by ACP II in the Avista Utica joint venture through our “B Units” interest in ACP II described 

below under “Natural Gas Plays—Avista Marcellus Joint Venture,” was terminated.

Following the sale transactions described above, on October 24, 2012, we and Avista amended the Utica Shale joint venture 

agreements to provide that the expiration date of our remaining option to increase our participating interest in the Avista Utica 

joint venture properties was accelerated from March 2013 to January 15, 2013. We exercised this option on January 15, 2013 by 

paying $63.1 million for an additional 40% interest in approximately 11,000 acres pursuant to the terms of the Avista Utica joint 

venture agreement. We and Avista also agreed that after the option was exercised, our participating interest in subsequently acquired 
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properties within the area of mutual interest continued to be 10% and Avista’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 Avista’s contribution of purchase proceeds). This additional 

option will expire May 31, 2013. In connection with the January 2013 exercise of our option to increase our participating interest 

in the Avista Utica joint venture properties, our right to receive distributions associated with properties owned by ACPIII through 

our “B Units” interest in ACP III that we acquired at the formation of the Utica joint 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 of the following events, at which time the area of mutual 

interest will only continue to apply to those areas where the joint venture is active: (i) September 1, 2014, (ii) ACPIII’s investment 

reaches $170.0 million and Avista 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 of ACP II or ACP III (or either’s designee) as a co-operator of the applicable properties in 

connection with a default by us under the terms of any pledge of our interest in the Utica joint venture properties, (v) the sale by 

Avista of substantially all of its interest in the Utica joint venture properties or (vi) termination of the ACPIII management services 

agreement. 

Each party’s ability to transfer its interest in the Utica joint venture to third parties is generally subject to “tag along” rights. 

Avista’s tag along rights do not apply upon a change of control of the Company. 

Steven A. Webster, Chairman of our Board of Directors, serves as Co-Managing Partner and President of Avista Capital 

Holdings, LP, which entity has the ability to control Avista and its affiliates. ACPII’s and ACPIII’s Boards of Managers have the 

sole authority for determining whether, when and to what extent any cash distributions will be declared and paid to members of 

ACP II or ACP III, respectively. Mr. Webster is not a member of either entity’s Board of Managers. As previously disclosed, we 

have been a party to prior arrangements with affiliates of Avista Capital Holdings LP, including in respect of our existing joint 

venture with Avista in the Marcellus Shale. The terms of the joint ventures with Avista in the Utica Shale and the Marcellus Shale 

were approved by a special committee of the Company’s disinterested directors. See also “Natural Gas Plays—Avista Marcellus 

Joint Venture” and “Note 11. Related Party Transactions” of the Notes to our Consolidated Financial Statements.

U.K. North Sea

We used a low cost entry business model in the U.K. North Sea that allowed us to acquire prospective acreage without making 

any initial capital commitments. This strategy led directly to the acquisition of our interest in the Huntington Field discovery 

located primarily on block 22/14b, where 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 $116.5 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. We classified our U.K. North Sea assets and liabilities as held for sale in the consolidated balance 

sheets along with the related results of operations and cash flows as discontinued operations, net of income taxes, in the consolidated 

statements of income and cash flows. 

The Carrizo UK senior secured multicurrency credit facility agreement that was secured by substantially all of Carrizo 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 of the development costs associated with the Huntington Field development project through a term loan facility, 

a cost overrun facility and a letter of credit facility. 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.

As of February 25, 2013, we held interests in four other licenses in the U.K. North Sea. We currently have satisfied or believe 

that we can satisfy all remaining committed work obligations on these four licenses at no material additional cost to 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, 2011. 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 2011. The decrease in natural gas proved reserves and 

natural gas production was primarily related to the sale of a substantial portion of our Barnett Shale properties in the second quarter 

of 2012. See “Barnett Shale” below for additional information.
8

Marcellus Shale

We began active participation in the Marcellus Shale in 2007. We believe that we have leveraged the knowledge and experience 

that we gained in the Barnett Shale to effectively explore for and develop natural gas in the Marcellus Shale. Our activities in the 

Marcellus Shale are currently conducted through two joint ventures described below.

As of December 31, 2012, we owned interests in 223,899 gross (80,505 net) acres in the Marcellus Shale, principally in 

Pennsylvania, New York and West Virginia. 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. We commenced producing from our first 

operated Marcellus well in late October 2011 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. Total proved reserves for the Marcellus Shale were 74.8 Bcfe at December 31, 2012, all of which 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 Wyoming counties. As a result 

of the material decline in natural gas prices, we and our joint venture partners are carefully reviewing our development program 

and have reduced our planned spending in the Marcellus shale during 2013. We will continue to monitor prices and, consistent 

with our existing contractual commitments, may decrease our activity level and capital expenditures further, or may increase such 

activity, if natural gas prices so warrant. We are currently operating one rig capable of drilling horizontal wells in the Marcellus 

Shale.

Avista Marcellus Joint Venture. Effective as of August 2008, our wholly owned subsidiary, Carrizo (Marcellus) LLC, entered 

into a joint venture with ACPII, an affiliate of Avista with which we also have a joint venture in the Utica Shale. See also “Crude 

Oil and Liquids Plays—Avista Utica Joint Venture” and “Note 11. Related Party Transactions” of the Notes to our Consolidated 

Financial Statements.

We serve as operator of the properties covered by this joint venture and also perform specified management services for 

ACPII. An operating committee composed of one representative of each party provides overall supervision and direction of joint 

operations. Avista or its designee has the right to become a co-operator of the Avista Marcellus joint venture properties if all of its 

membership interests or substantially all of its assets are sold to an unaffiliated third party or if we default under the terms of any 

pledge of our interest in the Avista Marcellus joint venture properties. The joint venture agreements provide for an area of mutual 

interest applicable to specified halos in which the joint venture is active.

Subject to specified exceptions (including the Reliance transactions described below), net cash flow from hydrocarbon 

production from the Avista Marcellus joint venture properties and related sales proceeds, if such properties are sold, will be allocated 

(a) 75% to Avista and 25% to us until Avista has recovered the remainder of its investment, (b) thereafter, 100% to us until we 

recover an equal amount and (c) thereafter in accordance with the parties’ participating interests, which are currently 50/50. We 

have also agreed to jointly market Avista’s share of the production from the Marcellus joint venture properties with our own until 

the cash flows and sale proceeds are allocated in accordance with the parties’ participating interests under this joint operating 

agreement. 

In connection with the formation of ACPII, we were issued “B Units” in ACPII. 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 by ACPII in the Avista Utica joint venture through our “B Units” interest 

in ACP II was terminated. See “Crude Oil and Liquids Plays—Avista Utica Joint Venture” above for more information. 

Each party’s ability to transfer its interest in the Marcellus joint venture properties to third parties is subject in most instances 

to preferential purchase rights for transfers of less than 10% of its interest in such joint venture properties or to “tag along” rights 

for most other transfers.

As part of the closing of the transactions with Reliance, we and Avista amended our then-existing joint venture agreements 

to provide that the properties that we and Avista sold to Reliance, as well as the properties we committed to the joint venture with 

Reliance, are not subject to the terms of our Avista Marcellus joint venture, and that the area of mutual interest of our Avista 

Marcellus joint venture will generally not include Pennsylvania, in which those properties are located. Our Avista Marcellus joint 

venture will otherwise continue and, as of December 31, 2012, included approximately 71,774 net acres, primarily in West Virginia 

and New York. 

Reliance Joint Venture. In September 2010, we completed the sale of 20% of our interests in substantially all of our oil and 

gas properties in Pennsylvania that had been subject to the Avista Marcellus joint venture to Reliance Marcellus II, LLC 
9

(“Reliance”), a wholly owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited, for $13.1 

million in cash and a commitment by Reliance to pay 75% of certain of our future drilling and completion costs up to approximately 

$52.0 million. As of December 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 Avista. The Carrizo/Reliance joint venture agreement included 

approximately 103,232 net acres in northern and central Pennsylvania as of December 31, 2012. 

We have agreed to various restrictions on our ability to transfer our properties covered by the Reliance joint venture. 

Additionally, since the expiration of the Reliance development carry, we are subject to a mutual right of first offer on direct and 

indirect property transfers for the remainder of a ten-year development period (through September 2020), subject to specified 

exceptions. We have also granted an option in favor of Reliance to purchase a 60% (as adjusted over time) share of acreage 

purchased directly or indirectly by us after the closing. This option, which covers substantially all of Pennsylvania, is exercisable 

at our cost plus, in the case of direct property sales, a specified premium, and is subject to specified exceptions. We serve as 

operator of the properties covered by the Reliance joint venture, with Reliance having the right to assume operatorship of 60% of 

undeveloped acreage in portions of central Pennsylvania and until September 2014 to purchase all of our 40% interest in such 

acreage at a specified price. Operations under the Reliance joint venture will generally be required to conform to a budget approved 

by an operating committee that includes representatives of both parties, subject to exceptions, including those for sole risk operations 

and in the event of defaults by the parties. The parties have also generally agreed to certain restrictions regarding sole risk operations 

and other operations.

Barnett Shale

We have been operating in the Barnett Shale since 2003. As of December 31, 2012, we held interests in approximately 11,788

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 11,788 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 2011 production of 35.7 Bcfe, primarily related to the sale of a substantial 

portion of our Barnett Shale properties in the second quarter of 2012. Total proved reserves for the Barnett Shale were 303.5 Bcfe 

at December 31, 2012 all of which was natural gas.

As of December 31, 2012, we were not operating any drilling rigs in the Barnett Shale. We completed the hydraulic fracturing 

of one 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 affiliate of Atlas 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

Measured Growth Through the Drillbit

Our objective is to increase value through the execution of a business strategy focused on organic growth through the drillbit. 

Key elements of our business strategy include:

• Grow Primarily Through Drilling.We pursue a technology-driven exploration drilling program. We generate exploration 

prospects through geological and geophysical analysis of 3-D seismic and other data. Our ability to successfully define 

and drill exploratory prospects is demonstrated by our 99% apparent drilling success rate in the Barnett Shale, Eagle 

Ford Shale, Marcellus Shale and Niobrara Formation areas since our entrance into such plays. We 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 attract joint venture 

partners in our existing acreage in the Eagle Ford, Marcellus and Utica Shales and the Niobrara Formation.

• Pursue Growth in Crude Oil and Liquids-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 of total 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 our 
10

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.

• Control Operating and Capital Costs. We emphasize efficiencies to lower our costs to find, develop and produce our 

oil and gas reserves. This includes concentrating on our core areas, which allows us to optimize drilling and completion 

techniques as well as benefit from economies of scale. In addition, as we operate a significant percentage of our properties, 

the majority of our capital expenditure plan is discretionary allowing us the ability to reduce or reallocate our spending 

in response to changes in market conditions. For example, our discretionary capital spending has been strategically 

redeployed to pursue growth in crude oil and liquids-rich plays.

• Maintain Our Financial Flexibility.We are committed to preserving our financial flexibility. We have historically funded 

our capital program with a combination of cash generated from operations, proceeds from the sale of assets, proceeds 

from sales of securities, proceeds, payments or carried interest from our joint ventures and borrowings under our senior 

secured revolving credit facility.

• Utilize Our Experience as a Technical Advantage. We believe we have developed a technical advantage from our 

extensive experience drilling over 450 horizontal wells in the Barnett, Eagle Ford and Marcellus Shales and the Niobrara 

Formation, which has allowed our management, technical staff and field operations teams to gain significant experience 

in resource plays. We are now leveraging this advantage in our existing and other shale trends, including the Utica Shale. 

We plan to focus substantially all of our capital expenditures in these core areas, where we have acquired, or are acquiring 

significant acreage positions and a large prospect inventory.

• Maintain a Conservative Exploration and Development Portfolio.We continue to focus our exploration effort 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 Exposure. We 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. Our joint ventures with Reliance in most of Pennsylvania, with 

GAILin the Eagle Ford Shale and with the OILJVPartners and Haimo in the Niobrara Formation are prominent examples 

of this strategy. We also attempt to limit our exposure to reductions in commodity prices by actively hedging production 

of both 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

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

strategy:

• Large inventory of oil-focused drilling locations. We have developed a significant inventory of future drilling locations, 

primarily in our well-established position in LaSalle and McMullen counties in the Eagle Ford Shale and Weld and 

Adams counties in the Niobrara Formation. As of December 31, 2012, we owned leases covering approximately 208,545

gross acres in our focus areas of the Eagle Ford Shale and the Niobrara Formation. At December 31, 2012, we also had 

a substantial inventory of already 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. 

proved reserves at December 31, 2012 were undeveloped. In 2012, our crude oil revenue as a percentage of total revenues 

was 78%.

• Successful drilling history. We 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 efforts.

• Experienced management and professional workforce. We employ 54 oil and gas professionals, including geophysicists, 

petrophysicists, geologists, petroleum engineers and production and reservoir engineers and technical support staff, who 

have an average of over 19 years of experience. We believe our experience and expertise, particularly as they relate to 

successfully identifying and developing resource plays, is a competitive advantage.

• Operational control.As of December 31, 2012, we operated approximately 81% of the wells in which we held 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 of known or emerging pipeline infrastructures. A component of our 
11

exploitation strategy is to first identify and acquire surface tracts or “well pads” from which multiple wells can be drilled. We then 

seek to acquire contiguous lease blocks in the areas immediately adjacent to these well pads that can be developed quickly. We 

next acquire 3-D seismic data over these leases to assist in well placement and development optimization. Even in the relatively 

lower-risk, reserve-proven trends, such as the 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 into joint ventures with well-funded partners that will pay a disproportionate share of the drilling and completion 

costs of wells that we drill. For example, in 2012, we sold 30% of our interests in certain of our Niobrara Formation properties to 

the OILJVPartners, with the OILJVPartners agreeing to pay 50% of certain of our drilling and completion costs up to approximately 

$41.25 million, which we currently expect to fully utilize or receive by the end of the first quarter of 2014. In 2011, we sold 20% 

of our interests in certain of our Eagle Ford Shale properties to GAIL who agreed to pay 50% of certain of our drilling and 

completion costs up to approximately $31.3 million, which was fully utilized in 2012. In 2010, we sold 20% of our interests in 

our Pennsylvania properties to Reliance who agreed to pay 75% of certain of our drilling and completion costs up to approximately 

$52.0 million, which was fully utilized by the end of the fourth quarter of 2012. 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.

We strive to achieve a balance between acquiring acreage, seismic data (2-D and 3-D) and timely project evaluation through 

the drillbit to ensure that we minimize the costs to test for commercial reserves while building a significant acreage position. Our 

first exploration wells in these trends are frequently vertical wells, or a limited number of horizontal wells, because they allow us 

to evaluate thermal maturity and rock property data, while also permitting us to test various completion techniques without incurring 

the cost of drilling a substantial number of horizontal wells. As discussed above, we have also shifted our focus toward crude oil 

and liquids-rich plays to take advantage of the attractive economics associated with those commodities.

We maintain a flexible and diversified approach to project identification by focusing on the estimated financial results of a 

project area rather than limiting our focus to any one method or source for obtaining leads for new project areas. Additionally, we 

monitor competitor activity and review outside prospect generation by small, independent “prospect generators.” We complement 

our exploratory drilling portfolio through the use of these outside sources of project generation and typically retain operator rights. 

Specific drill-sites are typically chosen by our own geoscientists or, in highly populated or environmentally sensitive areas, are 

dictated by available leases.

Operating Approach

Our management team has extensive experience in the development and management of exploration and development projects 

in the Barnett Shale, onshore Gulf Coast and, more recently, the Marcellus Shale, Eagle Ford Shale and Niobrara Formation. We 

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 of our management in the development, processing 

and analysis of 3-D projects and data will play a significant part in our future success.

We generally seek to obtain lease operator status and control over field operations, and in particular seek to control decisions 

regarding 3-D survey design parameters and drilling and completion methods. As of December 31, 2012, we operated 300 gross 

(218.4 net) producing oil and gas wells. We generally seek to control operations for most new exploration and development taking 

advantage of our technical staff experience in horizontal drilling and hydraulic fracturing. During 2012, we operated all 59 of the 

gross wells drilled in the Eagle Ford Shale, 38 of the 39 gross wells drilled in the Marcellus Shale, 23 of the 26 gross wells drilled 

in the Niobrara, and 1 of the 6 gross wells drilled in the Barnett Shale.

Working Interest and Drilling in Project Areas

The actual working interest we will ultimately own in a well will vary based upon several factors, including the depth, cost 

and risk of each well relative to our strategic goals, activity levels and capital availability. From time to time some fraction of 

these wells may be sold to industry partners either on a prospect by prospect basis or a program basis. In addition, we may also 

contribute acreage to larger drilling units thereby reducing prospect working interest. We have, in the past, retained less than 100% 

working interest in our drilling prospects. References to our interests are not intended to imply that we have or will maintain any 

particular level of working interest.
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. and Ryder Scott Company Petroleum Engineers. For further information concerning these 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 of the first day of the 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)” 

of the Notes to our Consolidated Financial Statements.

Summary of Proved Oil and Gas Reserves as of December 31, 2012

Based on Average 2012 Prices

(Dollars in thousands)

Oil, Condensate

and Natural Gas

Liquids (MBoe)

Natural Gas

(MMcf)

Total

(MBoe) (1)

PV-10

Value (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

Worldwide

Developed 19,536 234,203 58,570 1,181,077

Undeveloped 30,163 194,134 62,519 672,813

Total Proved 49,699 428,337 121,089 $ 1,853,890

(1) Barrel of oil equivalents are determined using the ratio of 6 Mcf of natural gas to 1 Bbl of crude oil or 1 Boe of natural gas liquids which 

represents their approximate energy content. Despite holding this ratio constant at six Mcf to 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 of December 31, 2012 is pre-tax and was determined by using the average of oil and gas prices at the beginning of each 

month in the twelve-month period prior to December 31, 2012, which averaged $101.35 per Bbl of oil, $32.12 per Bbl of natural gas liquids 

and $1.95 per Mcf of natural gas in the United States and $111.21 per Bbl of oil and $13.32 per Mcf of natural 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 of the 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 of future income taxes to be paid, the use of the 

pre-tax measure provides greater comparability when evaluating companies. It is relevant and useful to investors for evaluating the relative 

monetary significance of our oil and gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size 

and value of our reserves to other oil and gas companies. Management also uses this pre-tax measure when assessing the potential return 

on investment related to its oil and gas properties and in evaluating acquisitions. The PV-10 value is not a measure of financial or operating 

performance under U.S. GAAP, nor is it intended to represent the current market value of the estimated oil and gas reserves owned by us. 

PV-10 value should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as 

defined under 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 of Total Proved Reserves (or standardized measure of discounted future net cash flows) is $1,418.4 

million.
13

Proved Undeveloped Reserves

United States. At December 31, 2012 and 2011, 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 of drilling and additional offset locations in the Marcellus Shale, Eagle Ford Shale and Niobrara 

Formation, respectively, (b) converted a net of 9.5 MMBoe of reserves from proved undeveloped to proved developed, primarily 

in the Eagle Ford Shale and Marcellus Shale and (c) sold 22.6 MMBoe of proved undeveloped reserves in the Barnett Shale.

Costs incurred relating to the development of proved undeveloped reserves were approximately $227.0 million in 2012, as 

compared to $57.0 million in 2011. 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 of reserves 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 2011. As a result of the 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 of proved reserves comparable to those included herein have been included in reports to any 

federal agency other than the Securities and Exchange Commission (“SEC”). The reserves data set forth in this Annual Report on 

Form 10-K represents only estimates. See “Item 1A. Risk Factors — Our reserve data and estimated discounted future net cash 

flows are estimates based on assumptions that may be inaccurate and are based on existing economic and operating conditions 

that may change in the future.” 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. Risk Factors—We depend on successful exploration, development and acquisitions to maintain reserves and revenue 

in the future.” Also, the failure of an operator of our wells to adequately perform operations, or such operator’s breach of the 

applicable agreements, could adversely impact us. See “Item 1A. Risk Factors—We cannot control the activities on properties we 

do not operate and are unable to ensure their proper operation and profitability.”

In accordance with SEC regulations, LaRoche Petroleum Consultants, Ltd., Ryder Scott Company Petroleum Engineers and 

our internal reserve engineers each used the price based on the unweighted average of oil and gas prices at the beginning of each 

month in the twelve-month period ended December 31, 2012, adjusted for basis and quality differentials. The prices used in 

calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect market prices for oil and gas 

production subsequent to December 31, 2012. There can be no assurance that all of the proved reserves will be produced and sold 

within the periods indicated, that the assumed prices will actually be realized for such production or that existing contracts will 

be honored or judicially enforced.

LaRoche Petroleum Consultants, Ltd. determined 50.6 MMBoe, or 42% of our proved reserves (all of which were located 

in the Barnett Shale), for the year ended December 31, 2012. Ryder Scott Company Petroleum Engineers determined 69.5 MMBoe, 

or 57% of our proved reserves, for the year ended December 31, 2012. 

Qualifications of Third Party Engineers

As discussed above, we engaged LaRoche Petroleum Consultants, Ltd. and Ryder 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 of Petroleum Engineers. None of these firms own an interest in our properties 

or is employed on a contingent fee basis.

Internal Controls

A significant component of our internal controls in our reserve estimation effort is our practice of using independent 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 of Third Party Engineers.”

Our internal reserve engineers are three individuals at the Company who are primarily responsible for reviewing the reserves 

estimates prepared by our third party engineering firms and for the portion of reserves estimates not prepared by third party 
14

engineers. Each of these individuals has over 26 years of experience in the petroleum industry and extensive experience in the 

estimation of reserves and the review of reserve reports prepared by third party engineering firms.

These three individuals along with other Company personnel, review the inputs and assumptions made in the reserve estimates 

prepared by the third party engineer firms and assess them for reasonableness. The reserve reports are also reviewed by senior 

management, including the Chief Executive Officer, who is a registered petroleum engineer and holds a B.S. in Mechanical 

Engineering from the University of Colorado, and the Chief Operating Officer, who holds a B.S. in Petroleum Engineering from 

Texas A&M University.

Oil and Gas Reserve Replacement

Finding and developing sufficient amounts of oil and gas reserves at economical costs are critical to our long-term success. 

Given the inherent decline of hydrocarbon reserves resulting from production, it is important for an exploration and production 

company to demonstrate a long-term trend of more than offsetting produced volumes with new reserves that will provide for future 

production. Management uses the reserve replacement ratio, as defined below, as an indicator of our ability to replenish annual 

production volumes and grow our reserves, thereby providing some information on the sources of future production. We believe 

reserve replacement information is frequently used by analysts, investors and others in the industry to evaluate the performance 

of companies like ours. The reserve replacement ratio is calculated by dividing the sum of reserve additions from all sources 

(revisions, extensions, discoveries, other additions, acquisitions and sales of reserves in place) by the actual production for the 

corresponding period. We do not use unproved reserve quantities in calculating our reserve replacement ratio. It should be noted 

that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because 

it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative 

value is also limited for the same reasons. In addition, since the ratio does not take into consideration the cost or timing of future 

production of new reserves, it cannot be used as a measure of value creation. The ratio does not distinguish between changes in 

reserve quantities that are producing and those that will require additional time and funding to begin producing. Our reserve 

replacement ratio may be calculated differently from the comparable measure of other oil and gas companies. It is relevant to note 

the percentage of our reserves that were producing in the United States was 45% in 2012, 41% in 2011 and 45% in 2010. Set forth 

below is our reserve replacement ratio for the years ended December 31, 2012, 2011 and 2010. We also present the reserve 

replacement ratio, as adjusted for U.S. property sales, primarily the sale of natural gas reserves to Atlas in 2012 and KKR in 2011. 

We 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%

Worldwide

Reserve replacement (269)% 311% 749%

Reserve replacement adjusted for property sales 301 % 631% 749%
15

Oil and Gas Volumes, Prices and Production Expense

The following table sets forth certain information regarding the production volumes of, average sales prices received for and 

average production costs associated with our sales of oil and gas for the periods indicated.

Year Ended December 31,

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

Total Natural gas and NGLs (MMcfe) 39,442 40,251 35,754

Total 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

Total barrels of oil equivalent per day (MBoe) 25,781 20,578 16,808

Average 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

Average 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 of production offices, and insurance and property.
16

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

Our finding and development costs ($ per Boe) as adjusted for property sales for the years ended December 31, 2012, 2011 

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

Total costs incurred (1) $ 725,024 $ 505,716 $ 325,253

Average all-sources finding cost $ 23.35 $ 9.62 $ 9.64

Average finding and development cost (2) 20.78 9.37 10.72

Average drilling finding cost 17.04 7.32 5.89

Worldwide

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

Total costs incurred (1) $ 772,420 $ 548,144 $ 331,434

Average all-sources finding cost $ 24.84 $ 10.47 $ 8.33

Average finding and development cost (2) 22.32 10.26 9.32

Average drilling finding cost 18.45 8.17 5.12

(1) Total costs incurred include capitalized overhead of $11.8 million, $9.6 million and $5.3 million and exclude capitalized interest on unproved 

properties of $24.8 million, $23.4 million and $20.7 million for the years ended December 31, 2012, 2011 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. Total exploration, development and acquisition activities for the three-year period ended 

December 31, 2012 have added approximately 115.6 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 undeveloped properties necessary to convert those properties into proved producing properties of $214.0 million, 

$531.3 million and $379.0 million at December 31, 2012, 2011 and 2010, respectively, and includes net additions to proved 

undeveloped reserves of 22.0 MMBoe, 14.4 MMBoe and 22.1 MMBoe for the years ended December 31, 2012, 2011 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, 2011 and 2010, respectively. Year 

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) of proved 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 efforts to crude oil and liquids-rich plays. Our finding and 

development costs exclude the effect 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 of factors including the extent and timing 

of new discoveries and property acquisitions. Due to the timing of proved reserve additions and timing of the related costs incurred 

to find and develop our reserves, our all-sources finding cost measure often includes quantities of reserves for which a majority 

of the costs of development have not yet been incurred. Conversely, the measure often includes costs to develop proved reserves 

that had been added in earlier years. Finding and development costs, as measured annually, may not be indicative of our ability 

to economically replace oil and gas reserves because the recognition of costs may not necessarily coincide with the addition of 

proved reserves. Our all-sources finding cost may also be calculated differently than the comparable measure of other oil and gas 

companies.

Drilling Activity

The following table sets forth our drilling activity for the years ended December 31, 2012, 2011 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 Wells - Productive 69 31.8 88 38.4 57 28.9

Exploratory Wells - Nonproductive 1 0.5 1 0.5 3 2.3

Development Wells - Productive 60 37.7 33 15.0 28 13.4

Development Wells - Nonproductive — — — — — —

U.K. North Sea (discontinued operations)

Exploratory Wells - Productive — — — — — —

Exploratory Wells - Nonproductive 1 0.2 — — — —

Development Wells - Productive 2 0.3 2 0.3 — —

Development Wells - Nonproductive — — — — — —

Worldwide

Exploratory Wells - Productive 69 31.8 88 38.4 57 28.9

Exploratory Wells - Nonproductive 2 0.7 1 0.5 3 2.3

Development Wells - Productive 62 38.0 35 15.3 28 13.4

Development Wells - Nonproductive — — — — — —

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

As of December 31, 2012, we are in the process of drilling 6 gross (4.7 net) wells in the United States that are not included 

in the table above. We have no current plans to drill a well outside of the United States in 2013.

Productive Wells

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

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

Total 300 218.4 72 9.5 372 227.9
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As of December 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 following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 

2012. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would permit production 

of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed 

to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves.

Developed Acreage Undeveloped Acreage Total

Gross Net Gross Net Gross Net

U.S.

Eagle Ford Shale - Texas 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 York 2,117 158 29,407 6,392 31,524 6,550

Pennsylvania 4,694 1,589 121,365 42,906 126,059 44,495

West Virginia 893 435 61,875 27,250 62,768 27,685

Virginia 53 27 3,495 1,748 3,548 1,775

Marcellus Shale Total 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

Total 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

Worldwide 74,064 46,374 699,208 314,454 773,272 360,828

(1) “Other” includes other non-resource plays in Texas and Louisiana; Utica Shale in Ohio and Pennsylvania; Fayetteville Shale in Arkansas; 

the New Albany Shale in Kentucky and Illinois; the Floyd/Neal Shale in Mississippi; the Barnett/Woodford in West Texas and New Mexico; 

and the Bakken in North Dakota.

Our lease agreements generally terminate if producing wells have not been drilled on the acreage within their primary term 

or an extension thereof (a period that can be from three to 10 years depending on the area). If no production is established on our 

leases that are in their primary term, approximately 30% of our acreage will expire in 2013, 6% will expire in 2014 and 32% will 

expire in 2015.

Marketing

Our production is marketed to third parties consistent with industry practices. Typically, our oil and gas is sold at the wellhead 

to unaffiliated third parties. Oil is sold at field-posted prices plus 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 WAHA, Houston Ship Channel, 

Dominion Transmission 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 of natural gas and prevailing supply and demand conditions. We have made the strategic decision to sell as much of our 

natural gas production at the wellhead as possible, so that we can concentrate our efforts and resources on exploration and production 

which we believe are more consistent with our competitive expertise, rather than in natural gas pipeline operation, natural gas 

marketing and sales. In each case we sell at competitive market prices based on a differential to several sales points. We do not 

believe the loss of any one of our purchasers would materially affect our ability to sell the oil and gas we produce. We believe 

other purchasers are available in all our areas of operations.

Our marketing objective is to receive competitive wellhead prices for our product. We are aided by the presence of multiple 

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 affect the market for oil and gas generally, including:
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• demand for oil and gas;

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

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

• the marketing of competitive fuels; and

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

See “Item 1A. Risk Factors—Oil and gas prices are highly volatile, and lower oil and gas prices will negatively affect our 

financial position, planned capital expenditures and results of operations,” “—We 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 “—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.”

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. We 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 

Discussion and Analysis of Financial Condition and Results of Operations —Summary of Critical Accounting Policies —Derivative 

Instruments,” “Item 7A. Qualitative and Quantitative Disclosures About Market Risk—Commodity Risk,” and “Item 1A. Risk 

Factors — We may continue to enter into derivative transactions to manage the price risks associated with our production, 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 affected by pipeline and 

gathering system capacity constraints.”

Competition and Technological Changes

We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of 

exploratory prospects and proven properties. Many of our competitors are large, well-established companies that have been engaged 

in the oil and gas business for much longer than we have and possess substantially larger operating staffs and greater capital 

resources than we do. We may not be able to conduct our operations, evaluate and select suitable properties and consummate 

transactions successfully in this highly competitive environment.

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new 

products and services using new technologies. If one or more of the technologies we use now or in the future were to become 

obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition and 

results of operations could be materially adversely affected.

Regulation

Oil and gas operations are subject to various federal, state, local and international environmental regulations that may change 

from time to time, including regulations governing oil and gas production and transportation, federal and state regulations governing 

environmental quality and pollution control and state limits on allowable rates of production by well or proration unit. These 

regulations may affect the amount of oil and gas available for sale, the availability of adequate pipeline and other regulated 

transportation and processing facilities and the marketing of competitive fuels. For example, a productive natural gas well may 

be “shut-in” because of an oversupply of natural gas or lack of an available natural gas pipeline in the areas in which we may 

conduct operations. State and federal regulations generally are intended to prevent waste of oil and gas, protect rights to produce 

oil and gas between owners in a common reservoir, control the amount of oil and gas produced by assigning allowable rates of 

production, provide nondiscriminatory access to common carrier pipelines and control contamination of the environment. Pipelines 

are subject to the jurisdiction of various federal, state and local agencies. We are also subject to changing and extensive tax laws, 

the effects of which cannot be predicted.

The following discussion summarizes the regulation of the United States oil and gas industry. We believe we are in substantial 

compliance with the various statutes, rules, regulations and governmental orders to which our operations may be subject, although 

we cannot assure you that this is or will remain the case. Moreover, those statutes, rules, regulations and government orders may 

be changed or reinterpreted from time to time in response to economic or political conditions, and any such changes or 

reinterpretations could materially adversely affect our results of operations and financial condition. The following discussion is 
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not intended to constitute a complete discussion of the various statutes, rules, regulations and governmental orders to which our 

operations may be subject.

Regulation of Natural Gas and Oil Exploration and Production

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

• require permits for the drilling of wells;

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

regulate the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon 

which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations.

Our operations are also subject to various conservation laws and regulations. These regulations govern the size of drilling 

and spacing units or proration units, the density of wells that may be drilled in 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 Texas) rely primarily or exclusively on voluntary pooling of lands and leases. 

In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore more difficult to 

develop a project if the operator owns less than 100% of the leasehold. In addition, state conservation laws establish maximum 

rates of production from oil and gas wells generally prohibit the venting or flaring of natural gas and impose specified requirements 

regarding the ratability of production. The effect of these regulations may limit the amount of oil and gas we can produce from 

our wells and may limit the number of wells or the locations at which we can drill. The regulatory burden on the oil and gas 

industry increases our costs of doing business and, consequently, affects our profitability. Because these laws and regulations are 

frequently expanded, amended and reinterpreted, we are unable to predict the future cost or impact of complying with such 

regulations.

Regulation of Sales and Transportation of Natural Gas

Federal legislation and regulatory controls have historically affected the price of natural gas we produce and the manner in 

which our production is transported and marketed. Under the Natural Gas Act of 1938 (“NGA”), the Federal Energy Regulatory 

Commission (“FERC”) regulates the interstate transportation and the sale in interstate commerce for resale of natural gas. Effective 

January 1, 1993, the Natural Gas Wellhead Decontrol Act (the “Decontrol Act”) deregulated natural gas prices for all “first sales” 

of natural gas, including all of our sales of our own production. As a result, all of our domestically produced natural gas is sold at 

market prices, subject to the terms of any private contracts that may be in effect. The FERC’s jurisdiction over interstate natural 

gas transportation, however, was not affected by the Decontrol Act.

Under the NGA, facilities used in the production or gathering of natural gas are exempt from the FERC’s jurisdiction. We 

own certain natural gas pipelines that we believe satisfy the FERC’s criteria for establishing that these are all gathering facilities 

not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, 

environmental, and in some circumstances, nondiscriminatory take requirements but does not generally entail rate regulation. 

Some of the delay in bringing our natural gas to market has been the lack of available pipeline systems in the Barnett Shale, 

particularly those that would take natural gas production from the lease to existing infrastructure. In order to partly alleviate this 

issue, commencing in 2009, certain of our wholly owned subsidiaries have constructed non-jurisdictional gathering facilities in 

cases where we have determined that we can construct those facilities more quickly or more efficiently than waiting on an unrelated 

third-party pipeline company.

One of our pipeline subsidiaries, Hondo Pipeline Inc., exercises the power of eminent domain and transports gas for third 

parties and is a regulated public utility within the meaning of Section 101.003 (“GURA”) and Section 121.001 (the “Cox Act”) 

of the Texas Utilities Code. Both GURA and the Cox Act prohibit unreasonable discrimination in the transportation of natural gas 

and authorize the Texas Railroad Commission to regulate gas transportation rates. However, GURA provides for negotiated rates 

with transportation, industrial or similar large-volume contract customers so long as neither party has an unfair negotiating 

advantage, the negotiated rate is substantially the same as that negotiated with at least two other customers under similar conditions, 

or sufficient competition existed when the rate was negotiated.

Although we do not own or operate any pipelines or facilities that are directly regulated by the FERC, its regulations of thirdparty pipelines and facilities could indirectly affect our ability to market our production. Beginning in the 1980s the FERC initiated 

a series of major restructuring orders that required pipelines, among other things, to perform open access transportation, “unbundle” 

their sales and transportation functions, and allow shippers to release their pipeline capacity to other shippers. As a result of these 

changes, sellers and buyers of natural gas have gained direct access to the particular pipeline services they need and are better 

able to conduct business with a larger number of counterparties. We believe these changes generally have improved our access to 

markets while, at the same time, substantially increasing competition in the natural gas marketplace. It remains to be seen, however, 

what effect the FERC’s other activities will have on access to markets, the fostering of competition and the cost of doing business. 
21

We cannot predict what new or different regulations the FERC and other regulatory agencies may adopt, or what effect subsequent 

regulations may have on our activities.

In the past, Congress has been very active in the area of natural gas regulation. However, the more recent trend has been in 

favor of deregulation or “lighter handed” regulation and the promotion of competition in the gas industry. In light of this increased 

reliance on competition, the Energy Policy Act of 2005 amended the NGA to prohibit any forms of market manipulation in 

connection with the transportation, purchase or sale of natural gas. In addition to the regulations implementing these prohibitions, 

the FERC has established new regulations that are intended to increase natural gas pricing transparency through, among other 

things, expanded dissemination of information about the availability and prices of gas sold and new regulations that require both 

interstate pipelines and certain non-interstate pipelines to post daily information regarding their design capacity and daily scheduled 

flow volumes at certain points on their systems. The Energy Policy Act of 2005 also significantly increased the penalties for 

violations of the NGA and the FERC’s regulations to up to $1.0 million per day for each violation.

Oil Price Controls and Transportation Rates

Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. The 

price we receive from the sale of these products may be affected by the cost of transporting the products to market. Much of that 

transportation is through interstate common carrier pipelines. Effective as of January 1, 1995, the FERC implemented regulations 

generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those rates 

by which adjustments are made annually based on the rate of inflation, subject to specified conditions and limitations. These 

regulations may tend to increase the cost of transporting crude oil and natural gas liquids by interstate pipeline, although the annual 

adjustments may result in decreased rates in a given year. Every five years, the FERC must examine the relationship between the 

annual change in the applicable index and the actual cost changes experienced in the oil pipeline industry. In December 2010, to 

implement the third of the required five-yearly re-determinations, the FERC established an upward adjustment in the index to 

track oil pipeline cost changes. The FERC determined that the Producer Price Index for Finished Goods plus 2.65 percent (PPI 

plus 2.65 percent) should be the oil pricing index for the five-year period beginning July 1, 2011. We are not able at this time to 

predict the effects of this indexing system or any new FERC regulations on the transportation costs associated with oil production 

from our oil producing operations.

There regularly are legislative proposals pending in the federal and state legislatures which, if enacted, would significantly 

affect the petroleum industry. At the present time, it is impossible to predict what proposals, if any, might actually be enacted by 

Congress or the various state legislatures and what effect, if any, such proposals might have on us. Similarly, we cannot predict 

whether or to what extent the trend toward federal deregulation of the petroleum industry will continue, or what the ultimate effect 

on our sales of oil, gas and other petroleum products will be.

Environmental Regulations

Our operations are subject to numerous international, federal, state and local laws and regulations governing the discharge 

of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the 

acquisition of a permit before drilling commences, restrict the types, quantities and concentration of various substances that can 

be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on specified 

lands within wilderness, wetlands and other protected areas, require remedial measures to mitigate pollution from former operations, 

such as pit closure and plugging abandoned wells, and impose substantial liabilities for pollution resulting from production and 

drilling operations. The failure to comply with these laws and regulations may result in the assessment of administrative, civil and 

criminal penalties, imposition of investigatory or remedial obligations or the issuance of injunctions prohibiting or limiting the 

extent of our operations. Public interest in the protection of the environment has increased dramatically in recent years. The trend 

of applying more expansive and stricter environmental legislation and regulations to the oil and gas industry could continue, 

resulting in increased costs of doing business and consequently affecting our profitability. To the extent laws are enacted or other 

governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup 

requirements, our business and prospects could be adversely affected.

We generate waste that may be subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable 

state statutes. The U.S. Environmental Protection Agency (“EPA”), and various state agencies have limited the approved methods 

of disposal for certain hazardous and nonhazardous waste. Furthermore, certain waste generated by our oil and gas operations that 

are currently exempt from treatment as “hazardous waste” may in the future be designated as “hazardous waste” and therefore 

become subject to more rigorous and costly operating and disposal requirements.

We currently own or lease numerous properties that for many years have been used for the exploration and production of 

oil and gas. Although we believe that we have 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 for 
22

disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of 

hydrocarbons or other waste was not under our control. These properties and the waste disposed thereon may be subject to the 

Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), RCRAand 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 of the original conduct, on specified classes of persons that are considered to have contributed to the release of a “hazardous 

substance” into the environment. These classes of persons include the owner or operator of the disposal site or sites where the 

release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons 

who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for 

the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources 

and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims 

for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

Our operations may be subject to the Clean Air Act and comparable state and local requirements. In 1990 Congress adopted 

amendments to the Clean Air Act containing provisions that have resulted in the gradual imposition of certain pollution control 

requirements with respect to air emissions from our operations. The EPA and states have developed and continue to develop 

regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years 

for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other 

air emission-related issues. Moreover, changes in environmental laws and regulations occur frequently, and stricter laws, regulations 

or enforcement policies could significantly increase our compliance costs. Further, stricter requirements could negatively impact 

our production and operations. For example, the Texas Commission on Environmental Quality has finalized revisions to certain 

air permit programs that significantly increase the air permitting requirements for new and certain existing oil and gas production 

and gathering sites for 23 counties in the Barnett Shale production area. These initiatives could lead to more stringent air permitting, 

increased regulation and possible enforcement actions at the local, state, and federal levels. Additionally, the EPA has 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 of sulfur dioxide and volatile organic 

compounds, and National Emission Standards for Hazardous Air Pollutants to address hazardous air pollutants frequently associated 

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 (“OPA”) contains numerous requirements relating to the prevention of and response to oil 

spills into waters of the United States. The OPA subjects owners of facilities to strict joint and several liability for all containment 

and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release 

of oil to surface waters. The OPA also requires owners and operators of offshore facilities that could be the source of an oil spill 

into federal or state waters, including wetlands, to post a bond, letter of credit or other form of financial assurance in amounts 

ranging from $10.0 million in specified state waters to $35.0 million in federal outer continental shelf waters to cover costs that 

could be incurred by governmental authorities in responding to an oil spill. These financial assurances may be increased by as 

much as $150.0 million if a formal risk assessment indicates that the increase is warranted. Noncompliance with OPA may result 

in varying civil and criminal penalties and liabilities. Our operations are also subject to the federal Clean Water Act (“CWA”) and 

analogous state laws. In accordance with the CWA, the State of Louisiana issued regulations prohibiting discharges of produced 

water in state coastal waters effective July 1, 1997. Pursuant to other requirements of the CWA, the EPA has adopted regulations 

concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits or seek coverage 

under an EPA general permit. Like OPA, the CWA and analogous state laws relating to the control of water pollution provide 

varying civil and criminal penalties and liabilities for releases of petroleum or its derivatives into surface waters or into the ground. 

Similarly, the U.S. Congress has considered legislation to subject hydraulic fracturing operations to federal regulation and to 

require the disclosure of chemicals used by us and others in the oil and gas industry in the hydraulic fracturing process. Please 

read “Item 1A. Risk Factors — We are subject to various environmental risks and governmental regulations, including those 

relating to benzene emissions and hydraulic fracturing, and new regulations may be more stringent.”

We also are subject to a variety of federal, state, local and foreign permitting and registration requirements relating to protection 

of the environment. We believe we are in substantial compliance with current applicable environmental laws and regulations and 

that continued compliance with existing requirements will not have a material adverse effect on our financial position or results 

of operations.

Our offshore operations in the U.K. North Sea and onshore operations in the U.S. are subject to similar regulations covering 

permit requirements and the discharge of oil and other contaminants in connection with drilling operations.
23

Global Climate Change

There is increasing attention in the United States and worldwide being paid to the issue of climate change and the contributing 

effect of greenhouse gas (“GHG”) emissions. On December 15, 2009, the EPA published a Final Rule, also known as the EPA’s 

Endangerment Finding, finding that current and projected concentrations of six key GHGs in the atmosphere threaten the 

environment and public health and the welfare of current and future generations. Based on these findings, the EPA adopted two 

sets of regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act, including one that 

requires a reduction in emissions of GHGs from motor vehicles and another that regulates GHG emissions from certain large 

stationary sources under the Clean Air Act Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. The 

stationary source rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions, to be phased 

in through a multistep process, with the largest sources being the first subject to permitting. Facilities required to obtain PSD 

permits for their GHG emissions also will be required to meet “best available control technology” standards, which will be 

established by the states or, in some instances, by the EPA on a case-by-case basis. The EPA also expanded its existing GHG 

emissions reporting rule to apply to the oil and gas source category, including oil and natural gas production facilities and natural 

gas processing, transmission, distribution and storage facilities. In addition, the U.S. Congress has considered a number of legislative 

proposals to restrict GHG emissions and more than 20 states, either individually or as part of regional initiatives, have begun 

taking actions to control or reduce GHG emissions. Moreover, in 2005, the Kyoto Protocol to the 1992 United Nations Framework 

Convention on Climate Change, which establishes a binding set of emission targets for GHGs, became binding on all those countries 

that had ratified it. 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 not possible at this time to predict how regulation 

that may be enacted to address GHG emissions would impact our business, the modification of existing laws or regulations or the 

adoption of new laws or regulations curtailing oil and gas exploration in the areas of the United States or the North Sea in which 

we operate could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased 

costs. In addition, existing or new laws, regulations or treaties (including incentives to conserve energy or use alternative energy 

sources) could have a negative impact on our business if such incentives reduce demand for oil and gas.

In addition to the effects of future regulation, the meteorological effects of global climate change could pose additional risks 

to our onshore and offshore operations in the form of more frequent and/or more intense storms and flooding, which could in turn 

adversely affect our cost of doing business.

Title to Properties; Acquisition Risks

We believe we currently have satisfactory title to all of our producing properties in the specific areas in which we operate, 

except where failure to do so would not have a material adverse effect on our business and operations in such area, taken as a 

whole. For additional information, please see “Item 1A. Risk Factors—We may incur losses as a result of title deficiencies.”

Customers

For the year ended December 31, 2012, Flint Hills Resources, LPand 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, 2011 and 2010, DTE 

Energy Trading, Inc. accounted for approximately 43% and 63%, respectively of our oil and gas revenues. We do not believe the 

loss of any one of our purchasers would materially affect our ability to sell the oil and gas we produce. We believe other purchasers 

are available in our areas of operations. See “Additional Oil and Gas Disclosures—Marketing.”

Employees

At December 31, 2012, we had 208 full-time employees. We believe that our relationships with our employees are good.

In order to optimize prospect generation and development, we utilize the services of independent consultants and contractors 

to perform various professional services, particularly in the areas of 3-D seismic data mapping, acquisition of leases and lease 

options, construction, design, well site surveillance, permitting and environmental assessment. Independent contractors generally 

provide field and on-site production operation services, such as pumping, maintenance, dispatching, inspection and testing. We 

believe that this use of third-party service providers has enhanced our ability to manage general and administrative expenses.

Available Information

Our website address is www.crzo.net. We make our website content available for informational purposes only. It should not 

be relied upon for investment purposes, nor is it incorporated by reference in this Form 10-K. We make available on our website, 

through a direct link to the SEC’s website at www.sec.gov, free of charge, our annual report on Form 10-K, quarterly reports on 

Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically 

file such materials with, or furnish them to, the SEC. You may read and copy any materials we file with the SEC at the SEC’s 

Public Reference Room at 100 F Street NE, Washington, D.C. 20549. You may obtain information regarding the Public Reference 

Room by calling the SEC at 1-800-SEC-0330.
24

You may also find information related to our corporate governance, board committees and company code of ethics at our 

website. Among the information you can find there is the following:

• Audit Committee Charter;

• Compensation Committee Charter;

• Nominating and Corporate Governance Committee Charter;

• Code of Ethics and Business Conduct; and

• Compliance Employee Report Line.

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

Business Conduct and any waiver from a provision of our Code of Ethics by posting such information on our website at www.crzo.net 

under “About Carrizo—Governance.”

Glossary of Certain Industry Terms

The definitions set forth below shall apply to the indicated terms as used herein. All volumes of natural gas referred to herein 

are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances 

are rounded to the nearest multiple or power of ten.

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 of oil equivalent. A Boe is determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate 

or natural gas liquids, which approximates the relative energy content of oil, condensate and natural gas liquids as compared to 

natural gas. 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 interest. An agreement under which one party (carrying party) agrees to pay for a specified portion or for all of the 

drilling and completion and operating costs of another party (carried party) on a property for a specified time in which both own 

a portion of the working interest. The carrying party may be able to recover a specified amount of costs from the carried party’s 

share of the revenue from the production of reserves from the property.

Completion. The process of treating a drilled well followed by the installation of permanent 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 of hydrocarbons that exists in the gaseous phase at original reservoir temperature and 

pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

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

Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be 

recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment 

is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational 

at the time of the reserves estimate if the extraction is by means not involving a well.

Development Costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, 

gathering and storing the oil and gas. Development costs, including depreciation and applicable operating costs of support equipment 

and facilities and other costs of development activities, are costs incurred to (i) gain access to and prepare well locations for drilling, 

including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, 
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 of platforms 

and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly, (iii) acquire, construct and install, 

production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices and production storage 

tanks, natural gas cycling and processing plants, and central utility and waste disposal systems, and (iv) provide improved recovery 

systems.

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic 

horizon known to be productive.

Dry well.An exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient 

quantities to justify completion as an oil or gas well.

Economically producible. The term economically producible, as it relates to a resource, means a resource which generates 

revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate 

revenue shall be determined at the terminal point of “oil and gas producing activities” as defined in Rule 4-10(a)(16) of Regulation 

S-X 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 of a single reservoir or multiple reservoirs all grouped on or related to the 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 of adding proved reserves from various activities. Calculated as capital costs incurred in the acquisition, 

exploration, development and revisions of proved oil and natural gas reserves divided by proved reserve additions.

Finding and development cost - drilling. Calculated by dividing the amount of costs incurred for exploration and development 

activities, by the amount of proved reserve additions.

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

Hydraulic fracturing. Hydraulic fracturing is 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 of hydrocarbons 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 of natural gas.

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

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

or one Boe of natural 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 of six Mcf of natural gas to one Bbl of oil, condensate 

or natural 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.

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

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

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation 

and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and 

related equipment and facilities.

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

oil or gas well.

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

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

as:

The quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty 

to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating 

methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence 

indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. 

The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence 

the project within a reasonable time.

The area of a reservoir considered proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and 

(ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain 

economically producible oil or gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as 

seen in a well penetration unless geoscience, engineering or performance data and reliable technology establish a lower contact 

with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an 

associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, 

engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves that can be produced economically, based on prices used to estimate reserves, through application of improved 

recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful 

testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation 

of an installed program in the reservoir, or an analogous reservoir, or other evidence using reliable technology establishes the 

reasonable certainty of the engineering analysis on which the project or program was based and (ii) the project has been approved 

for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. 

The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, 
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.

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

PV-10 Value. When used with respect to oil and gas reserves, present value, or PV-10 means the estimated future gross 

revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using 

prices calculated as the average oil and gas price during the preceding 12-month period prior to the end of the current reporting 

period, (determined as the unweighted arithmetic average of prices on the first day of each month within the 12-month period) 

and costs in effect at the determination date, without giving effect to non-property related expenses such as general and 

administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted 

using an annual discount rate of 10%.

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the 

quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually 

recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved 

than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and 

economic data are made to estimated ultimate recovery (“EUR”) with time, reasonably certain EUR is much more likely to increase 

or remain constant than to decrease.

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

been previously completed.

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically 

producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or 

there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, 

installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the 

project.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil or gas, or 

both, that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Standardized measure. The present value, discounted at 10%, of future net cash flows from estimated proved reserves after 

income taxes, calculated holding prices and costs constant at amounts in effect 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 of oil and gas reserve information in financial statements filed with the U.S. Securities Exchange 

Commission.

“Tag along” rights. An agreement may provide that if one or more persons owning a majority (or some other specified 

portion) of certain interests desires to sell all (or some specified portion) of their interests in one or more related transactions, other 

owners of the same or similar interests have the “tag along” right to join in the sale.

3-D seismic data. Three-dimensional pictures of the subsurface created by collecting and measuring the intensity and timing 

of sound waves transmitted into the earth as they reflect back to the surface.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the 

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

Undeveloped oil and gas reserves. Reserves of any category that are expected to be recovered from new wells on undrilled 

acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain 

of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic 

producibility, based on pricing used to estimate reserves, at greater distances.

(ii) Undrilled locations are classified as having undeveloped reserves only if a development plan has been adopted indicating 

that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances are estimates for undeveloped reserves attributable to any acreage for which an application of 

fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual 

projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable 

certainty.
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Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on 

the property and a share of production.

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

Item 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 of low oil or gas prices may materially adversely affect our financial position, liquidity (including 

our borrowing capacity under our revolving credit facility), ability to finance planned capital expenditures and results of operations.

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 of natural 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 of the members of the Organization of Petroleum Exporting Countries and other exporting nations to agree 

upon and maintain production constraints and oil price controls;

• technological advances affecting 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 of our drilling program. Drilling for oil and gas involves numerous 

risks, including the risk that no commercially productive oil or gas reservoirs will be discovered. The cost of drilling, completing 

and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a 

variety of factors beyond our control, including:

• 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 of title 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 of the risks and uncertainties of our business, 

our future performance in exploration and drilling may not be comparable to our historical performance described herein.

We may not adhere to our proposed drilling schedule.

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

including:

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

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

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

• economic and industry conditions at the time of drilling, including prevailing and anticipated prices for 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 or budgeted for numerous drilling prospects, we may not be able to lease or drill those prospects 

within our expected time frame or at all. Wells that are currently part of our capital plan may be based on statistical results of 

drilling activities in other 3-D project areas that we believe are geologically similar rather than on analysis of seismic or other data 

in the prospect area, in which case actual drilling and results are likely to vary, possibly materially, from those statistical results. 

In addition, our drilling schedule may vary from our expectations because of future uncertainties. In addition, our ability to produce 

oil and gas may be significantly affected by the availability and prices of hydraulic fracturing equipment and crews.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. We 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 of the producer. The reserve data included herein represents only estimates. Reservoir engineering is a subjective and 

inexact process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner and is based 

on assumptions that may vary considerably from actual results. Furthermore, different reserve engineers may make different 

estimates of reserves 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 of reserves, with particular 

focus on proved undeveloped reserves. The interpretation of SEC rules regarding the classification of reserves and their applicability 

in different 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 of December 31, 2012, approximately 55% of our United States proved reserves were proved undeveloped and proved 

nonproducing. Moreover, some of the producing wells included in our reserve reports as of December 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. Volumetric analysis involves estimating the 

volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure based on 

seismic analysis. In addition, realization or recognition of our proved undeveloped reserves will depend on our development 

schedule and plans. Lack of reasonable certainty with respect to development plans for proved undeveloped reserves could cause 

the discontinuation of the classification of these reserves as proved.
30

The discounted future net cash flows included herein are not necessarily the same as the current market value of our estimated 

oil and gas reserves. As required by the current requirements for oil and gas reserve estimation and disclosures, the estimated 

discounted future net cash flows from proved reserves are based on the average of the sales price on the first day of each month 

in the applicable year, with costs determined as of the date of the estimate. Actual future net cash flows also will be affected by 

factors such as:

• 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 compliance with the Financial Accounting Standards Board Accounting Standards Codification Topic 932, “Extractive Activities

—Oil and Gas” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks 

associated with us or the oil and gas industry in general.

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

In general, the volume of production from oil and gas properties declines as reserves are depleted, with the rate of decline 

depending on reservoir characteristics. Except to the extent we conduct successful exploration and development activities or 

acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil 

and gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. In addition, 

we are dependent on finding partners for our exploratory activity. To the extent that others in the industry do not have the financial 

resources or choose not to participate in our exploration activities, we will be adversely affected.

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

to our projects.

We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and 

other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost 

of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity 

obligations of the other working interest owners such as nonpayment of costs and liabilities arising from the actions of the other 

working interest owners. In addition, the current economic downturn, the credit crisis and the volatility in oil and gas prices may 

increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not 

able to fulfill their joint activity obligations. Some of these working interest owners have experienced liquidity and cash flow 

problems. These problems may lead these parties to attempt to delay the pace of drilling or project development in order to preserve 

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 of these 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 efforts to recover these costs from such parties, which 

could materially adversely affect our financial position.

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

We have experienced and expect to continue to experience substantial capital needs as a result of our active exploration, 

development and acquisition programs. We expect that additional external financing will be required in the future to fund our 

growth. We may not be able to obtain additional financing, and financing under our existing revolving credit facility or new credit 

facilities may not be available in the future. Even if additional capital becomes available, it may not be on terms acceptable to us. 

As in the past, without additional capital resources, we may be forced to limit or defer our planned oil and gas exploration and 

development drilling program by releasing rigs or deferring fracturing, completion and hookup of the wells to pipelines and thereby 

adversely affect our production, cash flow, and the recoverability and ultimate value of our oil and gas properties, in turn negatively 

affecting our business, financial position and results of operations.

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. We rely 

upon access to both our revolving credit facility and longer-term capital markets as sources of liquidity 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 be 
31

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 ourdebt and the provisions of ourdebt agreements could adversely affect ourbusiness, financial 

position and results of operations.

We have demands on our cash resources, including interest expense, operating expenses and funding of our capital 

expenditures. Our level of long-term debt, the demands on our cash resources and the provisions of the 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 of our drilling program, selling assets, reducing 

our capital expenditures, refinancing all or a portion of our existing debt or obtaining additional financing, which may 

be on unfavorable terms; and

• 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 of our subsidiaries with respect to incurring additional indebtedness and liens, making dividends and 

other payments to shareholders, repurchasing or redeeming our common stock, redeeming our convertible senior notes, 8.625% 

Senior Notes and 7.50% Senior Notes, making investments, acquisitions, mergers and asset dispositions, entering into hedging 

transactions and other matters. Our revolving credit facility also requires compliance with covenants to maintain 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. If the price that we receive for our oil and 

natural gas production deteriorates significantly from current levels it could lead to lower revenues, cash flow and earnings, which 

in turn could lead to a default under certain financial covenants contained in our revolving credit facility, including the covenants 

related to working capital and the ratios described above. Because the calculations of the financial ratios are made as of certain 

dates, the financial ratios can fluctuate significantly from period to period as the amounts outstanding under our revolving credit 

facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and 

securities offerings. Additionally, these ratios may have the effect of restricting us from borrowing the full amount available under 

the borrowing base for our revolving credit facility. In order to provide a margin of comfort with regard to these financial covenants, 

we may seek to further reduce our capital expenditure plan, sell additional non-strategic assets or opportunistically modify or 

increase our derivative instruments to the extent permitted under our revolving credit facility. We cannot assure you that we will 

be able to successfully execute any of these strategies, or if executed, that they will be sufficient to avoid a default under our 

revolving credit facility if a precipitous decline in oil or natural gas prices were to occur in the future.

The borrowing base under our revolving credit facility may be reduced below the amount of borrowings outstanding under

those facilities.

Under the terms of our revolving credit facility, our borrowing base is subject to redeterminations at least semi-annually 

based in part on prevailing oil and gas prices. A negative adjustment could occur if the estimates of future prices used by the banks 

in calculating the borrowing base are significantly lower than those used in the last redetermination. The next redetermination of 

our borrowing base is scheduled to occur in May 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 and 
32

other financial covenants of such facility. In the event the amount outstanding under our revolving credit facility exceeds the 

redetermined borrowing base, we could be forced to repay a portion of our borrowings. We may not have sufficient funds to make 

any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or 

arrange new financing, we may have to sell a portion of our assets.

We have in the past identified material weaknesses in our internal controls over financial reporting, and the identification 

of any material weaknesses in the future could affect our ability to ensure timely and accurate financial statements.

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 sufficient to ensure that our internal controls are effective in the future. In addition, our history of 

material weaknesses, any future material weaknesses, or any failure to effectively address a material weakness or other control 

deficiency or implement required new or improved controls, or difficulties encountered in their implementation, could limit our 

ability to obtain financing, harm our reputation, disrupt our ability to process key components of our results of operations and 

financial position timely and accurately and cause us to fail to meet our reporting obligations under rules of the SEC, NASDAQ 

and our various debt arrangements.

We 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 difficult or impossible to obtain permits and other needed 

authorizations to operate, result in operational delays, or otherwise make operating more costly or difficult than operating elsewhere.

We have no experience drilling wells in the Utica Shale and less information regarding reserves and decline rates in this 

shale formation than in some other areas of our operations.

We have no exploration experience and no development experience in the Utica Shale. We have not participated in the 

drilling of any wells in this area. Other operators in this area have significantly more experience in the drilling of wells, including 

the drilling of horizontal wells. As a result, we have less information with respect to the ultimate recoverable reserves, the production 

decline rate and other matters relating to the exploration, drilling and development of the Utica Shale than we have in some other 

areas in which we operate.

If we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of the water we 

use at a reasonable cost and within applicable environmental rules, our ability to produce gas commercially and in 

commercial quantities could be impaired.

We use a substantial amount of water in our drilling operations. Our inability to locate sufficient amounts of water, or treat 

and dispose of water after drilling, could adversely impact our operations. Moreover, the imposition of new environmental initiatives 

and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of 

waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development 

or production of natural gas. Furthermore, future environmental regulations and permit requirements governing the withdrawal, 

storage and use of surface water or groundwater necessary for hydraulic fracturing of wells could increase operating costs and 

cause delays, interruptions or termination of operations, the extent of which cannot be predicted, all of which could have an adverse 

effect on our operations and financial performance.

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

If we are unable to increase our acreage positions in the Eagle Ford Shale, the Niobrara Formation or the Utica Shale, this 

may detract from our efforts to realize our growth strategy in crude oil and liquids-rich plays. Additionally, we may be unable to 

find or consummate other opportunities in these areas or in other areas with similar exposure to oil, condensate and natural gas 

liquids on similar terms or at all.

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

production.

One of our current primary core gas producing areas is located in largely urban portions of the Barnett Shale, which could 

disproportionately expose us to operational and regulatory risk in that area. At December 31, 2012, approximately 44% of our 
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United States proved reserves and approximately 45% of our then current production were located in the Barnett Shale. The core 

of the Barnett Shale is located in and around the greater Dallas-Fort Worth, Texas metropolitan area and much of our operations 

are within the city limits of various municipalities in that region, such as Arlington and Mansfield, Texas. In such urban or other 

populated areas, we may incur additional expenses, including expenses relating to mitigation of noise, odor and light that may be 

emitted in our operations, expenses related to the appearance of our facilities and limitations regarding when and how we can 

operate. The process of obtaining permits for drilling or for gathering lines to move our natural gas to market in such areas may 

be more time consuming and costly than in more rural areas. In addition, we may experience a higher rate of litigation or increased 

insurance and other costs related to our operations or facilities in such highly populated areas.

We face strong competition from other oil and gas companies.

We encounter competition from other oil and gas companies in all areas of our operations, including the acquisition of 

exploratory prospects and proven properties. Our competitors include major integrated oil and gas companies and numerous 

independent oil and gas companies, individuals and drilling and income programs. Many of our competitors are large, wellestablished companies that have been engaged in the oil and gas business much longer than we have and possess substantially 

larger operating staffs and greater capital resources than we do. These companies may be able to pay more for exploratory projects 

and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and 

prospects than our financial or human resources permit. In addition, these companies may be able to expend greater resources on 

the existing and changing technologies that we believe are and will be increasingly important to attaining success in the industry. 

Such competitors may also be in a better position to secure oilfield services and equipment on a timely basis or on favorable terms. 

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. We may not be able to conduct our operations, 

evaluate and select suitable properties and consummate transactions successfully in this highly competitive environment.

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

The oil and gas industry is characterized by rapid and significant technological advancements and introductions of new 

products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive 

disadvantage, and competitive pressures may force us to implement those new technologies at substantial cost. In addition, other 

oil and gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological 

advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to 

these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the 

technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially 

available technology, our business, financial condition and results of operations could be materially adversely affected.

Part of our strategy involves drilling existing or emerging shale plays using some of the 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 of the 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 of these drilling and completion techniques can only be evaluated over time as more wells are drilled 

and production profiles are established over a sufficiently 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.

We 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 of wells, unitization and pooling of properties 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 

regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, 

storage, transportation and disposal of oil and gas, by-products thereof and other substances and materials produced or used in 

connection with oil and gas operations, including drilling fluids and wastewater. In addition, we may incur costs arising out of 

property damage, including environmental damage caused by previous owners or operators of property we purchase or lease or 

relating to third party sites, or injuries to employees and other persons. As a result, we may incur substantial liabilities to third 

parties or governmental entities and may be required to incur substantial remediation costs. We also are subject to changing and 

extensive tax laws, the effects of which cannot be predicted. Compliance with existing, new or modified laws and regulations 

could result in substantial costs, delay our operations or otherwise have a material adverse effect on our business, financial position 

and results of operations.

Moreover, changes in environmental laws and regulations occur frequently and such laws and regulations tend to become 

more stringent over time. Stricter laws, regulations or enforcement policies could significantly increase our compliance costs and 

negatively impact our production and operations, which could have a material adverse effect on our results of operations and cash 

flows. See “Item 1. Business—Additional Oil and Gas Disclosures—Regulation—Environmental Regulations” for additional 

information.

There is increasing attention in the United States and worldwide being paid to the issue of climate change and the contributing 

effect of GHG emissions. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing 

oil and gas exploration in the areas in which we operate could materially and adversely affect 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 of water, sand and chemicals under pressure into rock 

formations to stimulate gas production. The U.S. Congress has considered legislation to subject hydraulic fracturing operations 

to federal regulation and to require the disclosure of chemicals used by us and others in the oil and gas industry in the hydraulic 

fracturing process. The EPA has asserted federal regulatory authority over hydraulic fracturing involving diesel under the federal 

Safe Drinking Water Act and has released draft permitting guidance for hydraulic fracturing operations that use diesel fuel in 

fracturing fluids in those states where EPA is the permitting authority. A number of federal agencies are also analyzing, or have 

been requested to review, a variety of environmental issues associated with hydraulic fracturing. For example, the EPAis conducting 

a comprehensive research study to investigate the potential adverse environmental impacts of hydraulic fracturing, including on 

water quality and public health. The EPA 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 Water Act, the 

Toxic Substances Control Act, or other regulatory mechanisms. President Obama has created the Interagency Working 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 York legislature has approved a temporary moratorium on drilling involving hydraulic fracturing 

and the New York State Department of Environmental Conservation has ceased issuing exploration and production drilling permits, 

pending completion of an environmental impact statement regarding hydraulic fracturing. Pennsylvania has adopted a variety of 

regulations since 2010 limiting how and where hydraulic fracturing can be performed in the state, including the adoption of 

upgraded well construction and casing standards, upgraded cement standards and new recordkeeping requirements. 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, extends well setbacks, establishes standards for containment on well sites, requires annual inventory of air emissions, 

enhances disclosure requirements, and increases the maximum amount of civil 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 Texas, have proposed or adopted 

legislative or regulatory restrictions on hydraulic fracturing through additional permit requirements, public disclosure of fracturing 

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, West Virginia, 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. We use hydraulic fracturing extensively and any increased federal, state, local, foreign or international 

regulation of hydraulic fracturing or offshore drilling, including legislation and regulation in the states of Colorado, New York, 
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Ohio, Texas and Pennsylvania, could reduce the volumes of oil and gas that we can economically recover, which could materially 

and adversely affect our revenues and results of operations.

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 of certain key U.S. federal income tax incentives currently available to oil and 

gas exploration and production companies. These or any other similar changes in U.S. federal income tax laws could defer or 

eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such 

change could negatively affect our financial position and results of operations.

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;

• spillage handling and disposing of materials, including drilling fluids and hydraulic fracturing fluids and other pollutants;

• pipeline ruptures or spills;

• releases of toxic gases; 

• adverse weather conditions, including drought, flooding, winter storms, snow, hurricanes or other severe weather events; 

and

• other environmental hazards and risks including conditions caused by previous owners and lessors of our properties.

Any of these 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.

Offshore operations are subject to a variety of operating risks in addition to the hazards described above, such as capsizing 

and collisions.The occurrence of other events such as blowouts and oil spills in marine environments can make containment and 

remediation more difficult and costly than on land. These conditions can and have caused substantial damage to facilities and 

interrupted production in the past. Additionally, offshore 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 of pipelines, natural gas gathering systems and 

processing facilities we do not own. Any significant change affecting these infrastructure facilities could materially harm our 

business. The lack of available capacity of gathering systems and pipelines could reduce the price offered for our production or 

result in the shut-in of producing 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 offshore 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 efforts may delay or halt the construction of 

additional pipelines or facilities. To the extent these services are unavailable, we would be unable to realize revenue from wells 

served by such facilities until suitable arrangements are made to market our production. As a result, we could experience reductions 

in revenue that could reduce or eliminate the funds available for our exploration and development programs and acquisitions, or 

result in the loss of property.
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We may not have enough insurance to cover all of the risks we face.

We maintain insurance against losses and liabilities in accordance with customary industry practices and in amounts that 

management believes to be prudent; however, insurance against all operational risks is not available to us. We do not carry business 

interruption insurance. We may elect not to carry insurance if management believes that the cost of available insurance is excessive 

relative to the risks presented. In addition, losses could occur for uninsured risks or in amounts in excess of existing insurance 

coverage. We cannot insure fully against pollution and environmental risks. We cannot assure you that we will be able to maintain 

adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. The 

occurrence of an event not fully covered by insurance could have a material adverse effect on our financial position and results 

of operations.

We conduct a substantial portion of our operations through joint ventures, which subject us to additional risks that could 

have a material adverse effect on the success of these operations, our financial position and our results of operations.

We conduct a substantial portion of our operations through joint ventures with third parties, including Avista and its affiliates, 

GAIL, Haimo, the OIL JV Partners, Reliance and an affiliate of Sumitomo Corporation. We may also enter into other joint venture 

arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as 

the obligation to pay substantial carried costs pertaining to the joint venture and to pay their share of capital and other costs of the 

joint venture. The performance of these third party obligations, including the ability of the third parties to satisfy their obligations 

under these arrangements, is outside our control. If these parties do not satisfy their obligations under these arrangements, our 

business may be adversely affected.

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

including, for example:

• our joint 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 

of joint venture liabilities;

• we may incur liabilities as a result of an action taken by our joint 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 our joint venture partners may result in delays, litigation or operational impasses.

The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture 

partners could adversely affect our ability to transact the business that is the subject of such joint venture, which would in turn 

negatively affect our financial condition and results of operations. The risks described above or the failure to continue our joint 

ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to transact the business that 

is the subject of such joint venture, which would in turn negatively affect our financial condition and results of operations. 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 the joint venture and require us to grant rights to our joint venture partners that could limit our 

ability to benefit fully from future positive developments. Some joint ventures requires us to make significant capital expenditures. 

If we do not timely meet our financial commitments or otherwise do not comply with our joint venture agreements, our rights to 

participate, exercise operator rights or otherwise influence or benefit from the joint venture may be adversely affected. 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 our joint venture partners propose, thereby reducing our ability to benefit from 

the joint venture.

We cannot control the activities on properties we do not operate.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence 

over, and control the risks associated with, operations of these properties. The failure of an operator of our wells to adequately 

perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best 

interests could reduce our production and revenues or could create liability for us for the operator’s failure to properly maintain 

the well and facilities and to adhere to applicable safety and environmental standards. With respect to properties that we do not 

operate:

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

• if we proceed with any of those projects the operator has refused to initiate, we may not receive any funding from the 

operator with respect to that project;

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

• the operator may propose greater capital expenditures than we wish, including expenditures to drill more wells or build 

more facilities on a project than we have funds for, which may mean that we cannot participate in those projects or 

participate in a substantial amount of the revenues from those projects; and

• the operator may not have sufficient expertise or resources.

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

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 

our oil or gas may have several adverse effects, including higher transportation costs, fewer potential purchasers (thereby potentially 

resulting in a lower selling price) or, in the event we were unable to market and sustain production from a particular lease for an 

extended time, possibly causing us to lose a lease due to lack of production. There is currently 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 of production 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 of our oil and gas production may be interrupted due to capacity constraints on the applicable system, for maintenance 

or repair of the system, or for other reasons as dictated by the particular agreements. Due to the lack of available pipeline capacity 

in the Eagle Ford Shale and the Marcellus Shale, we have entered into firm transportation agreements for a portion of our production 

in the Eagle Ford Shale and Marcellus Shale in order to assure our ability, and that of our purchasers, to successfully market the 

oil and gas that we produce. We may also enter into firm transportation arrangements for additional production in the future. These 

firm transportation agreements may be more costly than interruptible or short-term transportation agreements.

If production in the Marcellus Shale by oil and gas companies continues to expand, the amount of natural gas being produced 

by us and others could exceed the capacity of the various gathering and intrastate or interstate transportation pipelines currently 

available in these areas. If this occurs, it will be necessary for new pipelines and gathering systems to be built. Because of the 

current economic climate, certain pipeline projects that are planned for the Marcellus Shale may not occur for lack of financing. 

In addition, capital constraints could limit our ability to build intrastate gathering systems necessary to transport our gas to interstate 

pipelines. In such event, we might have to shut in our wells awaiting a pipeline connection or capacity or sell natural gas production 

at significantly lower prices than those we currently project, which could materially and adversely affect our results of operations.

A portion of our oil and gas production in any region may be interrupted, or shut in, from time to time for numerous reasons, 

including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or 

we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted 

at the same time, it could temporarily adversely affect our cash flow.

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

In acquiring producing properties, we assess the recoverable reserves, future oil and gas prices, 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 of a subject property in connection with our acquisition assessment 

will not reveal all existing or potential problems or permit us to become sufficiently familiar with the property to assess fully its 

deficiencies and capabilities. We may not inspect every well, and we may not be able to observe structural and environmental 

problems even when we do inspect a well. If problems are identified, the seller may be unwilling or unable to provide effective 

contractual protection against all or part of those problems. Any acquisition of property interests may not be economically 

successful, and unsuccessful acquisitions may have a material adverse effect on our financial position and future results of 

operations.
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Our business may suffer if we lose key personnel.

We depend to a large extent on the services of certain key management personnel, including our executive officers and other 

key employees, the loss of any of whom could have a material adverse effect on our operations. We have entered into employment 

agreements with many of our key employees as a way to assist in retaining their services and motivating their performance. We 

do not maintain key-man life insurance with respect to any of our employees. Our success will also be dependent on our ability 

to continue to employ and retain skilled technical personnel.

We may experience difficulty in achieving and managing future growth.

We have experienced growth in the past primarily through the expansion of our drilling program. Future growth may place 

strains on our financial, technical, operational and administrative resources and cause us to rely more on project partners and 

independent contractors, possibly negatively affecting our financial position and results of operations. Our ability to grow will 

depend on a number of factors, including:

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

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

• our ability to identify and acquire new exploratory prospects;

• our ability to develop existing prospects;

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

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

• the results of our drilling program;

• hydrocarbon prices; and

• our access to capital.

We may not be successful in upgrading our technical, operations and administrative resources or in increasing our ability 

to internally provide certain of the services currently provided by outside sources, and we may not be able to maintain or enter 

into new relationships with project partners and independent contractors. Our inability to achieve or manage growth may adversely 

affect our financial position and results of operations.

We 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 differential swaps to reduce our exposure to price declines associated with a portion 

of our oil and gas production and thereby to achieve a more predictable cash flow. The use of these arrangements limits our ability 

to benefit from increases in the prices of oil and gas. Our derivative arrangements may apply to only a portion of our production, 

thereby providing only partial protection against declines in oil and gas prices. These arrangements may expose us to the risk of 

financial loss in certain circumstances, including instances in which production is less than expected, our customers fail to purchase 

contracted quantities of oil and gas or a sudden, unexpected event materially impacts oil or gas prices. In addition, the counterparties 

under our derivatives contracts may fail to fulfill their contractual obligations to us.

Periods of high demand for field services and equipment and the ability of suppliers to meet that demand may limit our

ability to drill and produce our oil and gas properties.

During periods when oil and gas prices are relatively high, well service providers and related equipment and personnel may 

be in short supply. These shortages can cause escalating prices, delays in drilling and other exploration activities and the possibility 

of poor services coupled with potential damage to downhole reservoirs and personnel injuries. Such pressures may increase the 

actual cost of services, extend the time to secure such services and add costs for damages due to any accidents sustained from the 

overuse of equipment and inexperienced personnel.

We may record impairments of oil and gas properties that would reduce our shareholders’ equity.

We use the full cost method of accounting for our oil and gas properties. Accordingly, we capitalize all productive and 

nonproductive costs directly associated with property acquisition, exploration and development activities to cost centers established 

on a country-by-country basis. Under the full cost method, the capitalized cost of oil and gas properties, less accumulated 

amortization and related deferred income taxes may not exceed the “cost center ceiling” which is equal to the sum of the present 

value of estimated future net revenues from proved reserves, less estimated future expenditures to be incurred in developing and 

producing the proved reserves computed using a discount factor of 10%, plus the costs of properties not subject to amortization, 
39

plus the lower of the cost or estimated fair value of unproved properties included in the costs being amortized, less related income 

tax effects. If the net capitalized costs exceed the cost center ceiling, we recognize the excess as an impairment of oil and gas 

properties. This impairment does not impact cash flows from operating activities but does reduce earnings and our shareholders’

equity. The risk that we will be required to recognize impairments of our oil and gas properties increases during periods of low 

oil or gas prices. In addition, impairments would occur if we were to experience sufficient downward adjustments to our estimated 

proved reserves or the present value of estimated future net revenues, as further discussed under “—Our reserve data and estimated 

discounted future net cash flows are estimates based on assumptions that may be inaccurate and are based on existing economic 

and operating conditions that may change in the future.” An impairment recognized in one period may not be reversed in a 

subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period. We have 

in the past and could in the future incur additional impairments of oil and gas properties, particularly as a result of a decline in oil 

or gas prices.

We could lose our ability to use net operating loss carryforwards that we have accumulated over the years.

Our ability to utilize U.S. net operating loss carryforwards to reduce future taxable income is subject to various limitations 

under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon 

the occurrence of certain ownership changes, including the purchase or sale of our stock by 5% shareholders and our offering of 

stock during any three-year period resulting in an aggregate change of more than 50% in our beneficial ownership. In the event 

of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of our taxable income that can be 

offset by these carryforwards. The limitation is generally equal to the product of (a) the fair market value of our equity multiplied 

by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership 

change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only 

to the extent of any net unrealized built-in gains inherent in the assets sold. As of December 31, 2012, we believe an ownership 

change occurred in February 2005, which imposed an annual limitation of approximately $12.6 million of the Company’s taxable 

income that can be offset 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 of proposed impact fees on natural gas wells could adversely impact our results of operations and the economic 

viability of exploiting natural gas drilling and production opportunities in Pennsylvania.

Legislation has been enacted in Pennsylvania, that authorizes counties to impose fees on certain natural gas wells in 

Pennsylvania. If a county elects to impose a fee, the fee will apply to any “unconventional gas well,” which is generally defined 

as a well using hydraulic fracture treatments or multilateral well bores. Any county that elects not to impose the fee can be overruled 

by the municipalities within that county. The fee would be imposed over a fifteen year period, starting with the year the well is 

actually drilled and declining thereafter, and is based on natural gas prices and the Consumer Price Index. Unconventional gas 

wells drilled before the fee is imposed would still be subject to the fee and, for purposes of calculating the amount of the fee, will 

be considered to have been drilled in the calendar year prior to the imposition of the fee. A substantial portion of our Marcellus 

Shale acreage and a portion of our Utica Shale acreage is located in the Commonwealth of Pennsylvania. To the extent such fees 

are ultimately enacted by counties in which we now or may in the future operate, or if Pennsylvania adopts severance taxes or 

additional fees, such actions could adversely impact our results of operations and the economic viability of exploiting natural gas 

drilling and production opportunities in Pennsylvania.

We may incur losses as a result of title deficiencies.

We purchase working and revenue interests in the oil and gas leasehold interests upon which we will perform our exploration 

activities from third parties or directly from the mineral fee owners. The existence of a material title deficiency can render a lease 

worthless and can adversely affect our results of operations and financial condition. Title insurance covering mineral leaseholds 

is not generally available and, in all instances, we forego the expense of retaining lawyers to examine the title to the mineral interest 

to be placed under lease or already placed under lease until the drilling block is assembled and ready to be drilled. Even then, 

particularly in urban settings, the cost of performing detailed title work can be expensive. We may choose to forgo detailed title 

examination by title lawyers on a portion of the mineral leases that we place in a drilling unit or conduct less title work than we 

have traditionally performed. As is customary in our industry, we generally rely upon the judgment of oil and gas lease brokers 

or independent landmen who perform the field work in examining records in the appropriate governmental offices and abstract 

facilities before attempting to acquire or place under lease a specific mineral interest and before drilling a well on a leased tract. 

We, in some cases, perform curative work to correct deficiencies in the marketability or adequacy of the title to us. The work 

might include obtaining affidavits of heirship or causing an estate to be administered. In cases involving more serious title problems, 

the amount paid for affected oil and gas leases can be generally lost and the target area can become undrillable. The failure of title 

may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of 

the minerals under the property.
40

We have risks associated with our foreign operations.

We currently have international activities and we continue to evaluate and pursue new opportunities for international 

expansion in select areas. Ownership of property interests and production operations in areas outside the United States is subject 

to the various risks inherent in foreign operations. These risks may include:

• currency restrictions and exchange rate fluctuations;

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

• increases in taxes and governmental royalties;

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

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

• labor problems; and

• other uncertainties arising out of foreign government sovereignty over our international operations.

Our international operations also may be adversely affected by the laws and policies of the United States affecting foreign 

trade, taxation and investment. In addition, if a dispute arises with respect to our foreign operations, we may be subject to the 

exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of 

the United States.

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

We cannot assess the extent of either the threat or the potential impact of future terrorist attacks on the energy industry in 

general, and on us in particular, either in the short-term or in the long-term. Uncertainty surrounding such hostilities may affect 

our operations in unpredictable ways, including the possibility that infrastructure facilities, including pipelines and gathering 

systems, production facilities, processing plants and refineries, could be targets of, or indirect casualties of, an act of terror, a cyber 

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

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” 

of the 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 of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse 

effect on our financial position or results of operations.

Item 4. Mine Safety Disclosures

Not applicable.
41

PART II

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

Our common stock, par value $0.01 per share, trades on the NASDAQ Global Select Market under the symbol “CRZO.” 

The following table sets forth the high and low sales prices per share of our common stock on the NASDAQ Global Select Market 

for the periods indicated.

High Low

2011

First Quarter $ 39.34 $ 28.71

Second Quarter 42.72 32.47

Third Quarter 44.17 20.95

Fourth Quarter 30.00 18.02

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 of our common stock on February 25, 2013 was $21.29 per share. As of February 25, 2013, there 

were an estimated 185 owners of record of our common stock.

We have not paid any dividends on our common stock in the past and do not intend to pay such dividends in the foreseeable 

future. We currently intend to retain any earnings for the future operation and development of our business, including exploration, 

development and acquisition activities. Our revolving credit facility restricts our ability to pay dividends. See “Item 7. 

Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

The following graph presents a comparison of the yearly percentage change in the cumulative total return on our Common 

Stock over the period from December 31, 2007 to December 31, 2012, with the cumulative total return of the S&P500 Index and 

the American Stock Exchange (“AMEX”) Natural Resources Industry Index of publicly traded companies over the same period. 

The graph assumes that $100 was invested on December 31, 2007 in our common stock at the closing market price at the beginning 

of this period and in each of the other two indices and the reinvestment of all dividends, if any.

The graph is presented in accordance with requirements of the SEC. Shareholders are cautioned against drawing any 

conclusions from the data contained therein, as past results are not necessarily indicative of future financial performance.

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, 2011 86 80 48

December 31, 2012 97 76 38

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

We made no repurchases of our common stock in the fourth quarter of 2012.

On November 24, 2009, we entered into a land agreement with an unrelated third party and its affiliate. This land agreement 

expired by its terms on May 31, 2011. Under the land agreement, we issued warrants to purchase 31,983, 28,576 and 57,641 shares 

of common stock in 2012, 2011 and 2010, respectively. The warrants have an expiration date of August 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 

warrants under the land agreement was effected in April 2012. The warrants were issued pursuant to an exemption from registration 

under §4(2) of the Securities Act of 1933, as amended. Please see “Item 7. Management’s Discussion and Analysis of Financial 

Condition and Results of Operations—Liquidity and Capital Resources—Lease Option Arrangements” for more information about 

this land agreement and other lease option arrangements.
42

During second and fourth quarters of 2012, we issued 45,327 and 47,962 newly issued shares, respectively, of our common 

stock to the University of Texas 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 of Texas at Arlington, where we are 

producing natural gas from a number of wells 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) of the Securities Act of 1933, 

as amended, for transactions not involving a public offering.

See “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” for 

information regarding shares of common stock authorized for issuance under our stock incentive plans.
43

Item 6. Selected Financial Data 

Our financial information set forth below for each of the 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 and Analysis of Financial Condition and Results of Operations” and our Consolidated Financial Statements and related 

Notes included in “Item 8. Financial Statements and Supplementary Data.”

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 offerings, net of offering 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

Total 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 115.1 MMBoe at December 31, 2012. The key drivers to our success in 2012 included the following:

Drilling program. Our success is largely dependent on the results of our drilling program. For the year ended December 31, 

2012, we drilled 133 gross (70.8 net) wells a success rate of 99% that was comprised of: (a) 59 of 59 gross (46.7 net) wells in the 

Eagle Ford Shale, (b) 26 of 26 gross (9.1 net) wells in the Niobrara Formation, (c) 38 of 39 gross (12.5 net) wells in the Marcellus 

Shale, (d) 6 of 6 gross (1.7 net) wells in the Barnett Shale, and (e) 2 of 3 gross (0.4 net) wells in other project areas. At December 31, 

2012, 61 of these gross (28.7 net) wells were awaiting completion or pipeline connections.

Production and reserve growth. 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 2011 production of 7.5 MMBoe. The increase in production was primarily due to 

increased production from new wells, partially offset 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 2011. Due to divestitures during 

2012, our U.S. proved oil and gas reserves decreased 23% to 115.1 MMBoe at December 31, 2012, as compared to 149.7 MMBoe

at December 31, 2011. Adjusted for the divestitures of 53.8 MMBoe in 2012, we replaced 303% of 2012’s record production.

Commodity prices. Our average gas price during 2012 was $1.90 per Mcf, $1.08 per Mcf less than the 2011 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 2011. Commodity prices are affected 

by changes in market demand, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis 

differentials and other factors. Our financial results are largely dependent on commodity prices, which are beyond our control and 

have been and are expected to remain volatile.

Financial flexibility. During 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 offering $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 effect by our hedging of 18,250,000 MMBtus of natural gas (approximately 57% of currently forecasted 2013 production) 

for 2013. We are rapidly growing our oil production, part of the effect of which will serve to further reduce our exposure to the 

weak natural gas market. The current market and outlook for 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 of oil (approximately 84% of forecasted 2013 production) and 2,555,000 Bbls of oil 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 of Carrizo UK, and all of its 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 of income taxes, in the consolidated statements of 

income and cash flows.

Control capital costs and maintain financial flexibility. Our Board of Directors 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 expenditure plan. In 2013, we plan to focus on the development of our key U.S. oil and gas resource plays. Our 

capital expenditures could vary from our current plan depending upon various factors, including the availability and cost of drilling 

rigs, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, 

commodity prices, market conditions, 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

Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

Revenues from oil and gas production for 2012 increased 82% to $368.2 million compared to $202.2 million in 2011. 

Production volumes in 2012 were 9.4 MMBoe, an increase of 26%, compared to production of 7.5 MMBoe in 2011. The increase 

in production was primarily due to increased production from new wells, partially offset by normal production decline, and the 

Atlas and KKR sales. See “Item 1. Business—Natural Gas Plays—Barnett Shale” for additional information. Average oil prices 

increased 6% to $99.97 per Bbl in 2012 from $94.14 per Bbl in 2011. Average natural gas prices decreased 36% to $1.90 per Mcf 

in 2012 from $2.98 per Mcf in 2011. Average NGL prices decreased 31% to $34.86 per Bbl in 2012 from $50.30 per Bbl in 2011.

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 2011:

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)%

Total Natural gas and NGLs (MMcfe) 39,442 40,251 (809) (2)%

Total 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)%

Total barrels of oil equivalent per day (Boe/d) 25,781 20,578 5,203 25 %

Average 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)%

Total 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)%

Total 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 2011. 

Lease operating expenses increased $3.2 million primarily due to increased production from new wells partially offset by the Atlas 

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 offset by the higher operating cost per Boe

associated with oil production.

Production taxes increased to $13.5 million (or 3.7% of oil and gas revenues) in 2012 from $5.7 million (or 2.8% of oil and 

gas revenues) in 2011 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 effective 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 2011. The increase 

in ad valorem taxes is due primarily to new oil wells drilled in 2011 and the Commonwealth of Pennsylvania’s February 2012 

enactment of an “impact fee” on the drilling of unconventional natural gas wells. Because of the retroactive nature of the 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 2011, which have higher property tax valuations 

as compared to our natural gas wells, as well as the recognition of the 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 ($11.26 per Boe) in 2011. 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 of the significant decrease in natural 

gas reserves in the Barnett Shale as a result of the Atlas and KKR sales as well as the increase in crude oil reserves in the Eagle 

Ford Shale that have been added during 2011 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 2011. The increase 

was primarily due to increased compensation costs related to an increase in personnel in 2012 as compared to 2011. This was 

partially offset 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 2011, partially offset by 

higher stock-based compensation expense due to a higher number of restricted units outstanding during 2012 as compared to 2011.

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 2011 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 2011, 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 2011 as well as interest on the $300.0 

million aggregate principal amount of our 7.50% Senior Notes issued in the third quarter of 2012. 

Our effective income tax rate was 37.7% for 2012 and 44% for 2011. The decrease in the effective income tax rate is primarily 

due to the adjustments to prior state income tax provisions recorded during fourth quarter of 2011 and the income tax benefit of 

a capital loss associated with a prior investment.

Net income from discontinued operations, net of income taxes for 2012 increased to $4.3 million from $4.1 million in 2011. 

The increase is primarily related to income tax benefits associated with Carrizo UK.

Year Ended December 31, 2011 Compared to the Year Ended December 31, 2010

Revenues from oil and gas production for 2011 increased 46% to $202.2 million from $138.1 million in 2010. Production 

volumes for oil and gas in 2011 increased 22% to 7.5 MMBoe from 6.1 MMBoe in 2010. The increase in production for the year 

ended December 31, 2011 as compared to the year ended December 31, 2010 was primarily due to increased production from new 

wells, partially offset by normal production decline, the Atlas sale, and the KKR sale. Average oil prices increased 20% to $94.14 

per Bbl from $78.74 per Bbl in 2010. Average natural gas prices decreased 11% to $2.98 per Mcf in 2011 from $3.33 per Mcf in 

2010. Average NGL prices increased 31% to $50.30 per Boe in 2011 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, 2011 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 %

Average 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)%

Total 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 %

Total oil and gas revenues $ 202,167 $ 138,123 $ 64,044 46 %

Lease operating expenses for 2011 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. We continue to experience a decrease in the operating cost per 

Boe of our Barnett Shale production as a result of the Atlas and KKR sales, which was partially offset 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 2011 from $3.6 million (2.6% of oil and gas 

revenues) in 2010 as a result of higher oil prices and increased production in 2011. The increase in production taxes as a percentage 

of oil and gas revenues is due to increased oil production, which has a higher effective production tax rate as compared to natural 

gas production. 

Ad valorem taxes decreased to $3.6 million ($0.48 per Boe) in 2011 from $3.7 million ($0.60 per Boe) in 2010 due to the 

sale of substantially all of our non-core area Barnett Shale properties in May 2011, partially offset by new oil and gas wells drilled 

in 2010.

DD&A expense for 2011 increased to $84.6 million ($11.26 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 2011 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 efforts resulting in a full-cost ceiling test impairment of $2.7 million ($1.7 

million net of income taxes) for the year ended December 31, 2010 with respect to the U.K. cost center. 
48

G&Aexpense for 2011 increased to $41.5 million from $35.9 million in 2010. The increase was due primarily to (a) increased 

compensation costs related to an increase in personnel in 2011 as compared to 2010, (b) the expense associated with contributions 

to University of Texas at Arlington, (c) increased office costs related to relocating our corporate headquarters in the fourth quarter 

of 2011 partially offset by (d) decreased stock-based compensation expense driven by a significant decrease in the fair value of 

SARs that we expect to be settled in cash due to a decrease in stock price during the second half of 2011, partially offset by higher 

stock-based compensation expense due to a higher number of stock-based compensation awards outstanding during 2011.

The net gain on derivative instruments of $48.4 million in 2011 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 2011, 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 of two banks in the prior credit facility who did not participate in the new revolving 

credit facility. 

In November 2010, we completed a tender offer for $300.0 million aggregate principal amount outstanding of our convertible 

senior notes for an aggregate consideration of approximately $306.3 million, including accrued and unpaid interest on the 

convertible senior notes. We recognized a $31.0 million pre-tax loss on extinguishment of debt as a result of the purchase of the 

convertible senior notes in the tender offer, substantially all of which was non-cash representing the associated unamortized 

discount and deferred financing costs.

Interest expense and capitalized interest in 2011 were $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 of 2010 and the $200.0 million aggregate principal amount 

of 8.625% Senior Notes issued in the fourth quarter of 2011 partially offset by decreased interest attributable to the $300.0 million 

aggregate principal amount of our convertible senior notes purchased in the tender offer during the fourth quarter of 2010. This 

increase was partially offset by increased capitalized interest due to higher levels of unproved properties during 2011.

Our effective income tax rate was 44.0% for 2011 and 36.3% for 2010. The increase in the effective income tax rate is 

primarily due to prior period adjustments to state income tax provisions recorded during the fourth quarter of 2011 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 2011 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 2011 while in 2010 we had a full-cost ceiling 

test impairment of $2.7 million.

Liquidity and Capital Resources

2013 Capital Expenditure Plan and Funding 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 effect 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. We intend to finance the remainder of our 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.

Sources and Uses of Cash. Our primary use of cash is capital expenditures related to our drilling and development programs 

and, to a lesser extent, our lease and seismic data acquisition programs. For the year ended December 31, 2012, capital expenditures, 

net of proceeds 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 our joint ventures with Reliance in the Marcellus 

Shale, Avista 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 Avista Utica divestures, the Haimo joint venture, net proceeds from 

the offering of our 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 hand and cash generated by operations. Cash flows from operations are highly dependent on commodity prices 

and market conditions for oilfield services. We hedge a portion of our forecasted production to mitigate the risk of a 

decline in oil and gas prices. 

• Borrowings under our revolving credit facility. At February 25, 2013, we had no borrowings outstanding and $0.9

million in letters of credit 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 of the revolving credit 

facility, which borrowing base is currently $365.0 million, is subject to compliance with the financial covenants and 

other provisions of the 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 of approximately $187.4 million. We used substantially all of the 

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 

of Mexico located primarily in Texas and Louisiana for net proceeds of approximately $17.6 million. In October 2012, 

we sold substantially all of our interests in oil and gas properties dedicated to the Avista 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 

final post-closing adjustments. The proceeds from all the sales described above were recognized as a reduction of proved 

oil and gas properties. On February 22, 2013, we sold Carrizo UK, and all of its interest in the Huntington Field discovery, 

to Iona Energy for net proceeds of approximately $116.5 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 offering 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 ventures. 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 Avista in the Utica Shale and other parts of the 

Marcellus Shale, with GAILin the Eagle Ford Shale, and with an affiliate of Sumitomo Corporation in the Barnett Shale. 

Effective 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. We received cash proceeds of approximately $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. We 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, effective 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 of proved 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% of the joint venture acreage, respectively.’’

• Lease purchase 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 sources. We may consider sale/leaseback transactions of certain capital assets, such as our remaining pipelines 

and compressors, which are not part of our core oil and gas exploration and production business.

Overview of Cash Flow Activities. 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, 2011 and 2010, respectively. The increase was 

primarily due to increased crude oil production and oil prices, partially offset by lower gas prices in 2012 as compared to 2011. 

Net cash provided by operating activities from continuing operations increased in 2011 from 2010 due to increased production, 

particularly higher crude oil and condensate production in the Eagle Ford Shale and increased oil prices, partially offset by lower 

gas prices in 2011 as compared to 2010.

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, 2011 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 

of advances received for joint operations in 2011, partially offset by an increase in proceeds from the sale of oil and gas properties. 
50

Net cash used in investing activities from continuing operations in 2011 related primarily to capital expenditures, partially offset 

by proceeds from the sale of our non-core area Barnett Shale properties to KKR, proceeds from the sale of an interest in certain 

of our Eagle Ford Shale properties to GAILand cash distributions on our “B Units” interest in ACPII of $3.3 million. The decrease 

in investing activities from continuing operations in 2011 as compared to 2010 was due to higher proceeds from the sales of oil 

and gas properties and increase in advances for joint ventures, partially offset by increased capital expenditures during 2011.

Net cash provided by financing activities from continuing operations for the years ended December 31, 2012, 2011 and 2010

were $237.8 million, $116.8 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 offset by a decrease in net borrowings under the revolving credit 

facility during 2012 as compared to 2011. Net cash provided by financing activities from continuing operations in 2011 related 

primarily to net proceeds of $194.5 million from the issuance of an additional $200.0 million aggregate principal amount of 8.625% 

Senior Notes in November 2011, partially offset by repayment of borrowings outstanding under our revolving credit facility. The 

decrease in financing activities from continuing operations in 2011 as compared to 2010 was due the absence of common stock 

offerings and less debt issuance and borrowing during 2011.

Liquidity/Cash Flow Outlook

Economic downturns may adversely affect our ability to access capital markets in the future. We currently believe that cash 

provided by operating activities from continuing operations, the sale of assets (including our sale of the 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 sufficient to fund our immediate cash flow requirements. Cash provided 

by operating activities from continuing operations is primarily driven by production and commodity prices. While we have steadily 

increased production over the last few years, spot and futures prices of natural gas continue to remain depressed. To manage our 

exposure to commodity price risk and to provide a level of certainty in the cash flows that will support our capital expenditures 

program, we hedge a portion of our forecasted production and, as of February 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 facility is currently $365.0million. As of February 25, 2013, we had no borrowings outstanding under our revolving 

credit facility and had issued $0.9 million in letters of credit, which reduce the amounts available under our revolving credit facility. 

As of February 25, 2013, we had no borrowings outstanding under the Huntington Facility, which was repaid by Iona Energy upon 

consummation of the sale of the 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 of the credit agreement governing the revolving credit facility. The borrowing base under our revolving credit facility 

is affected 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 of 2013.

If cash 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 insufficient to fund our 

2013 capital expenditure plan, we may need to reduce our capital expenditure plan or seek other financing alternatives. We may 

not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we cannot obtain adequate 

financing, we may be required to limit or defer our planned 2013 capital expenditure plan, thereby adversely affecting the 

recoverability and ultimate value of our 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 

market or in privately negotiated transactions, through debt redemptions or tender offers, or through repayments of bank borrowings.
51

Contractual Obligations

The following table sets forth estimates of our contractual obligations as of December 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. We have the intent and ability 

to refinance our convertible senior notes on a long-term basis with the available capacity of our 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 of 3.87% 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

We currently do not have any off balance sheet arrangements.

Financing Arrangements

8.625% Senior Notes and 7.50% Senior Notes

As of December 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 of the 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 of the 8.625% Senior Notes, at redemption prices decreasing from 104.313% of the principal amount to 100%

of the principal amount on October 15, 2017, plus accrued and unpaid interest. In connection with certain equity offerings 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% of the aggregate principal amount of the 8.625% Senior Notes at a redemption price of 108.625%, of the principal amount, 

plus accrued and unpaid interest, if any, to the redemption date using the net cash proceeds of such equity offerings. Prior to 

October 15, 2014, we may redeem all or part of the 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, we may be required by holders to repurchase the 

8.625% Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus any accrued but unpaid interest.
52

On September 10, 2012, the Company issued in a public offering $300.0 million aggregate principal amount of 7.50% 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% Senior Notes mature on September 15, 2020, with interest payable 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 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 offerings 

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% of the aggregate principal amount of the 7.50% Senior Notes at a redemption price of 107.500%, of the principal amount, 

plus accrued and unpaid interest, if any, to the redemption date using the net cash proceeds of such equity offerings. Prior to 

September 15, 2016, we may redeem all or part of the 7.50% 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 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% of the 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 of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of our assets; enter 

into agreements that restrict distributions or other payments from our restricted subsidiaries to us; engage in transactions with 

affiliates; and create unrestricted subsidiaries.

The indentures governing the 8.625% Senior Notes and the 7.50% Senior Notes are subject to customary events of default, 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 final judgments.

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. We may redeem 

notes at any time on or after June 1, 2013 at a redemption price equal to 100% of the principal amount of the notes to be redeemed 

plus accrued and unpaid interest, if any.

While the holders of the 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 of our 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

We have a senior secured revolving credit facility that permits us to borrow up to the lesser of (i) the borrowing base (as 

defined in the 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 of our 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 of the 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 of the borrowing base, we have 

the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment 

curing the deficiency, deliver reserve engineering reports and mortgages covering additional oil and gas properties sufficient in 

the lenders’ opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments 

that will cure the deficiency within the next six-month period. Upon certain adjustments to the borrowing base, we are required 

to make a lump sum payment in an amount equal to the amount by which the outstanding principal balance of the revolving loans 

and the aggregate face amount of all letters of credit under the revolving credit facility exceeds the borrowing base. Otherwise, 

any unpaid principal will be due at maturity.

The annual interest rate on each base rate borrowing is (a) the greatest of the Agent’s Prime Rate, the Federal Funds Effective 

Rate plus 0.5% and the adjusted LIBO rate for a three-month interest period on such day plus 1.00%, plus (b) a margin between 

1.00% and 2.00% (depending on the then-current level of borrowing base usage). The interest rate on each Eurodollar loan will 

be the adjusted LIBO rate for the applicable interest period plus a margin between 2.00% to 3.00% (depending on the then-current 

level of borrowing base usage).

We 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 of Total 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 of additional senior notes, including those issued in the September 2012 notes offering. 

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

We are subject to certain covenants under the terms of the revolving credit facility, as amended, which include, but are not 

limited to, the maintenance of the following financial covenants: (1) a ratio Total 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 of EBITDA to Interest Expense of not less than 2.50 to 1.00 (each of the 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 

Total 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 EBITDAto Interest Expense ratio was 5.19 to 1.00. Total Debt and Senior Debt, as defined in the 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 of our common stock, redemptions 

of our senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and 

other matters.

Our revolving credit facility is subject to customary events of default, including a change in control (as defined in the credit 

agreement governing our revolving credit facility). If an event of default occurs and is continuing, the Majority Lenders (as defined 

in the credit agreement governing the revolving credit facility) may accelerate amounts due under the revolving credit facility 

(except for a bankruptcy event of default, in which case such amounts will automatically become due and payable).

At December 31, 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 of oil and gas properties and securities offerings. 

The revolving credit facility may also be used to repurchase our convertible senior notes.

Huntington Field Development Project Credit Facility

On January 28, 2011, we and Carrizo UK, as borrower, entered into the Huntington Facility. The Huntington Facility was 

secured by substantially all of Carrizo 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 of Carrizo UK, and all of its 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 of the sales transaction. As of December 31, 2012 and February 22, 2013, borrowings outstanding under 

the Huntington Facility were $52.0 million 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 of 3.79% and no letters of credit had been 

issued. 

Securities Offerings in 2012, 2011 and 2010

In September 2012, we issued in a public offering $300.0 million aggregate principal amount of 7.50% Senior Notes. We 

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 2011, we issued $200.0 million aggregate principal amount of 8.625% Senior Notes in a private placement 

exempt from the registration requirements of the Securities Act of 1933, as amended. We used the net proceeds of approximately 

$194.5 million after deducting initial purchasers’ discounts and our estimated expenses, to repay a substantial portion of the 

borrowings then outstanding under our revolving credit facility. In February 2012, we completed an exchange offer and issued 

new notes and guarantees having substantially identical terms, but registered with the SEC, in exchange for all such privately 

issued 8.625% Senior Notes. The $200.0 million of 8.625% Senior Notes issued in November 2011 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 of the Securities Act. We used the net proceeds of approximately $387.5 million after 

deducting initial purchasers’ discounts and our estimated expenses, to repay initially in full borrowings outstanding under our 

prior credit facility and held the remaining net proceeds in short-term investments. We subsequently purchased the $300.0 million 

of convertible senior notes in the tender offer with a combination of cash on hand and borrowings under our prior credit facility. 

In June 2011, we completed an exchange offer and issued new notes and guarantees having substantially identical terms, but 

registered with the SEC, in exchange for all such privately issued 8.625% Senior Notes.

In December 2010, we sold 3.975 million shares of our common stock in an underwritten public offering at a price to the 

underwriter of $28.90 per share. We used the net proceeds of approximately $114.9 million to repay a portion of the outstanding 

borrowings under our prior credit facility.

In April 2010, we sold 3.22 million shares of our common stock in an underwritten public offering at a price to the underwriter 

of $23.00 per share. We used the net proceeds of approximately $73.8 million to repay a portion of the then-outstanding borrowings 

under a prior credit facility.

Lease Purchase Option Arrangements

From time to time, we have entered into lease purchase option arrangements with third parties. In 2011, we utilized one lease 

purchase option arrangement described below with an unrelated third party. Strategically, such leasing arrangements have allowed 

us to temporarily control important acreage positions during periods that we have lacked sufficient capital to directly acquire such 

oil and gas leases. We may continue to use these arrangements as a strategic alternative in the future.

On November 24, 2009, we entered into a land agreement 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 affiliate. The land agreement expired by its terms on May 31, 2011. In consideration of our receipt of an option to purchase the 

leases acquired by the third party (as described below), we issued to the third party’s affiliate warrants to purchase a certain number 

of shares of our common. See “Item 5. Market for Registrant’s Common Stock, Related Shareholder Matters and Issuer Purchases 

of Equity 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 affected by changing oil and gas prices. Although natural gas prices have 

significantly declined since mid-2008 and the price of natural gas remains depressed, our revenue per unit of production increased 

in 2012 as a result of increased crude oil production and oil prices. Historically, inflation has had a minimal effect on us. However, 

with interest rates at historic lows and the government attempting to stimulate the economy through rapid expansion of the money 

supply in recent years, inflation could become a significant issue in the future.
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” of the Notes to our Consolidated Financial Statements.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires 

management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of 

contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during 

the periods reported. Actual results could differ from these estimates. We evaluate subsequent events through the date the financial 

statements are issued.

Significant estimates include volumes of proved oil and gas reserves which are used in calculating the amortization of proved 

oil and gas property costs, the present value of future net revenues included in the full cost ceiling test, estimates of future taxable 

income used in assessing the realizability of deferred tax assets, and asset retirement obligations. Other significant estimates 

include the, impairment of unproved properties, fair values of derivative instruments, stock-based compensation, the collectability 

of outstanding receivables, and contingencies. Proved oil and gas reserve estimates have numerous inherent uncertainties. The 

accuracy of any reserve estimate is a function of the quality and quantity of available data and the application of engineering and 

geological interpretation and judgment to available data. Subsequent drilling results, testing and production may justify revisions 

of such estimates. Accordingly, proved oil and gas reserve estimates are often different from the quantities of oil and gas that are 

ultimately recovered. In addition, proved oil and gas reserve estimates are vulnerable to changes in market prices of oil and gas. 

Such prices have been volatile in the past and can be expected to be volatile in the future.

Estimates are based on current assumptions that may be materially affected by changes to future economic conditions such 

as the market prices of oil and gas, the credit worthiness of counterparties, interest rates and the market value and volatility of our 

common stock. Future changes in these assumptions may affect these significant estimates materially in the near term.

Discontinued Operations

On December 27, 2012, we agreed to sell Carrizo UK, a wholly owned subsidiary of the Company, and all of its 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. We 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 of the 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)” of the Notes to our Consolidated Financial Statements.

Oil and Gas Properties

Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive 

costs directly associated with property acquisition, exploration and development activities are capitalized to costs centers 

established on a country-by-country basis. Internal costs directly identified with acquisition, exploration and development activities 

are capitalized and totaled $11.8 million, $9.6 million and $5.3 million for the years ended December 31, 2012, 2011 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 of one barrel of oil or natural gas liquids to six thousand cubic 

feet of gas, which represents their approximate relative energy content. The equivalent unit-of-production rate is computed on a 

quarterly basis by dividing production by proved oil and gas reserves at the beginning of the quarter which is applied to capitalized 

oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated 

future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average 

DD&A per Boe was $17.55, $11.26 and $7.67 for the years ended December 31, 2012, 2011 and 2010, respectively.

Costs not subject to amortization include unevaluated leasehold and seismic costs associated with specific unevaluated 

properties, the cost of exploratory 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 not 
56

held by production and drilling capital expenditure plans. We expect to complete the evaluation of the majority of our unproved 

properties within the next two to five years. Insignificant costs are grouped by major area and added to the oil and gas property 

costs subject to amortization based on the average primary lease terms of the properties. We capitalized interest costs associated 

with our unevaluated leasehold and seismic costs and exploratory wells in progress of $24.8 million, $23.4 million and $20.7 

million for the years ended December 31, 2012, 2011 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 effects. If the net capitalized costs exceed the cost center ceiling, 

the excess is recognized as an impairment of oil and gas properties. An impairment recognized in one period may not be reversed 

in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period.

The 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 average realized market prices on the first calendar day of each month during the 12-month period 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 Average 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 $111.21 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, 2011 by approximately 

$202.6 million and was based on crude oil and condensate prices of $92.76 per barrel, natural gas liquids prices of $44.90 per 

barrel and natural gas prices of $3.21 per Mcf, representing the unweighted average realized market prices on the first calendar 

day of each month during the 12-month period ended December 31, 2011. A ten percent increase in average market prices at 

December 31, 2011 would have increased the cost center ceiling by approximately $163.4 million and a ten percent decrease in 
57

average market prices would have caused an impairment of approximately $24.4 million. This sensitivity analysis is as of 

December 31, 2011 and, accordingly, does not consider drilling results, production and prices subsequent to December 31, 2011 

that may require revisions of proved reserve estimates.

The cost center ceiling exceeded our net capitalized costs for the U.K. cost center at December 31, 2011 by approximately 

$124.5 million and was based on crude oil and condensate prices of $106.90 per barrel and natural gas prices of $7.54 per Mcf, 

representing the unweighted average realized market prices on the first calendar day of each month during the 12-month period 

ended December 31, 2011. A ten percent increase in average market prices at December 31, 2011 would have increased the cost 

center ceiling by approximately $19.0 million and a ten percent decrease in average market prices would have decreased the cost 

center ceiling by approximately $19.0 million. This sensitivity analysis is as of December 31, 2011 and, accordingly, does not 

consider drilling results, production and prices subsequent to December 31, 2011 that may require revisions of proved reserve 

estimates.

We have a significant amount of proved undeveloped reserves. We had 62.5 MMBoe, 79.9 MMBoe and 73.0 MMBoe of 

proved undeveloped reserves, representing 52%, 51% and 52% of our total proved reserves at December 31, 2012, 2011 and 2010, 

respectively. Approximately 34.5 MMBoe, or 55%, and 22.5 MMBoe, or 36%, of our proved undeveloped reserves at December 31, 

2012, are attributable to the Eagle Ford Shale and Barnett Shale, respectively. We currently expect to drill wells associated with 

these undeveloped reserves within the next five years.

Because our depletion rate is based on the ratio of production to total proved reserves, we expect our relatively low historical 

depletion rate to continue until the level of undeveloped reserves in relation to total proved reserves is reduced through the 

development of existing undeveloped reserves or the significant addition of proved developed reserves through acquisition or 

exploration. If our level of total proved reserves and future development costs were to remain constant and average market prices 

were to decline, a lower depletion rate would result in an impairment of oil and gas properties earlier or to a larger extent than 

would a higher depletion rate.

Oil and Gas Reserve Estimates

Over 99% of the proved oil and gas reserve estimates as of December 31, 2012 included in this document have been prepared 

by Ryder Scott Company Petroleum Engineers and LaRoche Petroleum Consultants, Ltd., independent third party reserve engineers. 

Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured 

in an exact manner. The process relies on judgment and the interpretation of available geologic, geophysical, engineering and 

production data. The extent, quality and reliability of this data can vary. The process also requires assumptions regarding drilling 

and operating costs, taxes and availability of funds. The oil and gas reserve estimation and disclosure requirements mandate certain 

of these assumptions such as existing economic and operating conditions, average oil and gas prices and the discount rate.

Proved oil and gas reserve estimates prepared by others may be substantially higher or lower than our estimates. Significant 

assumptions used by the independent third party reserve engineers are assessed by our internal reserve team. All reserve reports 

prepared by the independent third party reserve engineers are reviewed by our senior management team, including the Chief 

Executive Officer and Chief Operating Officer. Because these estimates depend on many assumptions, all of which may differ 

from actual results, reserve quantities actually recovered may be significantly different than estimated. Material revisions to reserve 

estimates may be made depending on the results of drilling, testing, and production.

You should not assume that the present value of future net cash flows is the current market value of our estimated proved 

oil and gas reserves. In accordance with the oil and gas reserve estimation and disclosure requirements, the discounted future net 

cash flows from proved reserves are based on the unweighted average of the first day of the month price for each month in the 

previous twelve-month period, using current costs and a 10% discount rate.

Our depletion rate depends on our estimate of total proved reserves. If our estimates of total proved reserves increased or 

decreased, the depletion rate and therefore DD&A expense would decrease or increase, respectively. A 10% increase or decrease 

in our estimates of total proved reserves at December 31, 2012, would have decreased or increased our DD&A expense by 

approximately 8.9% or 10.9%, respectively, for the fourth quarter of 2012.

Derivative Instruments

We use derivative instruments, typically fixed-rate swaps, costless collars, puts, calls and basis differential swaps, to manage 

commodity price risk associated with a portion of our forecasted oil and gas production. Derivative instruments are recognized at 

their current fair value as assets or liabilities in the consolidated balance sheets. Although the derivative instruments provide an 

economic hedge of our exposure to commodity price risk associated with oil and gas production, because we elect not to meet the 

criteria to qualify our derivative instruments for hedge accounting treatment, unrealized gains and losses as a result of changes in 

the fair value of derivative instruments are recognized as gain (loss) on derivative instruments, net in the consolidated statements 

of income. Realized gains and losses as a result of cash settlements with counterparties to our derivative instruments are also 
58

recorded as gain (loss) on derivative instruments, net in the consolidated statements of income. We offset fair value amounts 

recognized for derivative instruments executed with the same counterparty and subject to master netting agreements.

Our Board of Directors establishes risk management policies and reviews derivative instruments, including volumes, types 

of instruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only by the 

President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and Chairman 

of the Board. The master contracts with approved counterparties identify the President and Chief Financial Officer as the only 

Company representatives authorized to execute trades.

Income Taxes

Deferred income taxes are recognized at each reporting period for the future tax consequences of differences between the 

tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the 

periods in which the differences are expected to affect taxable income. We routinely assess the realizability of our deferred tax 

assets and consider our estimate of future taxable income based on production of proved reserves at estimated future pricing in 

making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not 

be realized, the deferred tax assets are reduced by a valuation allowance. We classify interest and penalties associated with income 

taxes as interest expense.

Commitments and Contingencies

Liabilities are recognized for contingencies when (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.

Volatility of Oil and Gas Prices

Our revenues, future rate of growth, results of operations, financial position and ability to borrow funds or obtain additional 

capital are substantially dependent upon prevailing prices of oil and gas.

We review the carrying value of our oil and gas properties on a quarterly basis using the full cost method of accounting. See 

“ —Summary of Critical Accounting Policies—Oil and Gas Properties.”

We 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 and basis differential swaps. Under these derivative instruments, payments are received 

or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at termination, 

expiration or exchanged for physical delivery contracts. Our current long-term strategy is to manage exposure for a substantial, 

but varying, portion of forecasted production up to 60months. The derivative instruments are carried at fair value in the 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 of derivative instruments at December 31, 2012 and 2011 was a net asset of $29.2 million and $37.5 million, 

respectively. The following sets forth a summary of the 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%

Total 100% 100%

Master netting agreements are in place with each of these counterparties. Because the counterparties are either investment 

grade financial institutions or an investment grade international oil and gas company, we believe we have minimal credit risk and 

accordingly do not currently require our counterparties to post collateral to support the asset positions of our derivative instruments. 

As such, we are exposed to credit risk to the extent of nonperformance by the counterparties to our derivative instruments. Although 

we do not currently anticipate such nonperformance, we continue to monitor the financial viability of our counterparties. Because 
59

Credit Suisse, Credit Agricole, BBVA Compass, Wells 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 of our U.S. natural gas derivative positions at average NYMEX prices as of December 31, 

2012.

Period

Volume

(in MMBtu)

Weighted

Average

Floor Price

($/MMBtu)

Weighted

Average

Ceiling Price

($/MMBtu)

2013 18,250,000 $ 4.63 $ 4.63

2014 3,650,000 $ — $ 5.50

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

2012.

Period

Volume

(in Bbls)

Weighted

Average

Floor Price

($/Bbls)

Weighted

Average

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

Volume

(in Bbls)

Weighted

Average

Short Put Price

($/Bbls)

Weighted

Average

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, 2011 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 of natural gas. The 

effects of such pricing volatility have been discussed above, and such volatility is expected to continue. A 10% fluctuation in the 

price received for oil and gas production would have an approximate $35.8 million impact on our revenues for the year ended 

December 31, 2012.

We 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 we typically use include 

fixed-rate swaps, costless collars, puts, calls and basis differential swaps. Our current long-term strategy is to manage exposure 

for a substantial, but varying, portion of forecasted production up to 60 months. We do not hold or issue derivative instruments 
60

for trading purposes. We recorded gains on derivative instruments, net of $31.4 million, $48.4 million and $47.8 million for the 

years ended December 31, 2012, 2011, 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 of cash and cash equivalents, receivables, and payables approximate fair value 

due to the highly liquid or short-term nature of these instruments. The fair values of borrowings 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 of December 31, 2012, scheduled maturities of long-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 of this Annual Report on 

Form 10-K.

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

None.

Item 9A. Controls and Procedures

(a) Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required 

to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission (the “SEC”) under the 

Securities Exchange Act of 1934, as amended (the “Exchange Act”), is recorded, processed, summarized and reported within the 

time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to our management, 

including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required 

disclosure.

In accordance with Rules 13a-15(b) and 15d-15(b) under the Exchange Act, we carried out an evaluation, under the 

supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the 

effectiveness of our disclosure controls and procedures (as defined by Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as 

of the end of the period covered by this Annual Report on Form 10-K. As described below under paragraph (b) within Management’s 

Annual Report on Internal Control over Financial Reporting, our Chief Executive Officer and Chief Financial Officer have 

concluded that, as of the end of the period covered by this Annual Report on Form 10-K, our disclosure controls and procedures 

were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit 

to the SEC under the Exchange Act is recorded, processed, summarized and reported within the time periods specified by the 

SEC’s rules and forms and that such information is accumulated and communicated to our management, including our Chief 

Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

The audit report of KPMG, LLP, which is included in this Annual Report on Form 10-K, expressed an unqualified opinion 

on our consolidated financial statements.

(b) Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined 

in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide 

reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes 

in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies 

and procedures that:

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

dispositions of our assets;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements 

in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only 

in accordance with authorizations of our management and directors; and

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition 

of our assets that could have a material effect on the financial statements.
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 of fraud. Controls 

are susceptible to manipulation, especially in instances of fraud caused by collusion of two or more people, including our senior 

management. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become 

inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, our management 

conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2012. In making 

this evaluation, management used the Internal Control – Integrated Framework issued by the Committee of Sponsoring 

Organizations of the Treadway Commission (“COSO”). Based on the results of our evaluation, our management concluded that 

our internal control over financial reporting was effective as of December 31, 2012.

KPMG LLP, our independent registered public accounting firm that audited our consolidated financial statements, has also 

issued its own attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2012, 

which is filed with this Annual Report on Form 10-K.

(c) Changes in Internal Control over Financial Reporting

There have not been any changes in our internal control over financial reporting during the fiscal quarter ended December 31, 

2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.
62

PART 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 of shareholders. 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 Transactions, 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

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)(1) Financial Statements

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

(a)(2) Financial Statement Schedules

None.

(a)(3) Exhibits

EXHIBIT INDEX

Exhibit 

Number Description

†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 of Amendment to Amended and Restated Articles of Incorporation (incorporated herein by 

reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 25, 2008).

†3.3 — Amended and Restated Bylaws of the Company (incorporated herein by reference to Exhibit 3.1 to the 

Company’s Current Report on Form 8-K filed on January 3, 2008).

†4.1 — Indenture among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National 

Association, as trustee, dated May 28, 2008 (incorporated herein by reference to Exhibit 4.1 to the 

Company’s Current Report on Form 8-K filed on May 28, 2008).

†4.2 — First Supplemental Indenture dated May 28, 2008 between Carrizo Oil & Gas, Inc. and Wells Fargo 

Bank, National Association, as trustee (incorporated herein by reference to Exhibit 4.2 to the 

Company’s Current Report on Form 8-K filed on May 28, 2008).

†4.3 — Second Supplemental Indenture dated May 14, 2009 among Carrizo Oil & Gas, Inc., the subsidiaries 

named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein by reference 

to Exhibit 4.21 to the Company’s Registration Statement on Form S-3 (Registration No. 333-159237)).

†4.4 — Fourth Supplemental Indenture dated November 2, 2010 among Carrizo Oil & Gas, Inc. the subsidiary 

guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein 

by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed on November 2, 2010).

†4.5 — Fifth Supplemental Indenture dated November 2, 2010 among Carrizo Oil & Gas, Inc. the subsidiary 

guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein 

by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on November 2, 2010).

†4.6 — Sixth Supplemental Indenture dated May 4, 2011 among Carrizo Oil & Gas, Inc. the subsidiary 

guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein 

by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the quarter ended 

March 31, 2011).

†4.7 — Seventh Supplemental Indenture dated May 4, 2011 among Carrizo Oil & Gas, Inc. the subsidiary 

guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein 

by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for the quarter ended 

March 31, 2011).

†4.8 — Eighth Supplemental Indenture dated August 5, 2011 among Carrizo Oil & Gas, Inc. the subsidiary 

guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein 

by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended 

June 30, 2011).

†4.9 — Ninth Supplemental Indenture dated August 5, 2011 among Carrizo Oil & Gas, Inc. the subsidiary 

guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated herein 

by reference to Exhibit 4.4 to the Company’s Quarterly Report on Form 10-Q for the quarter ended 

June 30, 2011).
64

†4.10 — Tenth Supplemental Indenture among Carrizo Oil & Gas, Inc., the Subsidiary Guarantors named therein 

and Wells 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 Wells Fargo Bank, National Association, as trustee 

(incorporated herein by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for 

the quarter ended September 30, 2012).

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

subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee 

(incorporated herein by reference to Exhibit 4.2 to the Company’s Quarterly Report on Form 10-Q for 

the quarter ended September 30, 2012).

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

subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee 

(incorporated herein by reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for 

the quarter ended September 30, 2012).

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

subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee 

(incorporated herein by reference to Exhibit 4.4 to the Company’s Quarterly Report on Form 10-Q for 

the quarter ended September 30, 2012).

†4.15 — Officers’ Certificate of the Company dated as of November 17, 2011 (incorporated herein by reference 

to Exhibit 4.5 to the Company’s Current Report on Form 8-K filed on November 17, 2011).

†4.16 — Form of Warrant issued pursuant to Land Agreement dated November 24, 2009 (incorporated herein by 

reference to Exhibit 4.3 to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 

31, 2011)

*†10.1 — Amended and Restated Incentive Plan of the Company effective as of April 30, 2009 (incorporated 

herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 6, 

2009).

*†10.2 — 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 Award Agreement (incorporated herein by reference to Exhibit 10.43 to the 

Company’s Annual Report on Form 10-K for the year ended December 31, 2004).

*†10.10 — Form of Director Restricted Stock Award Agreement under the Incentive Plan of Carrizo Oil & Gas, 

Inc. (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K 

filed on April 22, 2005).
65

*†10.11 — Form of Director Restricted Stock Award Agreement under the Incentive Plan of Carrizo Oil & Gas, 

Inc. (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K 

filed on April 22, 2005).

*†10.12 — Form of Employee Restricted Stock Award Agreement under the Incentive Plan of Carrizo Oil & Gas, 

Inc. (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K 

filed on April 22, 2005).

*†10.13 — Form of 2010 Employee Restricted Stock Unit Award Agreement (with performance-based vesting and 

time-based vesting) (incorporated herein by reference to Exhibit 10.12 to the Company’s Annual Report 

on Form 10-K for the year ended December 31, 2010).

*†10.14 — Form of 2009 Employee Restricted Stock Unit Award Agreement (with performance-based vesting 

only) (incorporated herein by reference to Exhibit 10.8 to the Company’s Current Report on Form 8-K 

filed on June 9, 2009).

*†10.15 — Form of 2010 Employee Cash Settled Stock Appreciation Rights Award Agreement under the Carrizo 

Oil & Gas, Inc. Incentive Plan (incorporated herein by reference to Exhibit 10.14 to the Company’s 

Annual Report on Form 10-K for the year ended December 31, 2010).

*†10.16 — Form of 2009 Employee Cash or Stock Settled Stock Appreciation Rights Award Agreement under the 

Carrizo Oil & Gas, Inc. Incentive Plan (incorporated herein by reference to Exhibit 10.9 to the 

Company’s Current Report on Form 8-K filed on June 9, 2009).

*†10.17 — 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 Award Agreement pursuant to the 

Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (incorporated herein by reference 

to Exhibit 10.11 to the Company’s Current Report on Form 8-K filed on June 9, 2009).

*†10.19 — Form of Independent Contractor Restricted Stock Award Agreement (incorporated herein by reference 

to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on May 30, 2006).

*†10.20 — Form of Employee Restricted Stock Award Agreement (with performance-based vesting) (incorporated 

herein by reference to Exhibit 10.6 to the Company’s Current Report on Form 8-K filed on December 

23, 2008).

†10.21 — S Corporation Tax Allocation, Payment and Indemnification Agreement among the Company and 

Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (incorporated herein by reference to Exhibit 

10.8 to the Company’s Registration Statement on Form S-1 (Registration No. 333-29187)).

†10.22 — S Corporation Tax Allocation, Payment and Indemnification Agreement among Carrizo Production, 

Inc. and Messrs. Loyd, Webster, Johnson, Hamilton and Wojtek (incorporated herein by reference to 

Exhibit 10.9 to the Company’s Registration Statement on Form S-1 (Registration No. 333-29187)).

†10.23 — Amended and Restated Registration Rights Agreement dated December 15, 1999 among the Company, 

Paul B. Loyd Jr., Douglas A. P. Hamilton, Steven A. Webster, S.P. Johnson IV, Frank A. Wojtek and 

DAPHAM Partnership, L.P. (incorporated herein by reference to Exhibit 99.5 to the Company’s 

Current Report on Form 8-K filed December 22, 1999).

†10.24 — Registration Rights Agreement dated February 20, 2002 among the Company, Mellon Ventures, L.P. 

and Steven A. Webster (incorporated herein by reference to Exhibit 99.5 to the Company’s Current 

Report on Form 8-K filed February 27, 2002).

†10.25 — Credit Agreement dated as of January 27, 2011 among Carrizo Oil & Gas, Inc., as Borrower, BNP

Paribas, as Administrative Agent, Credit Agricole Corporate and Investment Bank and Royal Bank of 

Canada, as Co-Syndication Agents, Capital One, N.A. and Compass Bank, as Co-Documentation 

Agents, BNP Paribas Securities Corp. as Sole Lead Arranger and Sole Bookrunner, and the Lenders 

party thereto (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on 

Form 8-K filed on February 2, 2011).

†10.26 — First Amendment, dated as of March 26, 2012, to Credit Agreement dated as of January 27, 2011, 

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, Wells 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, Wells 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, 2011 among Carrizo 

UK Huntington Ltd., as Borrower, Carrizo Oil & Gas, Inc., as Parent, and BNP Paribas and Societe 

Generale as Lead Arrangers, Bookrunners and Original Lenders (incorporated herein by reference to 

Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on February 2, 2011).

†10.30 — First Amendment, entered into as of April 17, 2012, to Senior Secured Multicurrency Credit Facility 

Agreement dated as of January 28, 2011, 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 

officers (incorporated herein by reference to Exhibit 10.6 to the Company’s Annual Report on Form 10-

K for the year ended December 31, 1997).

†10.32 — Form of Amendment to Director Indemnification Agreement (incorporated herein by reference to 

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

†10.33 — Omnibus Amendment among Carrizo (Marcellus) LLC, Carrizo Oil & Gas, Inc., Avista Capital 

Partners II, L.P. and ACP II Marcellus LLC, dated as of September 10, 2010 (incorporated herein by 

reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on September 16, 2010).

†10.34 — Amended and Restated Participation Agreement, dated as of November 16, 2010, and effective as of 

October 1, 2010, among Carrizo (Marcellus) WV LLC, Carrizo Oil & Gas, Inc., Avista Capital Partners 

II, L.P. and ACP II Marcellus LLC (incorporated herein by reference to Exhibit 10.1 to the Company’s 

Current Report on Form 8-K filed on November 19, 2010).

21.1 — Subsidiaries of the Company.

23.1 — Consent of KPMG LLP.

23.2 — Consent of LaRoche Petroleum Consultants, Ltd.

23.3 — Consent of Ryder Scott Company, L.P. (U.S.).

23.4 — Consent of Ryder 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 Ryder Scott Company, L.P. as of December 31, 2012 (U.S.).

99.3 — Summary of Reserve Report and Report of Ryder 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 CONSOLIDATED FINANCIAL STATEMENTS

PAGE

Reports of Independent Registered Public Accounting Firm

Consolidated Balance Sheets, December 31, 2012 and 2011

Consolidated Statements of Income for the Years Ended December 31, 2012, 2011 and 2010

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010

Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010

Notes to Consolidated Financial Statements

F-2

F-4

F-5

F-6

F-7

F-8
F-2

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Carrizo Oil & Gas, Inc.:

We have audited the accompanying consolidated balance sheets of Carrizo Oil & Gas, Inc. and subsidiaries (the Company) as of 

December 31, 2012 and 2011, 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. These consolidated financial statements are the responsibility of the 

Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). 

Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements 

are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures 

in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by 

management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable 

basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position 

of Carrizo Oil & Gas, Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash 

flows for each of the years in the three-year period ended December 31, 2012, in conformity with generally accepted accounting 

principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), 

Carrizo Oil & Gas, Inc.’s internal control over financial reporting as of December 31, 2012, based on criteria established in Internal 

Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), 

and our report dated February 27, 2013 expressed an unqualified opinion on the effectiveness of the Company’s internal control 

over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 27, 2013
F-3

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Carrizo Oil & Gas, Inc.:

We have audited Carrizo Oil & Gas Inc.’s internal control over financial reporting as of December 31, 2012, based on criteria 

established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway 

Commission (COSO). Carrizo Oil & Gas Inc.’s management is responsible for maintaining effective internal control over financial 

reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying 

Management’s Report on Internal Control over Financial Reporting as presented within Item 9A. Controls and Procedures. Our 

responsibility is to express an opinion on Carrizo Oil & Gas, Inc.’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 

Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control 

over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control 

over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating 

effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we 

considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Acompany’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability 

of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted 

accounting principles. Acompany’s internal control over financial reporting includes those policies and procedures that (1) pertain 

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

of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial 

statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are 

being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable 

assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that 

could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, 

projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because 

of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Carrizo Oil & Gas, Inc. maintained, in all material respects, effective internal control over financial reporting as 

of December 31, 2012, based on criteria established in Internal Control – Integrated Framework issued by the COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 

consolidated balance sheets of Carrizo Oil & Gas, Inc. and subsidiaries as of December 31, 2012 and 2011, 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, Texas

February 27, 2013
F-4

CARRIZO OIL & GAS, INC.

CONSOLIDATED 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

PROPERTY 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

TOTAL PROPERTY 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 VALUE OF DERIVATIVE INSTRUMENTS 5,180 9,617

DEFERRED INCOME TAXES 21,272 53,517

OTHER ASSETS 2,102 1,657

TOTAL 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 for joint 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 ASSOCIATED WITH ASSETS HELD FOR SALE 23,547 22,429

ASSET RETIREMENT OBLIGATIONS 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 2011, respectively) 402 395

Additional paid-in capital 667,096 647,429

Accumulated deficit (82,482) (137,969)

Total shareholders’ equity 585,016 509,855

TOTAL 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.

CONSOLIDATED STATEMENTS 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 AVERAGE COMMON SHARES OUTSTANDING

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.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

Common Stock Additional

Paid-in

Capital

Accumulated

Deficit

Total

Shareholders’

Shares Amount Equity

(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.

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31,

2012 2011 2010

(In thousands)

CASH FLOWS FROM OPERATING 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 operating 

activities-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 3,097

Changes 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

NET INCREASE IN CASH AND CASH EQUIVALENTS FROM CONTINUING OPERATIONS

25,698 22,269 291

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS FROM 

DISCONTINUED OPERATIONS (1,196) 1,715 —

CASH AND CASH EQUIVALENTS, beginning of year - continuing operations 26,397 4,128 3,837

CASH AND CASH EQUIVALENTS, end of year - continuing operations $ 52,095 $ 26,397 $ 4,128

CASH AND CASH EQUIVALENTS, beginning of year - discontinued operations 1,715 — —

CASH AND CASH EQUIVALENTS, end of year - discontinued operations $ 519 $ 1,715 $ —

SUPPLEMENTAL 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 CONSOLIDATED FINANCIAL STATEMENTS

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 Texas, the Niobrara Formation in Colorado, the Marcellus Shale in Pennsylvania, the Barnett Shale in 

North Texas, and the Utica Shale in Ohio.

2. Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

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 effect 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 of its 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 of operations and cash flows have been 

classified as discontinued operations, net of income taxes, in the consolidated statements of income, statements of cash 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 of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that 

affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial 

statements and the reported amounts of revenues and expenses during the periods reported. Actual results could differ from these 

estimates. The Company evaluates subsequent events through the date the financial statements are issued.

Volumes 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 of future net revenues included in the full cost ceiling test, estimates of future taxable 

income used in assessing the realizability of deferred tax assets, and asset retirement obligations. Other significant estimates 

include the impairment of unproved properties, fair values of derivative instruments, stock-based compensation, the collectability 

of outstanding receivables, and contingencies. Proved oil and gas reserve estimates have numerous inherent uncertainties. The 

accuracy of any reserve estimate is a function of the quality and quantity of available data and the application of engineering and 

geological interpretation and judgment to available data. Subsequent drilling results, testing and production may justify revisions 

of such estimates. Accordingly, proved oil and gas reserve estimates are often different from the quantities of oil and gas that are 

ultimately recovered. In addition, proved oil and gas reserve estimates are vulnerable to changes in average market prices of oil 

and gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

Estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the 

market prices of oil and gas, the creditworthiness of counterparties, interest rates and the market value and volatility of the 

Company’s common stock. Future changes in these assumptions may affect these significant estimates materially in the near term.
F-9

Cash and Cash Equivalents

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

Accounts Receivable and Allowance for Doubtful Accounts

The Company establishes an allowance for doubtful accounts when it determines that it will not collect all or a part of an accounts 

receivable balance. The Company assesses the collectability of its accounts receivable on a quarterly basis and adjusts the allowance 

as necessary using the specific identification method. A roll forward of the allowance for doubtful accounts is as follows:

Amount

(In thousands)

January 1, 2010 $ 2,036

Charged to general and administrative 485

Amounts written off (51)

December 31, 2010 2,470

Charged to general and administrative 31

Amounts written off (197)

December 31, 2011 2,304

Recoveries included in general and administrative (737)

Amounts written off (208)

December 31, 2012 $ 1,359

Concentration of Credit Risk

Substantially all of the 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 of customers and joint interest owners may impact the Company’s overall credit risk in that 

these entities may be similarly affected by changes in economic and other industry conditions. The Company does not require 

collateral from its customers. The Company generally has the right to offset revenue against related billings to joint interest owners.

Derivative instruments subject the Company to a concentration of credit risk. See “Note 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% of the Company’s oil and gas 

revenues. For the years ended December 31, 2011 and 2010, one customer accounted for approximately 43% and 63%, respectively, 

of the 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 $11.8 million, $9.6 million, and $5.3 million

for the years ended December 31, 2012, 2011 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 of one barrel of oil or natural gas liquids to six thousand cubic feet of gas, 

which represents their approximate relative energy content. The equivalent unit-of-production rate is computed on a quarterly 

basis by dividing production by proved oil and gas reserves at the beginning of the quarter then applying such amount to capitalized 

oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated 

future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average 

depreciation, depletion and amortization (“DD&A”) per Boe was $17.55, $11.26, and $7.67 for the years ended December 31, 

2012, 2011 and 2010, respectively.

Unproved properties, which are not amortized, include unevaluated leasehold and seismic costs associated with specific unevaluated 

properties, the cost of exploratory wells in progress, and related capitalized interest. Significant costs of unevaluated properties 
F-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 exploratory wells in progress of $24.8 million, $23.4 million, and $20.7 million for the years ended December 

31, 2012, 2011 and 2010, respectively. Interest is capitalized on the average balance of unevaluated leasehold and seismic costs 

and the average balance of exploratory 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 of properties not subject to amortization, and (C) the lower of cost or estimated fair value of unproved properties included 

in the costs being amortized; less (ii) related income tax effects. If the net capitalized costs exceed the cost center ceiling, the 

excess is recognized as an impairment of oil and gas properties. An impairment recognized in one period may not be reversed in 

a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period.

The estimated future net revenues used in the ceiling test are calculated using average quoted market prices for sales of oil and 

gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period. 

Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable 

contracts for the remaining term of those contracts. Prices used in the ceiling test computation do not include the impact of derivative 

instruments because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting 

treatment.

Depreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives ranging 

from five to ten years.

Deferred Financing Costs

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 2011, 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 

with revolving credit facilities. The capitalized costs are amortized to interest expense, net of amounts capitalized using the effective 

interest method over the terms of the 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 of cash and cash equivalents, receivables, payables, derivative instruments and longterm debt. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value due to the highly 

liquid or short-term nature of these instruments. The fair values of derivative instruments are based on a third-party pricing model 

which utilizes inputs that include (a) quoted forward prices for oil and gas, (b) discount rates, (c) volatility factors and (d) current 

market and contractual prices, as well as other relevant economic measures. The carrying amounts of long-term debt under the 

Company’s revolving credit facility approximate fair value as the borrowings bear interest at variable rates of interest. The carrying 

amounts of the 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-Term Debt” and “Note 13. Fair Value 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 oil 
F-11

and gas property costs. Asset retirement obligations require estimates of the costs to plug and abandon wells, the costs to restore 

the surface, the remaining lives of wells based on oil and gas reserve estimates and future inflation rates. The 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 

of oil and gas property retirement. Upon settlement of the liability, the Company either settles the obligation for its recorded amount 

or incurs a gain or loss upon settlement, which is included in oil and gas property costs. On an interim basis, the Company reassesses 

the estimated cash flows underlying the obligation when indicators suggest the estimated cash flows underlying the obligation 

have materially changed and updates its estimated obligation if necessary.

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 of its remaining proved oil and gas reserves. 

Oil and gas sales volumes are not significantly different from the Company’s share of production and as of December 31, 2012

and 2011, 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 differential swaps, to 

manage commodity price risk associated with a portion of its forecasted oil and gas production. Derivative instruments are 

recognized at their balance sheet date fair value as assets or liabilities in the consolidated balance sheets. Although the derivative 

instruments provide an economic hedge of the Company’s exposure to commodity price risk associated with a portion of its 

forecasted oil and gas production, because the Company elected not to meet the criteria to qualify its derivative instruments for 

hedge accounting treatment, unrealized gains and losses as a result of changes in the fair value of derivative instruments are 

recognized as gain (loss) on derivative instruments, net in the consolidated statements of income. Realized gains and losses as a 

result of cash settlements with counterparties to the Company’s derivative instruments are also recorded as gain (loss) on derivative 

instruments, net in the consolidated statements of income. The Company offsets fair value amounts recognized for derivative 

instruments executed with the same counterparty and subject to master netting agreements.

The Company’s Board of Directors establishes risk management policies and reviews derivative instruments, including volumes, 

types of instruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only 

by the President or Chief Financial Officer after consultation with and concurrence by the President, Chief Financial Officer and 

Chairman of the Board. The master contracts with approved counterparties identify the President and Chief Financial Officer as 

the only Company representatives authorized to execute trades. See “Note 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 

of the Company, SARs that may only be settled in cash, restricted stock awards and units to directors, employees and independent 

contractors. The Company recognized the following stock-based compensation expense for the periods indicated which is reflected 

as general and administrative expense in the consolidated statements of income:

Year Ended December 31,

2012 2011 2010

(In thousands)

Stock Appreciation Rights $ (2,116) $ 1,546 $ 6,649

Restricted Stock Awards and Units 17,049 13,965 9,959

14,933 15,511 16,608

Less: amounts capitalized (3,244) (3,647) —

Total Stock-Based Compensation Expense $ 11,689 $ 11,864 $ 16,608

Income Tax 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 

of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as other long-term 

liabilities. Subsequent to vesting, the liability for any SARs that the Company expects to settle in cash is remeasured in earnings 

at each reporting period based fair value until the awards are settled. The Company recognizes stock-based compensation expense 

over the vesting period for stock options and SARs using the straight-line method, except for awards with performance conditions, 

in which case the Company uses the graded vesting method. Stock options typically expire ten years after the date of grant. SARs 

typically expire between four and seven years after the date of grant.

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

requires the Company to make the following assumptions:

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

• The dividend yield on the Company’s common stock is assumed to be zero since the Company does not pay dividends 

and has no current plans to do so in the future.

• The volatility of the Company’s common stock is based on daily, historical volatility of the market price of the Company’s 

common stock over a period of time equal to the expected term and ending on the grant date.

• The expected term is based on historical exercises for various groups of directors, employees and independent contractors.

Restricted Stock Awards 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 or units with performance conditions, in which case the Company uses the graded vesting method. The fair value of restricted 

stock awards and units is based on the price of the Company’s common stock on the grant date. For restricted stock awards and 

units granted to independent contractors, stock-based compensation expense is based on fair value remeasured at each reporting 

period and recognized over the vesting period (generally three years) using the straight-line method.

Income Taxes

Deferred income taxes are recognized at each reporting period for the future tax consequences of differences between the tax bases 

of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in 

which the differences are expected to affect taxable income. The Company routinely assesses the realizability of its deferred tax 

assets and considers its estimate of future taxable income based on production of proved reserves at estimated future pricing in 

making such assessments by taxing jurisdiction. If the Company concludes that it is more likely than not that some portion or all 

of the deferred tax assets will not be realized, the deferred tax assets are reduced by a valuation allowance. The Company classifies 

interest and penalties associated with income taxes as interest expense.
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

Effect 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 of common 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 of the common shares for the period as the effect would be antidilutive to the computation. 

The shares excluded for the years ended December 31, 2012, 2011 and 2010 were not significant. Shares of common stock subject 

to issuance upon the conversion of the Company’s convertible senior notes did not have an effect on the calculation of dilutive 

shares for the years ended December 31, 2012, 2011 and 2010 because the conversion price was in excess of the 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 of its interest in the Huntington Field discovery, including 

a 15% non-operated working interest and certain overriding royalty interests, to a subsidiary of Iona Energy Inc. (“Iona Energy”) 

for net proceeds of approximately $116.5 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. 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 

outstanding under the Huntington Facility were $52.0 million and $55.0 million, respectively. Additionally, the net proceeds include 

non-refundable deposits of $8.0million received by the Company, in accordance with the sale and purchase 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 of income taxes, in the consolidated statements of income and 

cash flows. For the years ended December 31, 2012, 2011 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 of December 31, 2012 and 2011:

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 $ 22,429
F-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, 2011 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 TAX BENEFIT 5,068 7,391 956

NET INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF 

INCOME TAXES $ 4,310 $ 4,095 $ (1,775)

U.K. Huntington Field Development Project Credit Facility

On January 28, 2011, the Company and Carrizo UK, as borrower, entered into the Huntington Facility. The Huntington Facility 

was secured by substantially all of Carrizo UK’s assets and was limited recourse to the Company. 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.

As of December 31, 2012, borrowings outstanding under the Huntington Facility were $52.0 million, of which $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 of Carrizo UK, which closed on February 22, 2013, the $55.0 million of borrowings then outstanding under the Huntington 

Facility was repaid.

Deferred Income Taxes

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, 2011 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. Transaction gains or losses that 

occur due to the realization of assets and the settlement of liabilities denominated in a currency other than the functional currency 

are recorded as Other income (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 for warrants to purchase Oxane common stock and for certain exclusive use and preferential purchase 

rights with respect to the proppant. The Company simultaneously invested an additional $500,000 in a convertible promissory 

note from Oxane. The convertible promissory note accrued interest at a rate of 6% per annum. During the fourth quarter of 2008, 

the Company converted the promissory note into 630,371 shares of Oxane preferred stock. As of December 31, 2012 and 2011, 

the carrying amount of the investment in Oxane was $2.5 million. 
F-16

5. Property and Equipment, Net

At December 31, 2012 and 2011, property and equipment, net consisted of the 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

Total 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, $110.0 million in 2011, $34.7 million in 2010 and $2.0 million in 2009 and prior years.

Sale of Barnett Shale Properties

During the second quarter of 2011, the Company sold a substantial portion of its non-core area Barnett Shale properties to KKR 

Natural Resources (“KKR”), a partnership formed between an affiliate of Kohlberg Kravis Roberts & Co. L.P. and Premier Natural 

Resources. Net proceeds received from the sale were approximately $98.0 million, which represents an agreed upon price of 

approximately $104.0 million less net purchase price adjustments. Purchase price adjustments primarily relate to proceeds received 

by the Company for sales of hydrocarbons from such properties between the effective date of January 1, 2011 and the closing date 

of May 17, 2011. The proceeds from such sale were recognized as a reduction of proved oil and gas properties.

During the second quarter of 2012, the Company sold a significant portion of its Barnett Shale properties to an affiliate of Atlas 

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 effective date of January 1, 2012 and the 

closing date of April 30, 2012. The proceeds from such sale were recognized as a reduction of proved oil and gas properties.

Sale of Gulf Coast Properties

During the third quarter of 2012, the Company completed the sale of substantially all of its legacy producing properties along the 

onshore Gulf of Mexico located primarily in Texas 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 of hydrocarbons from such properties between the effective date 

of July 1, 2012 and the closing date of September 27, 2012. The proceeds from such sale were recognized as a reduction of proved 

oil and gas properties.

Sale of Utica Properties

In October 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 a third party and received net cash proceeds of $51.7 million, after final post-closing 

adjustments. The proceeds from such sale were recognized as a reduction of proved oil and gas properties, 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 Trumbull 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 

its participating interest from 10% to 50% in the same oil and gas properties on a “net proceeds basis” so that the Company received 

net proceeds with respect to 50% of the properties subject to the sale rather than the 10% for which it held record title. For additional 

information see “Note 11. Related Party Transactions.”

Marcellus Shale Joint Venture

In connection with the formation of ACPII Marcellus LLC (“ACPII”), the Company’s partner in one of its two joint ventures in 

the Marcellus Shale, the Company was issued a class of interests (“B Units”) in ACP II. The B Units entitle the Company to 

certain percentages of cash distributions to affiliates of Avista Capital Partners, LP(together with its affiliates, “Avista”), if, when 

and only to the extent that those cash distributions exceed certain internal rates-of-return and return-on-investment thresholds with 

respect to Avista’s investment in ACPII. During the second quarter of 2011, ACPII declared and paid cash distributions to Avista 

that exceeded Avista’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 2011on its B Units, which were recognized as reductions of 

proved oil and gas properties.

In June 2011, in accordance with the title and post-closing adjustment provisions of the sale and purchase agreements of the 

September 2010 sale by the Company of certain oil and gas properties to Reliance Marcellus II, LLC (“Reliance”), the Company 

provided additional interests in oil and gas properties in parts of Pennsylvania in the Marcellus Shale to Reliance in substitution 

of properties included in the sale that were affected by certain alleged title defects. In exchange for such substitute properties, the 

Company received $0.3 million in cash from Reliance relating to the sale of 20% of its interest.

Eagle Ford Joint Venture

On September 28, 2011, the Company completed the sale of 20% of its interests in oil and gas properties in parts of the Eagle 

Ford Shale to GAILGLOBAL(USA) INC. (“GAIL”), a wholly owned subsidiary of GAIL(India) Limited, effective September 1, 

2011. Under the purchase and participation agreement for this transaction, the Company received $63.7 million in cash which was 

recognized as a reduction of proved oil and gas properties. As part of the consideration for the purchase, GAIL committed to pay 

a “development carry” of 50% of certain of the Company’s future development costs up to approximately $31.3 million, which 

was fully utilized in 2012. The agreement provides for an ongoing joint 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 of mutual interest including the purchased interests and specified areas adjacent to such interests. GAIL

will have the right to purchase certain interests acquired by the Company in the area of mutual interest at a specified premium to 

the price paid by the Company.

Niobrara Joint Ventures 

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, effective October 1, 2012. For convenience, in these Notes to 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% of certain of the 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 of proved 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 Weld and Adams counties, Colorado.

Haimo Oil & Gas LLC. In December 2012, the Company completed the sale of a portion of its remaining interest in the same oil 

and gas properties sold to the OILJV Partners in the transaction described above to Haimo Oil & Gas LLC (“Haimo”), a subsidiary 

of Lanzhou Haimo Technologies Co. Ltd., effective 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% of the joint venture acreage, respectively.
F-18

6. Income Taxes

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

Total deferred income tax expense (30,142) (24,546) (2,449)

Total income tax expense from continuing operations $ (30,956) $ (25,611) $ (6,685)

The Company’s income tax expense from continuing operations differs 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

Total income tax expense from continuing operations $ (30,956) $ (25,611) $ (6,685)
F-19

Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities recognized for 

financial reporting purposes and such amounts recognized for tax purposes. At December 31, 2012 and 2011, deferred tax assets 

and liabilities are comprised of the 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

Valuation 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 difference. At December 31, 2012 and 2011, 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 of December 31, 2012, the Company had U.S. income tax loss carryforwards of approximately $176.9 million. The U.S. loss 

carryforwards expire between 2019 and 2032 if not utilized in earlier periods. The realization of the deferred tax assets related to 

the U.S. loss carryforwards is dependent on the Company’s ability to generate sufficient future taxable income in the U.S. within 

the applicable carryforward periods. As of December 31, 2011, the Company determined it was more likely than not that some of 

its state 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 sufficient future taxable income in the U.S. within 

the carryforward periods. As such, the Company believes that it is more likely than not that its net deferred income tax assets will 

be fully realized except for those state loss carryforwards for which valuation allowance has been established.

The ability of the 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 of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock 

by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of 

the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of the 

Company’s taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (a) the 

fair market value of the equity of the Company multiplied by (b) a percentage approximately equivalent to the yield on long-term 

tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are 

recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the 

assets sold. As of December 31, 2012, the Company believes an ownership change occurred in February 2005, which imposed 

an annual limitation of $12.6 million of the Company’s taxable income that can be offset by the pre-change carryforwards. Because 

the Company’s aggregate pre-change loss carryforward is $9.8 million, the Company does not believe it has 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 of the Company (including, potentially, relatively small transactions and transactions beyond the Company’s 

control) could cause further ownership changes and therefore a limitation on the annual utilization of the U.S. loss carryforwards.
F-20

The Company receives a tax deduction during the period stock options are exercised, generally for the excess of the exercise date 

stock price over the exercise price of the option. The Company also receives a tax deduction during the period restricted stock 

awards and units vest, generally equal to the fair value on the date that the awards or units vest. Because these stock-based 

compensation tax deductions did not reduce current taxes payable as a result of U.S. loss carryforwards, the benefit of these 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 Company plans to recognize the $10.2 million deferred tax asset associated with these stock-based compensation tax deductions 

when all other components of the U.S. 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 tax jurisdictions. 

7. Long-Term Debt

At December 31, 2012 and 2011, long-term debt consisted of the 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 

private placement. On November 17, 2011, the Company issued an additional $200.0 million aggregate principal amount of 8.625%

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 2011 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% of the principal amount to 100% of the principal amount on October 15, 2017, plus accrued and unpaid 

interest. In connection with certain equity offerings 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% of the aggregate principal amount of the 8.625% Senior 

Notes at a redemption price of 108.625% of the principal amount, plus accrued and unpaid interest, if any, to the redemption date 

using the net cash proceeds of such equity offerings. Prior to October 15, 2014, the Company may redeem all or part of the 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% of the aggregate principal amount, plus any accrued but unpaid interest.

On September 10, 2012, the Company issued in a public offering $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 offerings 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 of the 7.50% Senior Notes at a redemption price of 107.500% of the principal amount, plus accrued and unpaid interest, 

if any, to the redemption date using the net cash proceeds of such equity offerings. Prior to September 15, 2016, the Company 
F-21

may redeem all or part of the 7.50% 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 7.50% Senior Notes). If a Change of Control (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% of the 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 of the Company’s assets; enter into agreements that restrict distributions or other payments from the Company’s 

restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries. At December 31, 

2012, the 8.625% Senior Notes and the 7.50% Senior Notes were guaranteed by all of the 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 of 4.375% 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 of the convertible senior notes to receive cash up to the principal amount ($1,000 per note) and common stock in respect 

of the remainder, if any, of the Company’s conversion obligation in excess of such principal amount.

In November 2010, the Company completed a tender offer for $300.0 million aggregate principal amount outstanding of its 

convertible senior notes. Each holder received $1,000 for each $1,000 principal amount of convertible senior notes purchased in 

the tender offer, plus accrued and unpaid interest. The Company recognized a $31.0 million pre-tax loss on extinguishment of 

debt as a result of the purchase of the convertible senior notes in the tender offer, substantially all of which was non-cash representing 

the associated unamortized discount and deferred financing costs. After the Company’s purchase of $300.0 million aggregate 

principal amount of convertible senior notes, $73.8 million aggregate principal amount of convertible senior notes was outstanding 

as of December 31, 2012 and 2011.

The convertible senior notes are subject to customary non-financial covenants and events of default, including certain cross defaults 

of other indebtedness and mortgages, the occurrence and continuation of which could result in the acceleration of amounts due 

under the convertible senior notes. The convertible senior notes are unsecured obligations of the Company and rank equal to the 

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, if certain fundamental changes occur on or before June 1, 2013, the Company will in some cases increase the 

conversion rate for a holder electing to convert notes in connection with such fundamental change; provided, that in no event will 

the total number of shares issuable upon conversion of a note exceed 14.7406 per $1,000 principal amount of notes (subject to 

adjustment in the same manner as the conversion rate).

Holders may convert the notes only under the following conditions: (a) during any calendar quarter if the last reported sale price 

of the Company’s common stock exceeds 130% of the conversion price for at least 20 trading days in a period of 30 consecutive 

trading days ending on the last trading day of the immediately preceding calendar quarter, (b) during the five business days after 

any five consecutive trading day period in which the trading price per $1,000 principal amount of the notes is equal to or less than 

97% of the conversion value of such notes, (c) during specified periods if specified distributions to holders of the Company’s 

common stock are made or specified corporate transactions occur, (d) prior to the close of business on the business day preceding 

the redemption date if the notes are called for redemption or (e) on or after March 31, 2028 and prior to the close of business on 

the business day prior to the maturity date of June 1, 2028.

The holders of the convertible senior notes may require the Company to repurchase the notes on June 1, 2013, 2018 and 2023, or 

upon a fundamental corporate change at a repurchase price in cash equal to 100% 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% of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any.

The Company valued the convertible senior notes at May 21, 2008, as $309.6 million of debt and $64.2 million of equity representing 

the fair value of the conversion premium. The resulting debt discount is being amortized to interest expense through June 1, 2013, 

the first date on which the holders may require the Company to repurchase the convertible senior notes, resulting in an effective 

interest rate of approximately 8% for the convertible senior notes. Approximately $27.1 million of the remaining debt discount 

associated with the convertible senior notes purchased in the tender offer discussed above was recognized as a component of the 
F-22

loss on the extinguishment of debt in 2010. Amortization of the debt discount amounted to $2.7 million, $2.6 million and $11.6 

million for the years ended December 31, 2012, 2011 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 of its senior secured revolving credit facility, and accordingly, the convertible senior notes have been classified as longterm debt in the consolidated balance sheets as of December 31, 2012.

Senior Secured Revolving Credit Facility

The Company is party to a senior secured revolving credit facility with Wells Fargo Bank, National Association as the 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 of the 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 Effective 

Rate plus 0.5% and the adjusted LIBO rate for a three-month interest period on such day plus 1.00%, plus (b) a margin between 

1.00% and 2.00% (depending on the then-current level of borrowing base usage). The interest rate on each Eurodollar loan will 

be the adjusted LIBO rate for the applicable interest period plus a margin between 2.00% to 3.00% (depending on the then-current 

level of borrowing base usage).

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 of Total 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 offering. On September 27, 2012, the revolving credit facility was again 

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.

The Company is subject to certain covenants under the terms of the revolving credit facility which include the maintenance of the 

following financial covenants: (1) a ratio of Total Debt to EBITDA of not 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 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 of EBITDA to Interest 

Expense of not less than 2.50 to 1.00 (each of the 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 Total 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. Total Debt and Senior Debt, as defined in the credit agreement governing the revolving credit 

facility, are net of cash and cash equivalents of the Company. Because the calculation of the financial ratios are made as of a certain 

date, the financial ratios can fluctuate significantly period to period as the amounts outstanding under the revolving credit facility 

are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities 

offerings.

The revolving credit facility also places restrictions on the Company and certain of its subsidiaries with respect to additional 

indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, 

redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions 

and other matters.

The revolving credit facility is subject to customary events of default, including a change in control (as defined in the credit 

agreement governing the revolving credit facility). If an event of default occurs and is continuing, the Majority Lenders (as defined 

in the credit agreement governing the revolving credit facility) may accelerate amounts due under the revolving credit facility 

(except for a bankruptcy event of default, in which case such amounts will automatically become due and payable).

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 of credit outstanding which reduced the amounts available under the revolving credit 

facility. The revolving credit facility is generally used to fund ongoing working capital needs and the remainder of the Company’s 
F-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 offerings. 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, 2012 and 2011:

Year Ended December 31,

2012 2011

(In thousands)

Asset retirement obligations at beginning of period $ 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 of previous estimates 828 2,612

Asset retirement obligations at end of period 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 of business. While the 

outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse 

effect on the financial position or results of operations of the Company. 

The results of operations and financial position of the Company continue to be affected from time to time in varying degrees by 

domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and natural gas 

production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract 

rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable.

Rent expense included in general and administrative expense for the years ended December 31, 2012, 2011 and 2010 was $1.8 

million, $1.7 million, and $1.0 million, respectively, and includes rent expense primarily for the Company’s corporate office and 

field offices.

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

$ 190,683
F-24

10. Shareholders’ Equity and Stock Incentive Plans

Shareholders’ Equity

Common Stock. In December 2010, the Company sold 3.975 million shares of its common stock in an underwritten public offering 

at a price to the underwriter of $28.90 per share. The Company used the net proceeds of approximately $114.9 million to repay 

a portion of the outstanding borrowings under the Prior Credit Facility.

In April 2010, the Company sold 3.22 million shares of its common stock in an underwritten public offering at a price to the 

underwriter of $23.00 per share. The Company used the net proceeds of approximately $73.8 million to repay a portion of the 

outstanding borrowings under the Prior Credit Facility.

Warrants. On November 24, 2009, the Company entered into a land agreement with an unrelated third party and its affiliate. The 

land agreement expired pursuant to its terms on May 31, 2011. Under the land agreement, the Company issued warrants to purchase 

31,983, 28,576 and 57,641 shares of common stock in 2012, 2011 and 2010, respectively. The final issuance of warrants under 

the land agreement was granted in April 2012. The warrants have an expiration date of August 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 of Carrizo 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 of up 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, 2011 and 2010:

Shares

WeightedAverage

Exercise

Prices

WeightedAverage

Remaining Life

(In years)

Aggregate

Intrinsic Value

(In millions)

For the Year Ended December 31, 2010

Outstanding, beginning of period 895,463 $ 8.43

Granted — —

Exercised (266,433) 2.59

Forfeited (2,493) 18.56

Other (211,683) 20.22

Outstanding, end of period 414,854 $ 6.10

Exercisable, end of period 414,854 $ 6.10

For the Year Ended December 31, 2011

Outstanding, beginning of period 414,854 $ 6.10

Granted — —

Exercised (151,500) 4.36

Forfeited — —

Outstanding, end of period 263,354 $ 7.11

Exercisable, end of period 263,354 $ 7.11

For the Year Ended December 31, 2012

Outstanding, beginning of period 263,354 $ 7.11

Granted — —

Exercised (20,500) 5.50

Forfeited — —

Outstanding, end of period 242,854 $ 7.24 0.87 $ 3.21

Exercisable, end of period 242,854 $ 7.24 0.87 $ 3.21
F-25

No stock options or SARs were granted under the Incentive Plan during 2010, 2011 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, 2011 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, 2011 and 2010, respectively.

Restricted Stock Awards and Units. The Company began issuing restricted stock awards in 2005 and restricted stock units in 2009. 

Although shares of common stock are not released to the employee until vesting, restricted stock awards have the right to vote 

and accordingly, restricted stock awards are considered issued and outstanding at the date of grant. Restricted stock units, which 

may be settled in cash or common stock at the Company’s option, do not have the right to vote and are not considered issued and 

outstanding until converted into common shares and released to the employee upon vesting. The table below summarizes restricted 

stock award and unit activity for the years ended December 31, 2012, 2011 and 2010:

Shares/

Units

Grant-date

Fair Value

Unvested restricted stock awards and units at January 1, 2010 471,243 $ 25.01

Granted 640,207 18.60

Vested (380,668) 23.42

Forfeited (19,827) 25.23

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

Granted 567,901 35.27

Vested (452,585) 25.29

Forfeited (25,773) 23.30

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

Granted 854,292 25.25

Vested (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 of December 31, 2012, unrecognized compensation costs related to unvested restricted stock awards and units was $18.6 million

and will be recognized as stock-based compensation expense over a weighted-average period of two years. The 2010, 2011 and 

2012 grants of certain restricted stock units contained performance and service conditions. The performance conditions have been 

met for all awards.
F-26

Cash-Settled Stock Appreciation Rights Plan

The Company has also established the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SARs Plan”). 

The Cash SARs Plan enables employees and independent contractors to share in the appreciation of Carrizo’s common stock, but 

does not require the issuance of shares. During 2012 and 2011, the Company issued 193,336 and 153,801 SARs under the Cash 

SARs Plan, respectively. At December 31, 2012 and 2011, the liability for such SARs was $4.9 million and $6.5 million, of which, 

$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 2011, 

respectively:

2012 2011

Grant date fair value $ 12.23 $ 18.50

Volatility factor 48.2% 61.6%

Dividend yield — —

Risk-free interest rate 0.4% 0.4%

Expected term (in years) 3.0 2.9

As of December 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 Transactions

Transactions with Avista and affiliates

Utica Shale Joint Venture. In September 2011, the Company entered into a joint venture with affiliates of Avista to acquire and 

develop acreage in the liquids rich region of the Utica Shale. The Company serves as operator of the joint 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. Avista or its designee has the right to become a co-operator of the joint venture properties if (i) Avista 

sells substantially all of its interests in the Avista Utica joint venture or (ii) the Company defaults under the terms of any pledge 

of its interest in the properties. In addition to the Company's share in the production and sale proceeds from joint venture properties, 

the Company also acquired B Units in ACP III at the formation of the Avista Utica joint 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 Avista 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% of the properties subject to the sale rather than the 10% for which it held record title. Pursuant to the joint 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 Avista Utica joint venture properties. Subsequently, on October 24, 2012, the Company and Avista 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 Avista 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 Avista Utica 

joint venture properties. The Company and Avista 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 Avista’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 Avista’s acreage cost and associated improvements (compounded monthly following Avista’s 

contribution of purchase proceeds). This additional option will expire May 31, 2013. Additionally, the Company and Avista agreed 

to increase the cap on ACPIII’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 ACPII in the Avista Utica joint venture through its B Units 

in ACP II was terminated upon the consummation of the Company’s exercise of its option with respect to 50% of the 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 Avista Utica joint venture properties.
F-27

Steven A. Webster, Chairman of the Company’s Board of Directors, serves as Co-Managing Partner and President of Avista Capital 

Holdings, LP, which has the ability to control Avista and its affiliates. ACPII’s and III’s Boards of Managers have the sole authority 

for determining whether, when and to what extent any cash distributions will be declared and paid to members of ACPII or ACP

III, respectively. Mr. Webster is not a member of either entity’s Board of Managers.

Marcellus Shale Joint Ventures. Effective August 1, 2008, Carrizo (Marcellus) LLC, a wholly owned subsidiary of the Company, 

entered into a joint venture arrangement with ACPII, an affiliate of Avista. In September 2010, the Company completed the sale 

of 20% of its interests in substantially all of its oil and gas properties in Pennsylvania that had been subject to the Avista joint 

venture to Reliance. Simultaneously with the closing of this transaction, ACP II closed the sale of its entire interest in the same 

properties to Reliance for a purchase price of approximately $327.0 million. At the time of entering into the agreements for these 

transactions, the Company and Avista agreed that B Unit distributions to the Company with respect to Avista’s sale of properties 

to Reliance would be principally based upon Avista’s internal rates-of-return and return-on-investment thresholds associated with 

such properties, subject to amounts withheld from distribution by ACPII’s board. In connection with these sales transactions, the 

Company and Avista amended the participation agreement and other joint venture agreements with Avista to provide that the 

properties that the Company and Avista sold to Reliance, as well as the properties the Company committed to the new joint venture 

with Reliance, are not subject to the terms of the Avista Marcellus joint venture, and that the Avista Marcellus joint venture’s area 

of mutual interest will generally not include Pennsylvania, the state in which those properties are located. The Company’s joint 

venture with Avista continues and now covers approximately 71,774 net acres, primarily in West Virginia and New York. Pursuant 

to the terms of the Avista area of mutual interest, effective December 31, 2010, the initial area of mutual interest was reduced to 

specified halos in which the Avista Marcellus joint venture was active.

In December 2010, the Company entered into a settlement agreement with Reliance providing for the resolution of defects in title 

that Reliance alleged with respect to the properties it acquired from the Company and Avista in September 2010. In the agreement, 

the Company agreed to undertake specified curative measures with respect to the properties it and Avista sold to Reliance, and to 

indemnify Reliance on its own behalf and on behalf of Avista with respect to specified third party claims (in addition to existing 

customary indemnification obligations under the purchase agreement). In connection with entering into the settlement agreement, 

the Company entered into an agreement with Avista by which Avista agreed to indemnify the Company for amounts paid on 

Avista’s behalf by the Company under the settlement agreement, if any.

On November 16, 2010, Carrizo Marcellus assigned, via distribution and subsequent contribution, its interests in the Avista 

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 related joint operating agreement, pursuant to which operatorship of the Avista Marcellus joint venture 

was assumed by Carrizo WV. In addition, Carrizo WVand the other parties thereto amended and restated the participation agreement 

on November 16, 2010, effective as of October 1, 2010. This amended and restated participation agreement amends the participation 

agreement by, among other things, (i) providing fixed percentages and thresholds for sharing net cash flow from hydrocarbon 

production and proceeds from the sales of underlying joint venture properties and (ii) eliminating provisions that have been 

performed and are inapplicable going forward.

The Company serves as operator of the properties covered by the Avista Marcellus joint venture under a joint operating agreement 

with Avista and also performs specified management services for ACPII. An operating committee composed of one representative 

of each party provides overall supervision and direction of joint operations. Avista or its designee has the right to become a cooperator of the properties if all of its membership interests or substantially all of its assets are sold to an unaffiliated third party 

or if the Company defaults under the terms of any pledge of its interest in the properties.

The Company has agreed to jointly market Avista’s share of the production from the properties with its own until the cash flows 

and sale proceeds are allocated in accordance with the parties’ participating interests under the joint operating agreement. 

Each party now has ability to transfer its interest in the Avista Marcellus joint venture to third parties subject in most instances to 

preferential purchase rights for transfers of less than 10% of its interest in joint venture properties, or to “tag along” rights for 

most other transfers.

Steven A. Webster, Chairman of the Company’s Board of Directors, serves as Co-Managing Partner and President of Avista Capital 

Holdings, LP, which has the ability to control Avista. ACPII’s Board of Managers have the sole authority for determining whether, 

when and to what extent any cash distributions will be declared and paid to members of ACP II. Mr. Webster is not a member of 

ACP II’s Board of Managers. As disclosed elsewhere, the Company has been and is a party to prior arrangements with affiliates 

of Avista Capital Holdings, LP in respect of the Company’s joint venture with affiliates of Avista in the Utica Shale. 

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 2011 received an additional $3.3 million on its B Unit investment 

in ACP II, which were recognized as a reduction of capitalized oil and gas property costs. As described in “Utica Shale Joint 
F-28

Venture” above, the Company’s right to receive distributions associated with the properties owned by ACP II in the Avista Utica 

joint venture through its B Units in ACP II was terminated upon the consummation of the Company’s exercise of its option with 

respect to certain Avista Utica joint venture properties in October 2012.

Advances to and from Avista and Affiliates. At December 31, 2012, related party receivables on the consolidated balance sheets 

included $9.8 million, representing the net amounts Avista owes the company related to activity within the Utica and Marcellus 

Shale joint ventures. At December 31, 2011, advances for joint operations on the consolidated balance sheets included $9.5 million, 

representing the net amount Avista had advanced the Company related to activity within the Utica and Marcellus Shale joint 

ventures.

12. Derivative Instruments

The Company uses various types of derivative instruments to manage its exposure to commodity price risk and to provide a level 

of certainty in its forward cash flows supporting its capital expenditure program. The derivative instruments typically used are 

fixed-rate swaps, costless collars, puts, calls and basis differential swaps. Under these derivative instruments, payments are received 

or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at termination, 

expiration or exchanged for physical delivery contracts. The Company’s current long-term strategy is to manage exposure for a 

substantial, but varying, portion of forecasted production up to 60 months. The derivative instruments are carried at fair value in 

the 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 of derivative instruments at December 31, 2012 and 2011 was a net asset of $29.2 million and $37.5 million, 

respectively. The following sets forth a summary of the distribution of the net fair value of the 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 of these counterparties. Because the counterparties are either investment grade 

financial institutions or an investment grade international oil and gas company, the Company believes it has minimal credit risk 

and accordingly does not currently require its counterparties to post collateral to support the asset positions of its derivative 

instruments. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative 

instruments. Although the Company does not currently anticipate such nonperformance, it continues to monitor the financial 

viability of its counterparties. Because Credit Suisse, Credit Agricole, BBVA Compass, Wells 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 summary of the Company’s natural gas derivative positions at average NYMEX prices as of December 31, 

2012.

Period

Volume

(in MMBtu)

Weighted

Average

Floor Price

($/MMBtu)

Weighted

Average

Ceiling Price

($/MMBtu)

2013 18,250,000 $ 4.63 $ 4.63

2014 3,650,000 $ — $ 5.50
F-29

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

2012.

Period

Volume

(in Bbls)

Weighted

Average

Floor Price

($/Bbls)

Weighted

Average

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 

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 

Volumes

(in Bbls)

Weighted

Average

Short Put Price

($/Bbl)

Weighted

Average

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, 2011 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 Value Measurements

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. 

The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the 

observability of the inputs employed in the measurement. The three levels are defined as follows:

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

liabilities.

Level 2 — Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs 

which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 — Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions 

about how market participants would price the assets and liabilities.
F-30

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 

2012 and 2011, and indicate the fair value hierarchy of the 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 fair values of the Company’s derivative instruments are based on a pricing model that uses 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. To 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 are revised to reflect actual results, changes in market conditions and other factors. The assets and liabilities for derivative 

instruments included in the tables above are presented on a gross basis. The assets and liabilities for derivative instruments included 

in the consolidated balance sheets are presented on a net basis when such amounts are with the same counterparty and subject to 

master netting agreements. The Company had no transfers in or out of Levels 1 or 2 for the years ended December 31, 2012 and 

2011.

Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash 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 of these instruments. The carrying amounts of longterm debt under the Company’s revolving credit facility approximate fair value as these borrowings bear interest at variable rates 

of interest. The following table presents the carrying amounts and fair values of the Company’s senior notes and convertible senior 

notes, based on quoted market prices, as of December 31, 2012 and 2011.

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 2011, the Company and certain of the Company’s wholly owned subsidiaries (such subsidiaries 

collectively, the “Subsidiary Guarantors”) issued in private placements $400.0 million and $200.0 million, respectively, aggregate 

principal amount of the Company’s 8.625% Senior Notes. Certain, but not all, of the Company’s wholly owned subsidiaries have 

issued full, unconditional and joint and several guarantees of the 8.625% Senior Notes and may guarantee future issuances of debt 

securities. In June 2011 and February 2012, the Company completed the exchange of registered 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 of the Company’s wholly owned subsidiaries issued in a public offering $300.0 million

aggregate principal amount of the Company’s 7.50% Senior Notes.

The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed 

the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the 

voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating 
F-31

financial information as of December 31, 2012 and December 31, 2011, and for each of the three years ended December 31, 2012, 

2011 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 of operations of subsidiaries are therefore reflected in the parent company’s investment accounts and earnings. 

The principal elimination entries set forth below eliminate investments in subsidiaries and intercompany balances and transactions. 

Typically in a condensed consolidating financial statement, the net income and equity of the parent company equals the net income 

and equity of the consolidated entity. The Company’s oil and gas properties are accounted for using the full cost method of 

accounting whereby impairments and DD&Aare calculated and recorded on a country by country basis. However, when calculated 

separately on a legal entity basis, the combined totals of parent company and subsidiary impairments and DD&A can be more or 

less than the consolidated total as a result of differences in the properties each entity owns including amounts of costs incurred, 

production rates, reserve mix, future development costs, etc. Accordingly, elimination entries are required to eliminate any 

differences between consolidated and parent company and subsidiary company combined impairments and DD&A.
F-32

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING 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

Total 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

Total liabilities and shareholders’ equity $ 1,430,945 $ 1,256,752 $ 81,918 $ (1,241,935) $ 1,527,680
F-33

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS 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) from continuing operations before income taxes (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 of income taxes 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 of income taxes 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) from continuing operations before income taxes (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) $ 9,950
F-34

CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS 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 of year - 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

Total Worldwide

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

Total 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, 2011 and 2010, respectively.

Proved Oil and Gas Reserve Quantities

Proved reserves are generally those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated 

with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, 

operating methods and government regulations. Proved developed reserves include proved reserves that can be expected to be 

produced through existing wells with existing equipment and operating methods or in which the cost of the required equipment 

is relatively minor compared to the cost of a new well. Proved undeveloped reserves are generally proved reserves that are expected 

to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for 

recompletion.

Proved oil and gas reserve quantities at December 31, 2012, 2011 and 2010, and the related discounted future net cash flows before 

income taxes are based on estimates prepared by LaRoche Petroleum Consultants, Ltd. and Ryder 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, 2011 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, 2011 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 of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle 

Ford Shale and the Niobrara Formation.

2011 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle 

Ford Shale and the Niobrara Formation; Transfer of U.K. proved undeveloped reserves to proved developed reserves 

as a result of drilling.

2010 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle 

Ford Shale; Additions of U.K. proved undeveloped reserves as a result of the approval of the Huntington Field 

Development Plan by the Company and its joint venture partners and the U.K. Department of Energy and Climate 

Change in November 2010.

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

2011 Sales of properties 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, 2011 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, 2011 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 of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett 

Shale, Marcellus Shale, and Eagle Ford Shale.

2011 Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset 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 of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett 

Shale and Eagle Ford Shale, as well as an increase in previously estimated proved undeveloped reserves based on 

operational performance; Additions of U.K. proved undeveloped reserves as a result of the approval of the Huntington 

Field Development Plan by the Company and its joint venture partners and the U.K. Department of Energy and Climate 

Change in November 2010.

Natural gas revisions of previous 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 offset by negative quantity revisions due to a planned shift in future drilling priorities focusing 

more on drilling in the core of the Barnett Shale, which resulted in removing natural gas reserves previously classified 

as proved undeveloped in the Barnett Shale.

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

2012 Sales of properties to Atlas during the second quarter and sale of Gulf Coast properties during the third quarter.

2011 Sales of properties to KKR during the second quarter and GAIL during the third quarter.
F-38

Standardized Measure

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, 2011 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 of future net cash flows. The standardized measure of discounted future net cash flows is not intended 

to represent the replacement cost or fair value of the Company’s oil and gas properties. An estimate of fair value would also take 

into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices 

and costs, and a discount factor more representative of the time value of money and the risks inherent in oil and gas reserve 

estimates.
F-39

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are summarized 

below:

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

Total 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 $ 1,418,395
F-40

16. Selected Quarterly Financial Data (Unaudited)

The following table presents selected quarterly financial data for the years ended December 31, 2012 and 2011:

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 of the 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

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has caused this report 

to be signed on its behalf by the undersigned, thereunto duly authorized.

CARRIZO OIL & GAS, INC.

By: /s/ Paul F. Boling

Paul F. Boling

Chief Financial Officer, Vice President,

Secretary and Treasurer

Date: February 27, 2013

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons 

on behalf of the registrant and in the capacities and on the dates indicated.

Name Capacity Date

/s/ S.P. Johnson IV President, Chief Executive Officer and Director February 27, 2013

S. P. Johnson IV (Principal Executive Officer)

/s/ Paul F. Boling Chief Financial Officer, Vice President, February 27, 2013

Paul F. Boling Secretary and Treasurer

(Principal Financial Officer)

/s/ David L. Pitts Vice President and Chief Accounting Officer February 27, 2013

David L. Pitts (Principal Accounting Officer)

/s/ Steven A. Webster Chairman of the Board February 27, 2013

Steven A. Webster

/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. Wojtek Director February 27, 2013

Frank A. Wojtek
Exhibit 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.:

We consent to the incorporation by reference in the registration statement (No. 333-173821) on and the registration 

statements (Nos. 333-181585, 16528, and on of Carrizo Oil 

& Gas, Inc. of our reports dated February 27, 2013, with respect to the consolidated balance sheets of Carrizo Oil & Gas, Inc. as 

of December 31, 2012 and 2011, and the related consolidated statements of income, shareholders’ equity, and cash flows, for each 

of the years in the period ended December 31, 2012, and the effectiveness of internal control over financial reporting 

as of December 31, 2012, which reports appear in the December 31, 2012 annual report on of Carrizo Oil & Gas, Inc.

/s/ KPMG LLP

Houston, Texas 

February 27, 2013
Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the incorporation by reference in the registration statements on Form S-8 (Registration Nos. 

333-181585, 333-162888, 333-137273, 333-116528, 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 25, 2013, relating to estimates 

of proved reserves attributable to certain interests of Carrizo Oil & Gas, Inc. as of December 31, 2012.

 LaRoche Petroleum Consultants, Ltd.

 /s/ William M. Kazmann 

 William M. Kazmann

 Senior Partner 

Houston, Texas

February 27, 2013
Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the incorporation by reference in the registration statements on Form S-8 (Registration Nos. 

333-181585, 333-162888, 333-137273, 333-116528, 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/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 27, 2013
Exhibit 23.4

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the incorporation by reference in the registration statements on Form S-8 (Registration Nos. 

333-181585, 333-162888, 333-137273, 333-116528, 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/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 27, 2013
Exhibit 31.1

CERTIFICATION

PRINCIPAL 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 of the 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 officer 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 effectiveness of the registrant's disclosure controls and procedures and presented in this report our 

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the 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 affected, or is reasonably likely to materially affect the registrant's internal control over financial 

reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over 

financial reporting, to the registrant’s auditors and the audit committee of the 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 affect 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 Chief Executive Officer
Exhibit 31.2

CERTIFICATION

PRINCIPAL 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 of the 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 officer 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 effectiveness of the registrant's disclosure controls and procedures and presented in this report our 

conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the 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 affected, or is reasonably likely to materially affect the registrant's internal control over financial 

reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over 

financial reporting, to the registrant’s auditors and the audit committee of the 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 affect 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

Vice President, Chief Financial Officer and Secretary
Exhibit 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 Chief Executive Officer of Carrizo Oil & Gas, Inc., a Texas 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) of the Securities Exchange Act of 1934; and

2. information contained in the Report fairly presents, in all material respects, the financial condition and results of operations 

of the Company.

Date: February 27, 2013 /s/ S.P. Johnson, IV

S.P. Johnson, IV

President and Chief Executive Officer

The foregoing certification is being furnished solely 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) and is not being filed as part of the 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 staff upon 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, Vice President, Chief Financial Officer and Secretary of Carrizo Oil & Gas, Inc., a 

Texas 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) of the Securities Exchange Act of 1934; and

2. information contained in the Report fairly presents, in all material respects, the financial condition and results of operations 

of the Company.

Date: February 27, 2013 /s/ Paul F. Boling

Paul F. Boling

Vice President, Chief Financial Officer and Secretary

The foregoing certification is being furnished solely 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) and is not being filed as part of the 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 staff upon request.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580
SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790

621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258

[Ryder Scott Company L.P. logo]

TBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849

1100 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 York, Pennsylvania and Texas. 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 effect 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 differ 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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

SEC PARAMETERS

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 official 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 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 differences 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

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 or as economic conditions change. For proved reserves, the SEC states that “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 
Carrizo Oil & Gas, Inc.

February 6, 2013

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RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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, effects 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 differ 

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 select the method or combination of methods which in their 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.

February 6, 2013

Page 5

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 and their associated reserve categories may also be revised due to other factors such as changes 

in economic conditions, results of future operations, effects 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 sufficient 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 or which we have obtained from public data sources that were 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 sufficient for the purpose thereof. 

To 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 of future 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 of the 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 differentials 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 sufficient 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.

February 6, 2013

Page 6

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 effects 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.

Test 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 effect 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 effect 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 differentials 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 “differentials.” The differentials used in the preparation of this report were 

furnished to us by Carrizo. The differentials 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 differentials. 
Carrizo Oil & Gas, Inc.

February 6, 2013

Page 7

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for 

differentials 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

Average Benchmark

Prices

Average 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 effects 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 of general 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 COPAS 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 costs were furnished 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.

February 6, 2013

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RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We 

have over eighty engineers and geoscientists on our permanent staff. 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 officers or directors of any privately-owned or publiclytraded oil and gas company and are separate and independent from 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 staff have 

authored or co-authored technical papers on the subject of reserves related topics. We encourage our 

staff to maintain and enhance their professional skills by actively participating in ongoing continuing 

education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff 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.

Terms 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. 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 differences 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.

February 6, 2013

Page 9

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

The data and work papers used in the preparation of this report are available for examination by 

authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, 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)/pl
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical 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 responsible for coordinating and supervising staff and consulting engineers of the company 

in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number 

of engineering positions with 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 Texas. 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 Texas 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 of formalized in-house training as well as an additional five hours of formalized 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 2011 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. 
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES 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 effect for all filings made with 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 or wholly from the aforementioned SEC document are denoted in italics herein).

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. 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 

of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples 
PETROLEUM RESERVES DEFINITIONS

Page 2

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 of the differences in uncertainty, caution should be exercised when aggregating quantities 

of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as 

follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated 

to be economically producible, as of a given date, by application of development projects to known 

accumulations. In addition, there must exist, or there must be a reasonable expectation that there will 

exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil 

and gas or related substances to market, and all permits and financing required to implement the project. 

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 economically producible. 

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 RESERVES (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 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. 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 undrilled portions of the reservoir that can, with reasonable certainty, be judged 

to be continuous with it and to contain economically producible oil or gas on the basis of 

available geoscience and engineering data. 
PETROLEUM RESERVES DEFINITIONS

Page 3

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are 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 direct observation from well penetrations has defined a highest known 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 

reservoir or an analogous reservoir, or other evidence using reliable technology establishes 

the reasonable certainty of the engineering analysis on which the project or program was 

based; and 

(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 

reservoir is to be determined. The price shall be the average price during the 12-month period prior 

to the ending date of the period covered by the report, determined as an unweighted arithmetic 

average of the first-day-of-the-month price for each month within such period, unless prices are 

defined by contractual arrangements, excluding escalations based upon future conditions. 
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES 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 ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION 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 RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and 

gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered: 

(i) Through existing wells with existing equipment and operating methods or in which the 

cost of the required equipment is relatively minor compared to the cost of a new well; and 

(ii) Through installed extraction equipment and infrastructure operational at the time of the 

reserves estimate if the extraction is by means not involving a well. 

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 RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 of production. 

In all cases, production can be initiated or restored with relatively low expenditure compared to 

the cost of drilling a new well. 

UNDEVELOPED RESERVES (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 of any category that are expected to be recovered 

from new wells on undrilled acreage, or from existing wells where a relatively major expenditure 

is required for recompletion. 

(i) Reserves on undrilled acreage 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 of fluid injection or other improved recovery technique 

is contemplated, unless such techniques have been proved effective by actual projects in 

the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, 

or by other evidence using reliable technology establishing reasonable certainty.
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580
TBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849

SUITE 600, 1015 4TH STREET, S.W. CALGARY, ALBERTA T2R 1J4 TEL (403) 262-2799 FAX (403) 262-2790

621 17TH STREET, SUITE 1550 DENVER, COLORADO 80293-1501 TEL (303) 623-9147 FAX (303) 623-4258

[Ryder Scott Company, L.P. logo]

TBPE REGISTERED ENGINEERING FIRM F-1580 FAX (713) 651-0849

1100 LOUISIANA SUITE 4600 HOUSTON, TEXAS 77002-5294 TELEPHONE (713) 651-9191

February 15, 2013

Carrizo Oil & Gas, Inc.

1000 Louisiana Street, Suite 1500

Houston, Texas 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 offshore United Kingdom (UK). 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 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 effect 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 differ significantly from the estimated quantities presented in this report. The results of this 

study are summarized below.
Carrizo Oil & Gas, Inc.

February 15, 2013

Page 2

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

SEC PARAMETERS

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 official 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 differences 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 tariffs 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.

February 15, 2013

Page 3

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 or as economic conditions change. For proved reserves, the SEC states that “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, effects of regulation by governmental agencies or 

geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only 
Carrizo Oil & Gas, Inc.

February 15, 2013

Page 4

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 differ significantly 

from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the 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 select the method or combination of methods which in their 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 and their associated reserve categories may also be revised due to other factors such as changes 
Carrizo Oil & Gas, Inc.

February 15, 2013

Page 5

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

in economic conditions, results of future operations, effects 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 sufficient for the purpose thereof.

To 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 of future 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 of the 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 sufficient 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

Test 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.

February 15, 2013

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RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 effect 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 effect 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 differentials 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 “differentials.” The differentials used in the preparation of this report were 

furnished to us by Carrizo. The differentials 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 differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for 

differentials 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

Average

Benchmark Prices

Average

Realized Prices

United Kingdom

 North Sea

Oil/Condensate Brent $111.21/Bbl $111.21/Bbl

Gas UK $9.54/MMBTU $13.32/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not 

reflected in our individual property evaluations. 
Carrizo Oil & Gas, Inc.

February 15, 2013

Page 7

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We 

have over eighty engineers and geoscientists on our permanent staff. 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 officers or directors of any privately-owned or publiclytraded oil and gas company and are separate and independent from 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 staff have 

authored or co-authored technical papers on the subject of reserves related topics. We encourage our 

staff to maintain and enhance their professional skills by actively participating in ongoing continuing 

education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff 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.

February 15, 2013

Page 8

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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.

Terms 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. 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 differences 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 offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, 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)/pl
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical 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 responsible for coordinating and supervising staff and consulting engineers of the company 

in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Stell served in a number 

of engineering positions with 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 Texas. 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 Texas 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 of formalized in-house training as well as an additional five hours of formalized 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 2011 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. 
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES 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 effect for all filings made with 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 or wholly from the aforementioned SEC document are denoted in italics herein).

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. 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 

of their 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 RESERVES DEFINITIONS

Page 2

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 of the differences in uncertainty, caution should be exercised when aggregating quantities 

of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as 

follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated 

to be economically producible, as of a given date, by application of development projects to known 

accumulations. In addition, there must exist, or there must be a reasonable expectation that there will 

exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil 

and gas or related substances to market, and all permits and financing required to implement the project. 

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 economically producible. 

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 RESERVES (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 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. 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 undrilled portions of the reservoir that can, with reasonable certainty, be judged 

to be continuous with it and to contain economically producible oil or gas on the basis of 

available geoscience and engineering data. 
PETROLEUM RESERVES DEFINITIONS

Page 3

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are 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 direct observation from well penetrations has defined a highest known 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 

reservoir or an analogous reservoir, or other evidence using reliable technology establishes 

the reasonable certainty of the engineering analysis on which the project or program was 

based; and 

(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 

reservoir is to be determined. The price shall be the average price during the 12-month period prior 

to the ending date of the period covered by the report, determined as an unweighted arithmetic 

average of the first-day-of-the-month price for each month within such period, unless prices are 

defined by contractual arrangements, excluding escalations based upon future conditions. 
RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES 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 ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION 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 RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and 

gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered: 

(i) Through existing wells with existing equipment and operating methods or in which the 

cost of the required equipment is relatively minor compared to the cost of a new well; and 

(ii) Through installed extraction equipment and infrastructure operational at the time of the 

reserves estimate if the extraction is by means not involving a well. 

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 RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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 of production. 

In all cases, production can be initiated or restored with relatively low expenditure compared to 

the cost of drilling a new well. 

UNDEVELOPED RESERVES (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 of any category that are expected to be recovered 

from new wells on undrilled acreage, or from existing wells where a relatively major expenditure 

is required for recompletion. 

(i) Reserves on undrilled acreage 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 of fluid injection or other improved recovery technique 

is contemplated, unless such techniques have been proved effective by actual projects in 

the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, 

or by other evidence using reliable technology establishing reasonable certainty.
 

 

2435 N Central Expressway, Suite 1500 Dallas TX 75080 Phone (214) 363-3337 Fax (214) 363-1608

[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, Texas 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 Tarrant County, Texas. 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) Total

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)

Total 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 excluded from our consideration all matters as to which 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 affect 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 differ 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 WAHAphysical price of $2.68 per MMBtu, as posted by Platts Daily Gas, 

and are adjusted for energy content, transportation fees, and regional price differentials. 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 as well as compression costs. Leases and wells 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 of the cost to plug and abandon the wells net of salvage value are included 

and scheduled at the end of the economic life of individual properties. These costs are held constant.

Severance tax rates for all properties are calculated based on applicable State of Texas 

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.

Technical 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 sufficient production history to utilize performance-related 

reserve estimates. Therefore, these reserves are based on estimates of reservoir volumes and 

recovery efficiencies along with analogies to 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 differences 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 and Auditing 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 Texas 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 Texas at Austin and has prepared 

reserves estimates for his employers and his own companies throughout 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 office.

Very truly yours,

LaRoche Petroleum Consultants, Ltd.

State of Texas Registration Number F-1360

/s/ Al Iakovakis

Al Iakovakis

Manager of Unconventional Resource Evaluations

Senior Staff Engineer

/s/ William M. Kazmann

William M. Kazmann

Licensed Professional Engineer

State of Texas No. 45012

AI:mk

12-918
LaRoche Petroleum Consultants, Ltd.

DEFINITION OF RESERVES

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 of the effective date of the 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 of confidence which 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 effective 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 of 
LaRoche 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 shutin for market conditions or pipeline connections, or (3) wells not capable of production for 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 of fluid injection or other improved recovery technique is contemplated unless supported 

by techniques that have been proved effective 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.