Carrizo Oil & Gas 10Q 2003 Q3 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2003

¨	TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 000-22915.

CARRIZO OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

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

14701 St. Mary’s Lane, Suite 800, Houston, TX		77079
(Address of principal executive offices)		(Zip Code)

(281) 496-1352

(Registrant’s telephone number)

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). YES ¨ NO x

The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, as of November 1, 2003, the latest practicable date, was 14,571,426.

CARRIZO OIL & GAS, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003

INDEX

		PAGE
PART I. FINANCIAL INFORMATION

Item 1.	Unaudited Consolidated Balance Sheets - As of December 31, 2002 and September 30, 2003	2

	Unaudited Consolidated Statements of Operations - For the three and nine month periods ended September 30, 2003 and 2002	3

	Unaudited Consolidated Statements of Cash Flows - For the nine month periods ended September 30, 2003 and 2002	4

	Notes to Unaudited Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16

Item 3A.	Quantitative and Qualitative Disclosure About Market Risk	32

Item 4.	Controls and Procedures	33

PART II. OTHER INFORMATION

Items 1-6.		34

SIGNATURES		36

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	December 31, 2002			September 30, 2003
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,743		$	4,426
Accounts receivable, trade (net of allowance for doubtful accounts of $0.5 million at December 31, 2002 and September 30, 2003, respectively)		8,207			8,643
Advances to operators		501			2,697
Other current assets		651			92

Total current assets		14,102			15,858

PROPERTY AND EQUIPMENT, net (full-cost method of accounting for oil and natural gas properties)		120,526			124,030
Investment in Pinnacle Gas Resources, Inc. (Note 4)		—			7,101
Deferred financing costs		760			646

	$	135,388		$	147,635

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable, trade	$	9,957		$	13,502
Accrued liabilities		1,014			1,466
Advances for joint operations		1,550			3,222
Current maturities of long-term debt		1,609			811
Current maturities of seismic obligation payable		1,414			1,456

Total current liabilities		15,544			20,457

LONG-TERM DEBT		37,886			34,154
SEISMIC OBLIGATION PAYABLE		1,103			—
ASSET RETIREMENT OBLIGATION		—			704
DEFERRED INCOME TAXES		7,666			11,326
COMMITMENTS AND CONTINGENCIES (Note 7)
CONVERTIBLE PARTICIPATING PREFERRED STOCK (10,000,000 shares of preferred stock authorized, of which 150,000 are shares designated as convertible participating shares, with 65,294 and 68,559 convertible participating shares issued and outstanding at December 31, 2002 and September 30, 2003, respectively) (Note 8)		6,373			6,925

SHAREHOLDERS’ EQUITY:
Warrants (3,262,821 outstanding at December 31, 2002 and September 30, 2003, respectively)		780			780
Common stock, par value $.01 (40,000,000 shares authorized with 14,177,383 and 14,385,551 issued and outstanding at December 31, 2002 and September 30, 2003, respectively)		142			144
Additional paid in capital		63,224			63,821
Retained earnings		3,058			9,391
Accumulated other comprehensive loss		(388	)		(67	)

		66,816			74,069

	$	135,388		$	147,635

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2002			2003			2002			2003
	(In thousands except per share amounts)
OIL AND NATURAL GAS REVENUES	$	6,753		$	10,123		$	17,559		$	29,615

COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of depreciation shown separately below)		1,334			1,587			3,687			5,071
Depreciation, depletion and amortization		2,726			3,086			7,332			8,727
General and administrative		990			1,624			3,049			4,274
Accretion expense related to asset retirement obligations		—			11			—			29
Stock option compensation		(14	)		296			(70	)		319

Total costs and expenses		5,036			6,604			13,998			18,420

OPERATING INCOME		1,717			3,519			3,561			11,195
OTHER INCOME AND EXPENSES:
Equity in loss of Pinnacle Gas Resources, Inc.		—			(168	)		—			(177	)
Other income and expenses		117			(17	)		245			14
Interest income		16			13			44			50
Interest expense		(58	)		(103	)		(169	)		(419	)
Interest expense, related parties		(590	)		(599	)		(2,023	)		(1,773	)
Capitalized interest		648			696			2,192			2,176

INCOME BEFORE INCOME TAXES		1,850			3,341			3,850			11,066
INCOME TAXES (Note 6)		674			1,259			1,456			4,053

NET INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		1,176			2,082			2,394			7,013
DIVIDENDS AND ACCRETION ON PREFERRED STOCK		173			190			415			552

NET INCOME AVAILABLE TO COMMON SHAREHOLDERS BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		1,003			1,892			1,979			6,461
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		—			—			—			128

NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$	1,003		$	1,892		$	1,979		$	6,333

BASIC EARNINGS PER COMMON SHARE BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE	$	0.07		$	0.13		$	0.14		$	0.46
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF INCOME TAXES		—			—			—			(0.01	)

BASIC EARNINGS PER COMMON SHARE	$	0.07		$	0.13		$	0.14		$	0.45

DILUTED EARNINGS PER COMMON SHARE BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE	$	0.06		$	0.11		$	0.12		$	0.39
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE NET OF INCOME TAXES		—			—			—			(0.01	)

DILUTED EARNINGS PER COMMON SHARE	$	0.06		$	0.11		$	0.12		$	0.38

PRO FORMA AMOUNTS ASSUMING ASSET
RETIREMENTS OBLIGATION IS APPLIED RETROACTIVELY:
BASIC EARNINGS PER COMMON SHARE	$	0.07		$	0.13		$	0.14		$	0.46

DILUTED EARNINGS PER COMMON SHARE	$	0.06		$	0.11		$	0.12		$	0.39

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Nine Months Ended September 30,
	2002			2003
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income before cumulative effect of change in accounting principle	$	2,394		$	7,013
Adjustment to reconcile net income to net cash provided by operating activities-
Depreciation, depletion and amortization		7,332			8,727
Discount accretion		64			93
Equity in loss of Pinnacle Gas Resources, Inc.		—			177
Ineffective derivative instruments		(548	)		—
Interest payable in kind		1,008			1,063
Stock option compensation (benefit)		(70	)		319
Deferred income taxes		1,333			3,918
Changes in assets and liabilities-
Accounts receivable		1,302			(436	)
Other assets		(744	)		326
Accounts payable		107			1,682
Other liabilities		161			627

Net cash provided by operating activities		12,339			23,509

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(20,854	)		(20,368	)
Change in capital expenditure accrual		3,496			1,864
Advances to operators		(33	)		(2,196	)
Advances for joint operations		647			1,672

Net cash used in investing activities		(16,744	)		(19,028	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from the sale of common stock		13			599
Net proceeds from the sale of preferred stock		5,785			—
Net proceeds from the sale of warrants		15			—
Advances under Borrowing Base Credit Facility		6,500			—
Debt repayments		(8,346	)		(5,397	)

Net cash provided by (used in) financing activities		3,967			(4,798	)

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(438	)		(317	)

CASH AND CASH EQUIVALENTS, beginning of period		3,236			4,743

CASH AND CASH EQUIVALENTS, end of period	$	2,798		$	4,426

SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized)	$	—		$	—

Cash paid for income taxes	$	—		$	—

Common stock issued for oil and gas property (Note 8)	$	475		$	—

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

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CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ACCOUNTING POLICIES

The consolidated financial statements included herein have been prepared by Carrizo Oil & Gas, Inc. (the Company), and are unaudited, except for the balance sheet at December 31, 2002, which has been prepared from the audited financial statements at that date. The financial statements reflect the accounts of the Company and its subsidiary after elimination of all significant intercompany transactions and balances. The financial statements reflect necessary adjustments, all of which were of a recurring nature, and are in the opinion of management necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading. The financial statements included herein should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002.

2. MAJOR CUSTOMERS

The Company sold oil and natural gas production representing more than 10% of its oil and natural gas revenues for the nine months ended September 30, 2002 to Cokinos Natural Gas Company (11%); for the nine months ended September 30, 2003 to Gulfmark Energy, Inc. (17%), Cokinos Natural Gas Company (15%) and WMJ Investments Corp. (14%). Because alternate purchasers of oil and natural gas are readily available, the Company believes that the loss of any of its purchaser would not have a material adverse effect on the financial results of the Company.

3. EARNINGS PER COMMON SHARE

Supplemental earnings per share information is provided below:

	For the Three Months Ended September 30,
	(In thousands except share and per share amounts)
	Income						Shares		Per-Share Amount
	2002			2003			2002	2003	2002		2003
Net income	$	1,176		$	2,082
Less: Dividends and Accretion of Discount on Preferred Shares		(173	)		(190	)

Basic Earnings per Share
Net income available to common shareholders		1,003			1,892		14,176,528	14,264,639	$	0.07	$	0.13

Dilutive effect of Stock Options, Warrants and Preferred Stock conversions		—			—		1,725,826	2,625,991

Diluted Earnings per Share
Net income available to common shareholders plus assumed conversions	$	1,003		$	1,892		15,902,354	16,890,630	$	0.06	$	0.11


	For the Nine Months Ended September 30,
	(In thousands except share and per share amounts)
	Income						Shares		Per-Share Amount
	2002			2003			2002	2003	2002		2003
Net income before cumulative effect of change in accounting principle	$	2,394		$	7,013
Less: Dividends and Accretion of Discount on Preferred Shares		(415	)		(552	)

Basic Earnings per Share
Net income available to common shareholders		1,979			6,461		14,152,239	14,224,893	$	0.14	$	0.46

Dilutive effect of Stock Options, Warrants and Preferred Stock conversions		—			—		1,776,091	2,349,345

Diluted Earnings per Share
Net income available to common shareholders plus assumed conversions	$	1,979		$	6,461		15,928,330	16,574,238	$	0.12	$	0.39

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	For the Nine Months Ended September 30,
	(In thousands except share and per share amounts)
	Income						Shares		Per-Share Amount
	2002			2003			2002	2003	2002		2003
Cumulative effect of change in accounting principle net of income taxes	$	—		$	(128	)
Basic Earnings per Share
Net loss available to common shareholders		—			—		14,152,239	14,224,893	$	0.00	$	(0.01	)

Dilutive effect of Stock Options, Warrants and Preferred Stock conversions		—			—		1,776,091	2,349,345

Diluted Earnings per Share
Net income available to common shareholders plus assumed conversions	$	—		$	(128	)	15,928,330	16,574,238	$	0.00	$	(0.01	)


	For the Nine Months Ended September 30,
	(In thousands except share and per share amounts)
	Income						Shares		Per-Share Amount
	2002			2003			2002	2003	2002		2003
Net income	$	2,394		$	6,885
Less: Dividends and Accretion of Discount on Preferred Shares		(415	)		(552	)

Basic Earnings per Share
Net income available to common shareholders		1,979			6,333		14,152,239	14,224,893	$	0.14	$	0.45

Dilutive effect of Stock Options, Warrants and Preferred Stock conversions		—			—		1,776,091	2,349,345

Diluted Earnings per Share
Net income available to common shareholders plus assumed conversions	$	1,979		$	6,333		15,928,330	16,574,238	$	0.12	$	0.38

Basic earnings per common share is based on the weighted average number of shares of common stock outstanding during the periods. Diluted earnings per common share is based on the weighted average number of common shares and all dilutive potential common shares outstanding during the periods. The Company had outstanding 393,833 and 57,000 stock options and 252,632 and zero warrants during the three months ended September 30, 2002 and 2003, respectively, which were antidilutive and were not included in the calculation because the exercise price of these instruments exceeded the underlying market value of the options and warrants. The Company had outstanding 406,833 and 129,000 stock options and 252,632 warrants during the nine months ended September 30, 2002 and 2003, respectively, which were antidilutive and were not included in the calculation because the exercise price of these instruments exceeded the underlying market value of the options and warrants. At September 30, 2002 and 2003, the Company also had 1,090,649 and 1,202,791 shares, respectively, based on the assumed conversion of the Series B Convertible Participating Preferred Stock, that were antidilutive and were not included in the calculation.

4. INVESTMENT IN PINNACLE GAS RESOURCES, INC.

The Pinnacle Transaction

On June 23, 2003, pursuant to a Subscription and Contribution Agreement by and among the Company and its wholly-owned subsidiary, CCBM, Inc. (“CCBM”), Rocky Mountain Gas, Inc. (“RMG”) and the Credit Suisse First Boston Private Equity entities, named therein (the “CSFB Parties”), CCBM and RMG contributed their respective interests, having a estimated fair value of approximately $7.5 million each, in (1) leases in the Clearmont, Kirby, Arvada and Bobcat project areas and (2) oil and gas reserves in the Bobcat project area to a newly formed entity, Pinnacle Gas Resources, Inc., a Delaware corporation (“Pinnacle”). In exchange for the contribution of these assets, CCBM and RMG each received 37.5% of the common stock of Pinnacle (“Pinnacle Common Stock”) as of the closing date and options to purchase Pinnacle Common Stock (“Pinnacle Stock Options”). CCBM no longer has a drilling obligation in connection with the oil and natural gas leases contributed to Pinnacle (see “General Overview” in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a further discussion).

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Simultaneously with the contribution of these assets, the CSFB Parties contributed approximately $17.6 million of cash to Pinnacle in return for the Redeemable Preferred Stock of Pinnacle (“Pinnacle Preferred Stock”), 25% of the Pinnacle Common Stock as of the closing date and warrants to purchase Pinnacle Common Stock (“Pinnacle Warrants”). The CSFB Parties also agreed to contribute additional cash, under certain circumstances, of up to approximately $11.8 million to Pinnacle to fund future drilling, development and acquisitions. The CSFB Parties currently have greater than 50% of the voting power of the Pinnacle capital stock through their ownership of Pinnacle Common Stock and Pinnacle Preferred Stock.

Currently, on a fully diluted basis, assuming that all parties exercised their Pinnacle Warrants and Pinnacle Options, the CSFB Parties, CCBM and RMG would have ownership interests of approximately 46.2%, 26.9% and 26.9%, respectively. On a fully-diluted basis, assuming the additional $11.8 million of cash was contributed by the CSFB Parties and all Pinnacle Warrants and Pinnacle Options were exercised by all parties, the CSFB Parties would own 54.6% of Pinnacle and CCBM and RMG would each own 22.7% of Pinnacle.

Immediately following the contribution and funding, Pinnacle used approximately $6.2 million of the proceeds from the funding to acquire an approximate 50% working interest in existing leases and approximately 36,529 gross acres prospective for coalbed methane development in the Powder River Basin of Wyoming from Gastar Exploration, Ltd. The leases include 95 producing coalbed methane wells currently in the early stages of dewatering. These wells are producing at a combined gross rate of approximately 2.5 MMcfd, or an estimated 1 MMcfd net to Pinnacle. Pinnacle also agreed to fund up to $14.9 million of future drilling and development costs on these properties on behalf of Gastar prior to December 31, 2005. The drilling and development work will be done under the terms of an earn-in joint venture agreement between Pinnacle and Gastar. The majority of these leases are part of, or adjacent to, the Bobcat project area. All of CCBM and RMG’s interests in the Bobcat project area, the only producing coalbed methane property owned by CCBM prior to the transaction, were contributed to Pinnacle. As of June 30, 2003, Pinnacle owned interests in approximately 131,000 gross acres in the Powder River Basin.

Prior to and in connection with its contribution of assets to Pinnacle, CCBM paid RMG approximately $1.8 million in cash as part of its outstanding purchase obligation on the coalbed methane property interests CCBM previously acquired from RMG. The approximate $1.0 million remaining balance of CCBM’s obligation to RMG is scheduled to be paid in monthly installments of approximately $52,805 through November 2004 and a balloon payment on December 31, 2004. The RMG note is secured solely by CCBM’s interests in the remaining oil and natural gas leases in Wyoming and Montana. In connection with the Company’s investment in Pinnacle, the Company received a reduction in the principal amount of the RMG note of approximately $1.5 million and relinquished the right to receive certain revenues related to the properties contributed to Pinnacle.

CCBM continues its coalbed methane business activities and, in addition to its interest in Pinnacle, owns direct interests in approximately 189,000 gross acres of coalbed methane properties in the Castle Rock project area in Montana and the Oyster Ridge project area in Wyoming, which were not contributed to Pinnacle. CCBM and RMG will continue to conduct exploration and development activities on these properties as well as pursue other potential acquisitions. The Bobcat property was producing approximately 400 Mcfe of coalbed methane gas net to CCBM’s interest immediately prior to its contribution to Pinnacle. Other than indirectly through Pinnacle, CCBM currently has no proved reserves of, and is no longer receiving revenue from, coalbed methane gas.

Accounting and Tax Treatment

For accounting purposes, the transaction will be treated as a reclassification of a portion of CCBM’s investments in the contributed properties. The property contribution made by CCBM to Pinnacle is intended to be treated as a tax-deferred exchange as constituted by property transfers under section 351(a) of the Internal Revenue Code of 1986, as amended.

The FASB issued Interpretation 46, “Consolidation of Variable Interest Entities” (“FIN 46”), in January 2003. FIN 46 requires the consolidation of certain types of entities in which a company absorbs a majority of another entity’s expected losses, receives a majority of the other entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interests in the other entity. These entities are called “variable interest entities”. The provisions of FIN 46 are effective for the Company in the second quarter for new transactions or entities formed in 2003 and in the third quarter for transactions or entities formed prior to 2003.

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below), Carrizo could be defined as the primary beneficiary if the projected cash flows analysis indicated losses in excess of the equity invested. The initial determination of whether an entity is a VIE is to be reconsidered only when one or more of the following occur (1) the entity’s governing documents or the contractual arrangements among the parties involved change, (2) the equity investment of some part thereof is returned to the investors, and other parties become exposed to expected losses or (3) the entity undertakes additional activities or acquires additional assets that increase the entity’s expected losses.

We have determined that we should not consolidate Pinnacle, under FIN 46, because our current projected cash flow analysis of Pinnacle’s operations at inception indicates that Pinnacle is not a VIE. Accordingly, our investment in Pinnacle has been recorded using the equity method of accounting.

The reclassification of investments in contributed properties resulting from the transaction with Pinnacle are reflected in accordance with the full cost method of accounting in the Company’s balance sheet included in this Form 10-Q for the nine months ended September 30, 2003.

Related Parties in the Pinnacle Transaction

Steven A. Webster, Chairman of the Board of the Company, is also a managing director of Credit Suisse First Boston Private Equity and is therefore a related party to this transaction.

Transition Services Agreement

The Company entered into a transition services agreement with Pinnacle pursuant to which the Company will provide certain accounting, treasury, tax, insurance and financial reporting functions to Pinnacle through the end of 2003 for a monthly fee equal to the Company’s actual cost to provide such services. After December 31, 2003, the agreement will automatically renew on a quarterly basis unless one of the parties gives notice of its intent to terminate the agreement.

Similarly, Pinnacle has also entered into a transition services agreement with RMG to provide Pinnacle assistance in setting up operational accounting and management systems for a monthly fee equal to the actual cost to provide such services. After December 31, 2003, the agreement will automatically renew on a quarterly basis unless one of the parties gives notice of its intent to terminate the agreement.

5. LONG-TERM DEBT:

At December 31, 2002 and September 30, 2003, long-term debt consisted of the following:

	December 31, 2002			September 30, 2003
Borrowing base facility	$	8,500		$	7,000
Senior subordinated notes, related parties		25,478			26,605
Capital lease obligations		267			338
Non-recourse note payable to Rocky Mountain Gas, Inc.		5,250			1,022

		39,495			34,965
Less: current maturities		(1,609	)		(811	)

	$	37,886		$	34,154

On May 24, 2002, the Company entered into a credit agreement with Hibernia National Bank (the “Hibernia Facility”) which matures on January 31, 2005, and repaid its existing facility with Compass Bank (the “Compass Facility”). The Hibernia Facility provides a revolving line of credit of up to $30.0 million. It is secured by substantially all of the Company’s producing oil and gas properties assets and is guaranteed by the Company’s wholly owned subsidiary CCBM, Inc.

The borrowing base will be determined by Hibernia National Bank at least semi-annually on each October 31 and April 30. The initial borrowing base was $12.0 million, and the borrowing base as of September 30, 2003 was $13.5 million. Each party to the credit agreement can request one unscheduled borrowing base determination subsequent to each scheduled determination. The

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borrowing base will at all times equal the borrowing base most recently determined by Hibernia National Bank, less quarterly borrowing base reductions required subsequent to such determination. Hibernia National Bank will reset the borrowing base amount at each scheduled and each unscheduled borrowing base determination date. The initial quarterly borrowing base reduction, which commenced on June 30, 2002, was $1.3 million. The quarterly borrowing base reduction effective January 31, 2003 was $1.8 million. There was an increase in the borrowing base for the quarter ended June 30, 2003 of $2.2 million.

On December 12, 2002, the Company entered into an Amended and Restated Credit Agreement with Hibernia National Bank that provided additional availability under the Hibernia Facility in the amount of $2.5 million which was structured as an additional “Facility B” under the Hibernia Facility. As such, the total borrowing base under the Hibernia Facility as of December 31, 2002 and September 30, 2003 was $15.5 million and $13.5 million, respectively, of which $8.5 million and $7.0 million was outstanding on December 31, 2002 and September 30, 2003, respectively. The Facility B bore interest at LIBOR plus 3.375%, was secured by certain leases and working interests in oil and natural gas wells and matured on April 30, 2003.

If the principal balance of the Hibernia Facility ever exceeds the borrowing base as reduced by the quarterly borrowing base reduction (as described above), the principal balance in excess of such reduced borrowing base will be due as of the date of such reduction. Otherwise, any unpaid principal or interest will be due at maturity.

If the principal balance of the Hibernia Facility ever exceeds any re-determined borrowing base, the Company has the option within thirty days to (individually or in combination): (i) make a lump sum payment curing the deficiency; (ii) pledge additional collateral sufficient in Hibernia National Bank’s opinion to increase the borrowing base and cure the deficiency; or (iii) begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Such payments are in addition to any payments that may come due as a result of the quarterly borrowing base reductions.

For each tranche of principal borrowed under the revolving line of credit, the interest rate will be, at the Company’s option: (i) the Eurodollar Rate, plus an applicable margin equal to 2.375% if the amount borrowed is greater than or equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than 90% but greater than or equal to 50% of the borrowing base, or 1.625% if the amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate, plus an applicable margin of 0.375% if the amount borrowed is greater than or equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on either the last day of each Eurodollar option period or monthly, whichever is earlier. Interest on Base Rate Loans is payable monthly.

The Company is subject to certain covenants under the terms of the Hibernia Facility, including, but not limited to the maintenance of the following financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including availability under the borrowing base), (ii) a minimum quarterly debt services coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0 million,plus100% of all subsequent common and preferred equity contributed by shareholders,plus50% of all positive earning occurring subsequent to such quarter end, all ratios as more particularly discussed in the credit facility.The Hibernia Facility also places restrictions on additional indebtedness, dividends to non-preferred stockholders, liens, investments, mergers, acquisitions, asset dispositions, asset pledges and mortgages, change of control, repurchase or redemption for cash of the Company’s common or preferred stock, speculative commodity transactions, and other matters.

At December 31, 2002 and September 30, 2003, amounts outstanding under the Hibernia Facility totaled $8.5 million and $7.0 million, respectively, with an additional $4.3 million and $6.5 million, respectively, under Facility A and $2.5 million under Facility B at December 31, 2002 available for future borrowings. No amounts under the Compass Facility were outstanding at December 31, 2002. At December 31, 2002 and September 30, 2003, one letter of credit was issued and outstanding under the Hibernia Facility in the amount of $0.2 million.

On June 29, 2001, CCBM, Inc., a wholly owned subsidiary of the Company (“CCBM”), issued a non-recourse promissory note payable in the amount of $7.5 million to RMG as consideration for certain interests in oil and natural gas leases held by RMG in Wyoming and Montana. The RMG note was payable in 41 monthly principal payments of $0.1 million plus interest at 8% per annum commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is secured solely by CCBM’s interests in the oil and natural gas leases in Wyoming and Montana. At December 31, 2002 and September 30, 2003, the outstanding principal balance of this note was $5.3 million and $1.0 million, respectively. In connection with the Company’s investment in Pinnacle (see Note 3), the Company received a reduction in the principal amount of the RMG note of approximately $1.5 million and relinquished the right to certain revenues related to the properties contributed to Pinnacle.

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million. The lease is payable in 36 monthly payments of $3,462 including interest at 6.4% per annum. In May 2003, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $3,030 including interest at 5.5% per annum. In August 2003, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $2,179 including interest at 6.0% per annum. The Company has the option to acquire the equipment at the conclusion of the lease for $1 under all of these leases. DD&A on the capital leases for the three months ended September 30, 2002 and 2003 amounted to $6,000 and $14,000, respectively. DD&A on the capital leases for the nine months ended September 30, 2002 and 2003 amounted to $18,000 and $35,000 respectively, and accumulated DD&A on the leased equipment at December 31, 2002 and September 30, 2003 amounted to $28,000 and $62,000, respectively.

In December 1999, the Company consummated the sale of $22.0 million principal amount of 9% Senior Subordinated Notes due 2007 (the “Subordinated Notes”) and $8.0 million of common stock and Warrants. The Company sold $17.6 million, $2.2 million, $0.8 million, $0.8 million and $0.8 million principal amount of Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of the Company’s common stock and 2,208,152, 276,019, 92,006, 92,006 and 92,006 Warrants to CB Capital Investors, L.P. (now known as JPMorgan Partners, LLC), Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P. Hamilton, respectively. The Subordinated Notes were sold at a discount of $0.7 million, which is being amortized over the life of the notes. Interest payments are due quarterly commencing on March 31, 2000. The Company may elect, until December 2004, to increase the amount of the Subordinated Notes for 60% of the interest which would otherwise be payable in cash. As of December 31, 2002 and September 30, 2003, the outstanding balance of the Subordinated Notes had been increased by $3.9 million and $5.0 million, respectively, for such interest paid in kind.

The Company is subject to certain covenants under the terms of the Subordinated Notes securities purchase agreement, including but not limited to, (a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of EBITDA (earnings before interest, taxes, depreciation and amortization) to quarterly Debt Service (as defined in the agreement) of not less than 1.00 to 1.00, and (c) a limitation of its capital expenditures to an amount equal to the Company’s EBITDA for the immediately prior fiscal year (unless approved by the Company’s Board of Directors and a JPMorgan Partners, LLC appointed director), as well as limits on the Company’s ability to (i) incur indebtedness, (ii) incur or allow liens, (iii) engage in mergers, consolidation, sales of assets and acquisitions, (iv) declare dividends and effect certain distributions (including restrictions on distributions upon the Common Stock), (v) engage in transactions with affiliates and (vi) make certain repayments and prepayments, including any prepayment of the subordinated debt, indebtedness that is guaranteed or credit-enhanced by any affiliate of the Company, and prepayments that effect certain permanent reductions in revolving credit facilities. EBITDA was part of a negotiated covenant with the purchasers and is presented here as a disclosure of the Company’s covenant obligations.

At December 31, 2002 and September 30, 2003, the Company believes it was in compliance with all of its debt covenants.

6. INCOME TAXES

The Company estimates its annual effective tax rate to be approximately 35%, which also approximates its statutory rate. The Company provided deferred tax expense of $0.6 million and $1.2 million for the three months ended September 30, 2002 and 2003, respectively, and $1.3 million and $3.9 million for the nine months ended September 30, 2002 and 2003, respectively.

7. 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 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.

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Pursuant to agreements entered into with RMG in June 2001, CCBM has an obligation to fund $2.5 million of drilling costs on behalf of RMG. Through September 30, 2003, CCBM had satisfied $2.2 million of the drilling obligation on behalf of RMG.

8. CONVERTIBLE PARTICIPATING PREFERRED STOCK

In February 2002, the Company consummated the sale of 60,000 shares of Convertible Participating Series B Preferred Stock (the “Series B Preferred Stock”) and Warrants to purchase 252,632 shares of Carrizo’s common stock for an aggregate purchase price of $6.0 million. The Company sold 40,000 and 20,000 shares of Series B Preferred Stock and 168,422 and 84,210 Warrants to Mellon Ventures, Inc. and Steven A. Webster, respectively. The Series B Preferred Stock is convertible into common stock by the investors at a conversion price of $5.70 per share, subject to adjustments, and is initially convertible into 1,052,632 shares of common stock. Dividends on the Series B Preferred Stock will be payable in either cash at a rate of 8% per annum or, at the Company’s option, by payment in kind of additional shares of the same series of preferred stock at a rate of 10% per annum. At December 31, 2002 and September 30, 2003, the outstanding balance of the Series B Preferred Stock had been increased by $0.5 million (5,294 shares) and $0.9 million (8,559 shares), respectively, for dividends paid in kind. At September 30, 2003, the Company had accrued a dividend of $0.2 million (1,714 shares) that is payable on December 31, 2003. The Series B Preferred Stock is redeemable at varying prices in whole or in part at the holders’ option after three years or at the Company’s option at any time. The Series B Preferred Stock will also participate in any dividends declared on the common stock. Holders of the Series B Preferred Stock will receive a liquidation preference upon the liquidation of, or certain mergers or sales of substantially all assets involving, the Company. Such holders will also have the option of receiving a change of control repayment price upon certain deemed change of control transactions. The warrants have a five-year term and entitle the holders to purchase up to 252,632 shares of Carrizo’s common stock at a price of $5.94 per share, subject to adjustments, and are exercisable at any time after issuance. The warrants may be exercised on a cashless exercise basis.

Net proceeds of this financing were approximately $5.8 million and were used primarily to fund the Company’s ongoing exploration and development program and for general corporate purposes.

9. SHAREHOLDER’S EQUITY

The Company issued 106,472 and 208,168 shares of common stock during the nine months ended September 30, 2002 and 2003, respectively. The shares issued during the nine months ended September 30, 2002 were partial consideration for the acquisition of an interest in certain oil and natural gas properties and the shares issued during the nine months ended September 30, 2003 were the result of the exercise of options granted under the Company’s Incentive Plan.

In June of 1997, the Company established the Incentive Plan of Carrizo Oil & Gas, Inc. (the “Incentive Plan”). In October 1995, the FASB issued SFAS No. 123, “Accounting for Stock-Based Compensation”, which requires the Company to record stock-based compensation at fair value. In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock Based Compensation – Transition and Disclosure”. The Company has adopted the disclosure requirements of SFAS No. 148 and has elected to record employee compensation expense utilizing the intrinsic value method permitted under Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees”. The Company accounts for its employees’ stock-based compensation plan under APB Opinion No. 25 and its related interpretations. Accordingly, any deferred compensation expense would be recorded for stock options based on the excess of the market value of the common stock on the date the options were granted over the aggregate exercise price of the options. This deferred compensation would be amortized over the vesting period of each option. Had compensation cost been determined consistent with SFAS No. 123 “Accounting for Stock-Based Compensation” for all options, the Company’s net income (loss) and earnings per share would have been as follows:

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	For the Three Months ended September 30,						For the Nine Months ended September 30,
	2002			2003			2002			2003
	(In thousands except per share amounts)						(In thousands except per share amounts)
Net income available to common shareholders, as reported	$	1,003		$	1,892		$	1,979		$	6,333

Less: Total stock-based employee compensation expense determined under fair value method for all awards, net of related tax effects		(193	)		(132	)		(452	)		(397	)

Pro forma net income (loss) available to common shareholders	$	810		$	1,760		$	1,527		$	5,936

Net income per common share, as reported:
Basic	$	0.07		$	0.13		$	0.14		$	0.45
Diluted		0.06			0.11			0.12			0.38

Pro Forma net income (loss) per common share, as if value method had been applied to all awards:
Basic	$	0.06		$	0.12		$	0.11		$	0.42
Diluted		0.05			0.10			0.10			0.36

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Diluted earnings per share amounts for the three months ended September 30, 2002 and 2003 are based upon 15,902,354 and 16,890,630 shares, respectively, that include the dilutive effect of assumed stock option and warrant exercises of 1,725,826 and 2,625,911, respectively. Diluted earnings per share amounts for the nine months ended September 30, 2002 and 2003 are based upon 15,928,330 and 16,574,238 shares, respectively, that include the dilutive effect of assumed stock options and warrant exercises of 1,776,091 and 2,349,345, respectively.

Comprehensive income for the three and nine months ended September 30, 2002 and 2003 was as follows:

	For the Three Months ended September 30,					For the Nine Months ended September 30,
	2002			2003		2002			2003
Net income	$	1,176		$	2,082	$	2,394		$	6,885

Net change in fair value of hedging instruments		(586	)		612		(1,083	)		321

Comprehensive income	$	590		$	2,694	$	1,311		$	7,206

10. CHANGE IN ACCOUNTING PRINCIPLE

In June 2001, the Financial Accounting Standards Board issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. This Statement is effective for fiscal years beginning after June 15, 2002, and the Company adopted the Statement effective January 1, 2003. During the three months ended March 31, 2003, the Company recorded a cumulative effect of change in accounting principle of $0.1 million, $0.4 million as proved properties and $0.5 million as a liability for its plugging and abandonment expenses. The Company includes Asset Retirement Obligation costs, liabilities and related discounted cash flows in its ceiling test calculations.

11. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY

The Company’s operations involve managing market risks related to changes in commodity prices. Derivative financial instruments, specifically swaps, futures, options and other contracts, are used to reduce and manage those risks. The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. The Company enters into swaps, options, collars and other derivative contracts to hedge the price risks associated with a portion of anticipated future oil and natural gas production. While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. The Company enters into the majority of its hedging transactions with two counterparties and a netting agreement is in place with those counterparties. The Company does not obtain collateral to support the agreements but monitors the financial viability of counterparties and believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price risk. The Company has some risk of accounting loss since the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction.

As of December 31, 2002 and September 30, 2003, $0.4 million and $67,000, net of tax of $0.2 million and $36,000, respectively, remained in accumulated other comprehensive income related to the valuation of the Company’s hedging positions.

Total oil purchased and sold under swaps and collars during the three months ended September 30, 2002 and 2003 was 33,600 Bbls and 24,400 Bbls, respectively. Total natural gas purchased and sold under swaps and collars during the three months ended September 30, 2002 and 2003 was 731,000 MMBtu and 828,000 MMBtu, respectively. Total oil purchased and sold under swaps and collars during the nine months ended September 30, 2002 and 2003 was 79,100 Bbls and 150,700 Bbls, respectively. Total natural gas purchased and sold under swaps and collars during the nine months ended September 30, 2002 and 2003 was 3,094,000 MMBtu and 2,187,000 MMBtu, respectively. The net losses realized by the Company under such hedging arrangements was $0.1 million and $0.1 million for the three months ended September 30, 2002 and 2003, respectively, and are included in oil and natural gas revenues. The net losses realized by the Company under such hedging arrangements were $0.4 million and $1.8 million for the nine months ended September 30, 2002 and 2003, respectively, and are included in oil and natural gas revenues.

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At December 31, 2002 and September 30, 2003 the Company had the following outstanding hedge positions:

As of December 31, 2002
Quarter	Contract Volumes		Average Fixed Price		Average Floor Price		Average Ceiling Price
Quarter	BBls	MMbtu	Average Fixed Price		Average Floor Price		Average Ceiling Price
First Quarter 2003	27,000		$	24.85
First Quarter 2003	36,000				$	23.50	$	26.50
First Quarter 2003		540,000				3.40		5.25
Second Quarter 2003	27,300			24.85
Second Quarter 2003	36,000					23.50		26.50
Second Quarter 2003		546,000				3.40		5.25
Third Quarter 2003		552,000				3.40		5.25
Fourth Quarter 2003		552,000				3.40		5.25

As of September 30, 2003
Quarter	Contract Volumes		Average Fixed Price		Average Floor Price		Average Ceiling Price
Quarter	BBls	MMbtu	Average Fixed Price		Average Floor Price		Average Ceiling Price
Fourth Quarter 2003	30,700		$	30.22
Fourth Quarter 2003		552,000				3.40		5.25
First Quarter 2004		546,000				4.10		7.00
Second Quarter 2004		273,000				4.00		5.20
Third Quarter 2004		276,000				4.00		5.20
Fourth Quarter 2004		93,000				4.00		5.20

During October 2003, the Company entered into swap arrangements covering 30,200 Bbls of oil for November 2003 through February 2004 production with an average fixed price of $30.26.

In addition to the hedge positions above, during the second quarter of 2003, the Company acquired options to sell 6,000 MMBtu of natural gas per day for the period July 2003 through August 2003 (552,000 MMBtu) at $8.00 per MMBtu for approximately $119,000. The Company acquired these options to protect its cash position against potential margin calls on certain natural gas derivatives due to large increases in the price of natural gas. These options were classified as derivatives. As of September 30, 2003, these options have expired and a charge of $28,000 and $119,000 has been included in other income and expense for the three and nine months ended September 30, 2003, respectively.

12. NEW ACCOUNTING PRONOUNCEMENTS

The FASB issued Interpretation 46, “Consolidation of Variable Interest Entities” (“FIN 46”), in January 2003. FIN 46 requires the consolidation of certain types of entities in which a company absorbs a majority of another entity’s expected losses, receives a majority of the other entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interests in the other entity. The Company has identified no transactions or related entities that required consolidation under this interpretation.

Currently, the FASB and representatives of the SEC accounting staff are engaged in discussions on the issue of whether SFAS 141, “Business Combinations” and SFAS 142, “Goodwill and Other Intangibles”, which were effective June 30, 2001, called for mineral rights held under a lease or other contractual arrangement to be classified on the balance sheet as intangible assets and accompanied by specific footnote disclosures. Historically, oil and gas companies, including the Company, have included these costs with all other oil and gas property costs in Property, Plant, and Equipment on the consolidated balance sheet.

In the event this interpretation is adopted, a substantial portion of the acquisition costs of oil and gas properties would be required to be classified on the balance sheet as an intangible asset. The Company believes this interpretation would not have a material effect on our results of operations for the periods presented or in the future as these intangible assets would be depleted using the units of production method in a manner consistent with the method currently used to calculate depletion, depreciation, and amortization expense (“DD&A”) on those assets.

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13. SUBSEQUENT EVENTS

Exchange Transaction on October 10, 2003

Pursuant to an exchange election provided in a letter agreement, dated May 1, 2001, with certain participants in the Carrizo 2001 Seismic and Acreage Program (the “2001 Program”), the Company is issuing to such participants, who have exercised their election, approximately 168,000 shares of its common stock in exchange for the participants’ entire interest in the 2001 Program, including approximately 350 square miles of 3-D seismic data and working interests in certain producing properties. The exchange transaction was effective on October 10, 2003 and was valued using the closing price of the Company’s stock on that date, for a total of approximately $1.2 million.

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ITEM 2 - MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management’s discussion and analysis of certain significant factors that have affected certain aspects of the Company’s financial position and results of operations during the periods included in the accompanying unaudited financial statements. This discussion should be read in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the annual financial statements included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002 and the unaudited financial statements included elsewhere herein. Unless otherwise indicated by the context, references herein to “Carrizo” or “Company” mean Carrizo Oil & Gas, Inc., a Texas corporation.

General Overview

The Company began operations in September 1993 and initially focused on the acquisition of producing properties. As a result of the increasing availability of economic onshore 3-D seismic surveys, the Company began to obtain 3-D seismic data and options to lease substantial acreage in 1995 and began to drill its 3-D based prospects in 1996. The Company drilled 25 gross wells in 2002 and 22 gross wells through the nine months ended September 30, 2003 in the Gulf Coast region. The Company has budgeted to drill up to 35 gross wells (9.9 net) in the Gulf Coast region in 2003; however, the actual number of wells drilled will vary depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, Company cash flow, success of drilling programs, weather delays and other factors. If the Company drills the number of wells it has budgeted for 2003, depreciation, depletion and amortization, oil and gas operating expenses and production are expected to increase over levels incurred in 2002. The Company has typically retained the majority of its interests in shallow, normally pressured prospects and sold a portion of its interests in deeper, overpressured prospects.

The Company has primarily grown through the internal development of properties within its exploration project areas, although the Company acquired properties with existing production in the Camp Hill Project in late 1993, the Encinitas Project in early 1995 and the La Rosa Project in 1996. The Company made these acquisitions through the use of limited partnerships with Carrizo or Carrizo Production, Inc. as the general partner. In addition, in November 1998, the Company acquired assets in Wharton County, Texas in the Jones Branch project area for approximately $3.0 million.

During the second quarter of 2001, the Company formed CCBM, Inc. (“CCBM”) as a wholly-owned subsidiary. CCBM was formed to acquire interests in certain oil and gas leases in Wyoming and Montana in areas prospective for coalbed methane and develop such interests. The Company also acquired a 1,940 gross acre coalbed methane property in Wyoming, the “Bobcat Project”, for $0.7 million in cash and common stock in July 2002. CCBM planned to spend up to $5.0 million for drilling costs on these leases through December 2003, 50% of which would be spent pursuant to an obligation to fund $2.5 million of drilling costs on behalf of RMG, from whom the interests in the leases were acquired. Through September 30, 2003, CCBM has satisfied $2.2 million of its $2.5 million obligation on behalf of RMG. CCBM has drilled or acquired 75 gross wells (28.0 net) and incurred total drilling costs of $3.0 million through December 31, 2002 and drilled two gross wells (one net) and incurred total drilling costs of $0.4 million during the nine months ended September 30, 2003. These wells typically take up to 18 months to evaluate and determine whether or not they are successful. CCBM had budgeted to drill up to 50 gross (18 net) wells in 2003 before the Pinnacle transaction discussed below. CCBM no longer has a drilling obligation in connection with the properties contributed to Pinnacle. Accordingly, CCBM has no plans to drill any coalbed methane wells in the second half of 2003. The coalbed methane wells include 17 wells acquired as a result of the Bobcat acquisition. CCBM contributed its interests in leasehold acreage and 59 gross wells (24 net) to Pinnacle in June 2003.

During the second quarter of 2003, CCBM contributed its interests in (1) leases in the Clearmont, Kirby, Arvada and Bobcat project area and (2) oil and gas reserves in the Bobcat project area to a newly formed entity, Pinnacle Gas Resources, Inc. (“Pinnacle”). In exchange for the contribution of these assets, CCBM received common stock of Pinnacle and options to purchase Pinnacle common stock. See “The Pinnacle Transaction” later in this section for a complete description of this transaction. The Company retained its interests in approximately 189,000 gross acres in the Castle Rock project area in Montana and the Oyster Ridge project area in Wyoming.

Pursuant to an exchange election provided in a letter agreement dated May 1, 2001, with certain participants in the Carrizo 2001 Seismic and Acreage Program (the “2001 Program”), the Company issued to those participants who exercised their election approximately 168,000 shares of its common stock in exchange for the participants’ program interest in the 2001 Program, including approximately 350 square miles of 3-D seismic data and working interests in certain producing properties. The exchange transaction is effective on October 10, 2003 and was valued at approximately $1.2 million using the close price of the Company’s stock on that date.

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The Company has been awarded seven acreage blocks, consisting of one “Traditional” and three “Promote” licenses, in the United Kingdom’s 21^st Round of Licensing. The awarded blocks, to explore for oil and natural gas totaling approximately 209,000 acres, are located within mature producing areas of the Central and Southern North Sea in water depths of 30 to 350 feet. The Company plans to promote these interests to other parties experienced in drilling and operating in this region. Geological and geophysical costs will be incurred in an attempt to maximize the value of the Company’s retained interest. The Company’s estimated project commitments through mid-2005 are $0.7 million, comprised of $0.3 million for seismic data, $0.1 million for leasehold costs and $0.1 million for data processing in 2003 and $0.2 million for seismic data purchases in 2004. The Promote licenses do not have drilling commitments and the Traditional license would be cancelled after two years if the Company or its assignee elects not to commit to drilling a well.

Total oil purchased and sold under swaps and collars during the three months ended September 30, 2002 and 2003 was 33,600 Bbls and 24,400 Bbls, respectively. Total natural gas purchased and sold under swaps and collars during the three months ended September 30, 2002 and 2003 was 731,000 MMBtu and 828,000 MMBtu, respectively. Total oil purchased and sold under swaps and collars during the nine months ended September 30, 2002 and 2003 was 79,100 Bbls and 150,700 Bbls, respectively. Total natural gas purchased and sold under swaps and collars during the nine months ended September 30, 2002 and 2003 was 3,094,000 MMBtu and 2,187,000 MMBtu, respectively. The net losses realized by the Company under such hedging arrangements were $0.1 million and $0.1 million for the three months ended September 30, 2002 and 2003, respectively, and are included in oil and natural gas revenues. The net losses realized by the Company under such hedging arrangements were $0.4 million and $1.8 million for the nine months ended September 30, 2002 and 2003, respectively, and are included in oil and natural gas revenues.

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At December 31, 2002 and September 30, 2003 the Company had the following outstanding hedge positions:

As of December 31, 2002
	Contract Volumes		Average Fixed Price		Average Floor Price		Average Ceiling Price
Quarter	BBls	MMbtu	Average Fixed Price		Average Floor Price		Average Ceiling Price
First Quarter 2003	27,000		$	24.85
First Quarter 2003	36,000				$	23.50	$	26.50
First Quarter 2003		540,000				3.40		5.25
Second Quarter 2003	27,300			24.85
Second Quarter 2003	36,000					23.50		26.50
Second Quarter 2003		546,000				3.40		5.25
Third Quarter 2003		552,000				3.40		5.25
Fourth Quarter 2003		552,000				3.40		5.25

As of September 30, 2003
	Contract Volumes		Average Fixed Price		Average Floor Price		Average Ceiling Price
Quarter	BBls	MMbtu	Average Fixed Price		Average Floor Price		Average Ceiling Price
Fourth Quarter 2003	30,700		$	30.22
Fourth Quarter 2003		552,000				3.40		5.25
First Quarter 2004		546,000				4.10		7.00
Second Quarter 2004		273,000				4.00		5.20
Third Quarter 2004		276,000				4.00		5.20
Fourth Quarter 2004		93,000				4.00		5.20

During October 2003, the Company entered into swap arrangements covering 30,200 Bbls of oil for November 2003 through February 2004 production with an average fixed price of $30.26.

In addition to the hedge positions above, during the second quarter of 2003, the Company acquired options to sell 6,000 MMBtu of natural gas per day for the period July 2003 through August 2003 (552,000 MMBtu) at $8.00 per MMBtu for approximately $119,000. The Company acquired these options to protect its cash position against potential margin calls on certain natural gas derivatives due to large increases in the price of natural gas. These options were classified as derivatives. As of September 30, 2003, these options had expired and a charge of $28,000 and $119,000 has been included in other income and expense for the three and nine months ended September 30, 2003, respectively.

Results of Operations

Three Months Ended September 30, 2003,

Compared to the Three Months Ended September 30, 2002

Oil and natural gas revenues for the three months ended September 30, 2003 increased 50% to $10.1 million from $6.8 million for the same period in 2002. Production volumes for natural gas during the three months ended September 30, 2003 increased 19% to 1.4 Bcf from 1.1 Bcf for the same period in 2002. Average natural gas prices increased 46% to $5.21 per Mcf in the third quarter of 2003 from $3.57 per Mcf in the same period in 2002. Production volumes for oil in the third quarter of 2003 decreased 7% to 105 MBbls from 113 MBbls for the same period in 2002. Average oil prices increased 22% to $29.15 per barrel in the third quarter of 2003 from $23.82 per barrel in the same period in 2002. The decrease in oil production was due primarily to the natural decline in production from the Staubach #1, Burkhart #1R, and other wells, offset by the commencement of production at the Pauline Huebner A-382 #1, Hankamer #1, Beach House #1 and Espree #1 wells. The increase in natural gas production was primarily due to the commencement of production at the Burkhart #1R, Pauline Huebner A-382 #1 Matthes-Huebner #1, and Hankamer #1 wells offset by a workover at the Delta Farms #1, the natural decline in production at the Delta Farms #1, the Staubach #1, Riverdale #2 and other wells. Oil and natural gas revenues include the impact of hedging activities as discussed above under “General Overview”.

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The following table summarizes production volumes, average sales prices and operating revenues for the Company’s oil and natural gas operations for the three months ended September 30, 2002 and 2003:

	September 30,				2003 Period Compared to 2002 Period
	September 30,				Increase (Decrease)			% Increase (Decrease)
	2002		2003		Increase (Decrease)			% Increase (Decrease)
Production volumes -
Oil and condensate (MBbls)		113		105		(8	)	(7	)%
Natural gas (MMcf)		1,137		1,355		218		19	%
Average sales prices - (1)
Oil and condensate (per Bbls)	$	23.82	$	29.15	$	5.33		22	%
Natural gas (per Mcf)		3.57		5.21		1.64		46	%
Operating revenues (In thousands)-
Oil and condensate	$	2,691	$	3,064	$	373		14	%
Natural gas		4,062		7,059		2,997		74	%

Total	$	6,753	$	10,123	$	3,370		50	%

(1)	Includes impact of hedging activities.

Oil and natural gas operating expenses for the three months ended September 30, 2003 increased 19% to $1.6 million from $1.3 million for the same period in 2002 primarily due to higher severance taxes and other operating costs associated with the addition of new production. Operating expenses per equivalent unit increased 9% to $0.80 per Mcfe in the third quarter of 2003 from $0.74 per Mcfe in the same period in 2002 primarily as a result of the natural production decline of existing wells, the addition of the Delta Farms #2 (a relatively higher operating cost well) and higher severance taxes.

Depreciation, depletion and amortization (DD&A) expense for the three months ended September 30, 2003 increased to $3.1 million from $2.7 million for the same period in 2002. DD&A increased primarily due to increased production and expenses resulting from additional seismic and drilling costs. General and administrative expense for the three months ended September 30, 2003 increased 64% to $1.6 million from $1.0 million for the same period in 2002 primarily as a result of employee severance costs and the addition of contract staff to handle increased drilling and production activities, higher compensation costs and higher insurance costs.

Interest income for the three months ended September 30, 2003 decreased to $13,095 from $16,345 in the third quarter of 2002 primarily as a result of higher cash balances during the third quarter of 2003. Capitalized interest in the third quarter of 2003 increased to $0.7 million from $0.6 million in the third quarter of 2002 as a result of higher interest costs on the senior subordinated notes.

Income taxes increased to $1.3 million for the three months ended September 30, 2003 from $0.7 million for the same period in 2002 as a result of higher taxable income based on the factors described above.

Income before income taxes for the three months ended September 30, 2003 increased to $3.3 million from $1.9 million in the same period in 2002. Net income for the three months ended September 30, 2003 increased to $1.9 million from $1.0 million for the same period in 2002 primarily as a result of the factors described above.

Nine Months Ended September 30, 2003,

Compared to the Nine Months Ended September 30, 2002

Oil and natural gas revenues for the nine months ended September 30, 2003 increased 69% to $29.6 million from $17.6 million for the same period in 2002. Production volumes for natural gas during the nine months ended September 30, 2003 decreased 3% to 3.4 Bcf from 3.5 Bcf for the same period in 2002. Average natural gas prices increased 72% to $5.56 per Mcf in the first nine months of 2003 from $3.24 per Mcf in the same period in 2002. Production volumes for oil in the first nine months of 2003 increased 39% to 363 MBbls from 261 MBbls for the same period in 2002. Average oil prices increased 25% to $29.08 per barrel in the first nine months of 2003 from $23.34 per barrel in the same period in 2002. The increase in oil production was due primarily to the commencement of production at the Burkhart #1R, Pauline Huebner A-382 #1, Matthes-Huebner #1, Hankamer #1, Beach House #1 and Espree #1 wells offset by the natural decline in production from other wells. The decrease in natural gas production was primarily

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due to a workover at the Delta Farms #1, the natural decline in production at the Staubach #1, Riverdale #2 and other wells offset by the commencement of production at the Burkhart #1R, Pauline Huebner A-382 #1, Hankamer #1, Beachhouse #1 and Espree #1 wells. Oil and natural gas revenues include the impact of hedging activities as discussed above under “General Overview”.

The following table summarizes production volumes, average sales prices and operating revenues for the Company’s oil and natural gas operations for the nine months ended September 30, 2002 and 2003:

	September 30,				2003 Period Compared to 2002 Period
	September 30,				Increase (Decrease)			% Increase (Decrease)
	2002		2003		Increase (Decrease)			% Increase (Decrease)
Production volumes -
Oil and condensate (MBbls)		261		363		102		39	%
Natural gas (MMcf)		3,543		3,432		(111	)	(3	)%
Average sales prices - (2)
Oil and condensate (per Bbls)	$	23.34	$	29.08	$	5.74		25	%
Natural gas (per Mcf)		3.24		5.56		2.32		72	%
Operating revenues (In thousands)-
Oil and condensate	$	6,092	$	10,544	$	4,452		73	%
Natural gas		11,468		19,071		7,603		66	%

Total	$	17,560	$	29,615	$	12,055		69	%

(2)	Includes impact of hedging activities.

Oil and natural gas operating expenses for the nine months ended September 30, 2003 increased 38% to $5.1 million from $3.7 million for the same period in 2002 primarily due to higher severance taxes and other operating costs associated with the addition of new production. Operating expenses per equivalent unit increased 25% to $0.90 per Mcfe in the first nine months of 2003 from $0.72 per Mcfe in the same period in 2002 primarily as a result of the natural decline in production on older wells and the addition of the Delta Farms #2, a relatively higher cost well.

Depreciation, depletion and amortization (DD&A) expense for the nine months ended September 30, 2003 increased 19% to $8.7 million from $7.3 million for the same period in 2002. This increase was due to increased production and additional seismic and drilling costs. General and administrative expense for the nine months ended September 30, 2003 increased 40% to $4.3 million from $3.0 million for the same period in 2002 primarily as a result of employee severance costs and the addition of contract staff to handle increased drilling and production activities, higher compensation costs and higher insurance.

Interest income for the nine months ended September 30, 2003 increased to $50,000 from $44,000 in the first nine months of 2002 primarily as a result of higher cash balances during the first quarter of 2003. Capitalized interest was $2.2 million in the first nine months of 2003 and 2002.

Income taxes increased to $4.1 million for the nine months ended September 30, 2003 from $1.5 million for the same period in 2002 as a result of higher taxable income based on the factors described above.

The Company adopted Financial Accounting Standards Board’s Statement of Financial Standards No. 143 “Accounting for Asset Retirement Obligations” effective January 1, 2003 and recorded a cumulative effect of change in accounting principle of $0.1 million in the nine months ended September 30, 2003.

Income before income taxes for the nine months ended September 30, 2003 increased to $11.1 million from $3.9 million in the same period in 2002. Net income for the nine months ended September 30, 2003 increased to $6.3 million from $2.0 million for the same period in 2002 primarily as a result of the factors described above.

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Liquidity and Capital Resources

The Company has made and expects to make oil and gas capital expenditures in excess of its net cash flows provided by operating activities in order to complete the exploration and development of its existing properties. The Company will require additional sources of financing to fund drilling expenditures on properties currently owned by the Company and to fund leasehold costs and geological and geophysical costs on its exploration projects.

While the Company believes that the current cash balances and anticipated 2003 cash provided by operating activities will provide sufficient capital to carry out the Company’s 2003 exploration plans, management of the Company continues to seek financing for its capital program from a variety of sources. No assurance can be given that the Company will be able to obtain additional financing on terms that would be acceptable to the Company. The Company’s inability to obtain additional financing could have a material adverse effect on the Company. If the Company cannot obtain acceptable financing, the Company anticipates that it may be required to limit or defer its planned oil and gas exploration and development program, which could adversely affect the recoverability and ultimate value of the Company’s oil and gas properties.

The Company’s primary sources of liquidity have included proceeds from the 1997 initial public offering, from the December 1999 sale of Subordinated Notes, Common Stock and Warrants, the 2002 sale of shares of Series B Convertible Participating Preferred Stock and Warrants, the 1998 sale of shares of Series A Preferred Stock and Warrants, funds generated by operations, equity capital contributions, borrowings (primarily under revolving credit facilities) and the Palace Agreement that provided a portion of the funding for the Company’s 1999, 2000, 2001 and 2002 drilling program in return for participation in certain wells.

Cash flows provided by operating activities were $12.3 million and $23.5 million for the nine months ended September 30, 2002 and 2003, respectively. The increase in cash flows provided by operating activities in 2003 as compared to 2002 was due primarily to additional revenue as a result of higher oil and natural gas prices and higher oil and condensate production offset by the increase of working capital during the first nine months of 2003.

The Company has budgeted capital expenditures for the year ended December 31, 2003 of approximately $25.9 million, of which $5.2 million is expected to be used to fund 3-D seismic surveys and land acquisitions and $20.7 million is expected to be used for drilling activities in the Company’s project areas. The Company has budgeted to drill up to approximately 35 gross wells (9.9 net) in the Gulf Coast region and no CCBM coalbed methane wells in 2003. The actual number of wells drilled and capital expended depends on available financing, cash flow, availability and cost of drilling rigs, land and partner issues and other factors.

The Company has continued to reinvest a substantial portion of its cash flows into increasing its 3-D prospect portfolio, improving its 3-D seismic interpretation technology and funding its drilling program. Oil and gas capital expenditures were $21.1 million for the nine months ended September 30, 2003, which included $2.2 million of capitalized interest and general and administrative costs. The Company’s drilling efforts in the Gulf Coast region resulted in the successful completion of 17 gross wells (6.0 net) during the year ended December 31, 2002 and 22 gross wells (5.7 net) during the nine months ended September 30, 2003. Of the 77 gross wells (29 net) drilled or acquired by CCBM through September 30, 2003, 24 gross wells (8 net) are currently producing and 53 gross wells (21 net) are awaiting evaluation before a determination can be made as to their success.

The Pinnacle Transaction

Overview

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Immediately following the contribution and funding, Pinnacle used approximately $6.2 million of the proceeds from the funding to acquire an approximate 50% working interest in existing leases and approximately 36,529 gross acres prospective for coalbed methane development in the Powder River Basin of Wyoming from Gastar Exploration, Ltd. The leases include 95 producing coalbed methane wells currently in the early stages of dewatering. At the time of the Pinnacle transaction, these wells were producing at a combined gross rate of approximately 2.5 MMcfd, or an estimated 1 MMcfd net to Pinnacle. Pinnacle also agreed to fund up to $14.9 million of future drilling and development costs on these properties on behalf of Gastar prior to December 31, 2005. The drilling and development work will be done under the terms of an earn-in joint venture agreement between Pinnacle and Gastar. The majority of these leases are part of, or adjacent to, the Bobcat project area. All of CCBM and RMG’s interests in the Bobcat project area, the only producing coalbed methane property owned by CCBM prior to the transaction, were contributed to Pinnacle. As of June 30, 2003, Pinnacle owned interests in approximately 131,000 gross acres in the Powder River Basin.

Accounting and Tax Treatment

If an entity is determined to be a “variable interest entity” (“VIE”), the entity must be consolidated by the “primary beneficiary”. The primary beneficiary is the holder of the variable interests that absorbs a majority of the variable interest entity’s expected losses or receives a majority of the entity’s residual returns in the event no holder has a majority of the expected losses. The determination of the primary beneficiary is based on projected cash flows at the inception of the variable interests. Because Steven A. Webster, Chairman of Carrizo, is also a managing director of Credit Suisse First Boston (see “Related Parties in the Pinnacle Transaction” below), Carrizo could be defined as the primary beneficiary if the projected cash flows analysis indicated losses in excess of the equity invested. The initial determination of whether an entity is a VIE is to be reconsidered only when one or more of the following occur (1) the entity’s governing documents or the contractual arrangements among the parties involved change, (2) the equity investment of some part thereof is returned to the investors, and other parties become exposed to expected losses or (3) the entity undertakes additional activities or acquires additional assets that increase the entity’s expected losses.

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Related Parties in the Pinnacle Transaction

Steven A. Webster, Chairman of the Board of the Company, is also a managing director of Credit Suisse First Boston Private Equity and is therefore a related party to this transaction.

Transition Services Agreement

Area of Mutual Interest Agreement

The Company, CCBM, RMG, RMG’s majority shareholder U.S. Energy Corp. (“U.S. Energy”) and the CSFB Parties also entered into an area of mutual interest agreement covering the Powder River Basin in Wyoming and Montana (but excluding most of Powder River County, Montana) providing that Pinnacle has the right until June 23, 2008 to acquire at cost from the Company, CCBM, RMG and U.S. Energy any interest in oil and gas leases or mineral interests that such parties may have acquired in the covered area, subject to specified exceptions.

Securityholders’ Agreement

The Company, the CSFB Parties, CCBM, RMG, U.S. Energy, Peter G. Schoonmaker and Gary W. Uhland (the “Securityholders”) and Pinnacle also entered into a Securityholders’ Agreement (the “Securityholders’ Agreement”).

The Securityholders’ Agreement provides for an initial eight person board of directors, which initially would include four directors nominated by the CSFB Parties and two nominated by each of CCBM and RMG, subject to change as their respective ownership percentages change.

In the Securityholders’ Agreement, the Securityholders grant to each other a right of first offer and co-sale rights.

If the CSFB Parties propose to sell all of their Pinnacle Shares to a third party, under certain circumstances the CSFB parties may require the other Securityholders to include all of their Pinnacle Shares in such sale. In such a sale, the Pinnacle Preferred Stock will have a preferred right to receive an amount equal to the Liquidation Value (as defined below) per share plus accrued and unpaid dividends prior to the holders of shares of Pinnacle Common Stock and common stock equivalents.

Under the Securityholders’ Agreement, Pinnacle grants the Securityholders pre-emptive rights to purchase certain securities in order to maintain their proportionate ownership of Pinnacle.

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The Securityholders’ Agreement also generally provides for multiple demand registration rights with respect to the Pinnacle Common Stock in favor of the CSFB Parties and certain piggyback registration rights for each of CCBM and RMG subject to the satisfaction of specified conditions.

Pinnacle Stock Options

The same number of Pinnacle Stock Options were issued to both CCBM and RMG in two tranches. CCBM and RMG each have a continuing option (the “Tranche A” option) to purchase up to 25,000 shares of common stock at a purchase price of $100 per share, with a price escalation of 10% per annum, compounded quarterly. In addition, CCBM and RMG each have another continuing option (the “Tranche B” option) to purchase up to 25,000 additional shares of common stock at a purchase price of $100 per share, with a price escalation of 20% per annum, compounded quarterly. The Tranche B option cannot be exercised until all 25,000 shares are first purchased under the Tranche A option.

Pinnacle Preferred Stock

The Pinnacle Preferred Stock generally has the right to vote together with the Pinnacle Common Stock and has a class vote on specified matters, including certain extraordinary transactions.

In the event of any dissolution, liquidation, or winding up by Pinnacle, the holder of each share of Pinnacle Preferred Stock will be entitled to be paid $100 per share out of the assets of Pinnacle available for distribution to its shareholders (the “Liquidation Value”).

Dividends on the Pinnacle Preferred Stock will be payable either in cash at a rate of 10.5% per annum through June 23, 2011 and then 12.5% thereafter or, at Pinnacle’s option, by payment in kind of additional shares of the Pinnacle Preferred Stock. For each additional share of Pinnacle Preferred Stock distributed to a holder as an in-kind dividend, Pinnacle will also deliver to such holder one Pinnacle Warrant, which will have an exercise price equal to the exercise price of the outstanding Pinnacle Warrants on the date of such distribution.

On or after July 1, 2005, Pinnacle may redeem all or any portion of the Pinnacle Preferred Stock (provided, that if any Pinnacle Warrants are still outstanding, Pinnacle may redeem all but a single share) at a premium to the Liquidation Value if redeemed on or at any time after July 1, 2009.

The Pinnacle Preferred Stock is required to be redeemed by Pinnacle upon (1) specified changes of control or (2) specified events of default at a price per share, with respect to a redemption pursuant to clause (1) above, equal to 101% of the Liquidation Value and, with respect to a redemption pursuant to clause (2) above, prior to June 30, 2005, equal to 110% of the Liquidation Value and, thereafter, equal to an optional redemption price that decreases over time.

Pinnacle Warrants

The Pinnacle Warrants entitle the holders to purchase up to 130,000 shares of Pinnacle Common Stock at a price of $100 per share and are exercisable at any time until June 30, 2013. The Pinnacle Warrants can be exercised in cash, by tender of the Pinnacle Preferred Stock and on a cashless net exercise basis. The Pinnacle Warrants are subject to certain adjustments, including, in certain cases, an adjustment of the exercise price to equal the lowest price at which Pinnacle Common Stock is sold if such shares are sold below the then-current exercise price.

Financing Arrangements

On May 24, 2002, the Company entered into a credit agreement with Hibernia National Bank (the “Hibernia Facility”) that matures on January 31, 2005, and repaid its prior facility with Compass Bank (the “Compass Facility”). The Hibernia Facility provides a revolving line of credit of up to $30.0 million. It is secured by substantially all of the Company’s producing oil and gas properties and is guaranteed by the Company’s wholly owned subsidiary CCBM, Inc. (“CCBM”).

The borrowing base will be determined by Hibernia National Bank at least semi-annually on October 31 and April 30. The initial borrowing base was $12.0 million, and the borrowing base as of September 30, 2003 was $13.5 million. Each party to the credit agreement can request one unscheduled borrowing base determination subsequent to each scheduled determination. The borrowing base will at all times equal the borrowing base most recently determined by Hibernia National Bank, less quarterly borrowing base reductions required subsequent to such determination. Hibernia National Bank will reset the borrowing base amount at each

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scheduled and each unscheduled borrowing base determination date. The initial quarterly borrowing base reduction, which commenced on June 30, 2002, was $1.3 million. The quarterly borrowing base reduction effective January 31, 2003 was $1.8 million. There was a decrease in the borrowing base for the quarter ended September 30, 2003 of $2.5 million.

If the principal balance of the Hibernia Facility ever exceeds any re-determined borrowing base, the Company has the option within thirty days to take any of the following actions either individually or in combination: (i) make a lump sum payment curing the deficiency; (ii) pledge additional collateral sufficient in Hibernia National Bank’s opinion to increase the borrowing base and cure the deficiency; or (iii) begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Such payments are in addition to any payments that may come due as a result of the quarterly borrowing base reductions.

For each tranche of principal borrowed under the revolving line of credit, the interest rate will be, at the Company’s option: (i) the Eurodollar Rate, plus an applicable margin equal to: 2.375% if the amount borrowed is greater than or equal to 90% of the borrowing base, 2.0% if the amount borrowed is less than 90% but greater than or equal to 50% of the borrowing base, or 1.625% if the amount borrowed is less than 50% of the borrowing base; or (ii) the Base Rate, plus an applicable margin of 0.375% if the amount borrowed is greater than or equal to 90% of the borrowing base. Interest on Eurodollar Loans is payable on either the last day of each Eurodollar option period or monthly, whichever is earlier. Interest on Base Rate Loans is payable monthly.

The Company is subject to certain covenants under the terms of the Hibernia Facility, including but not limited to the maintenance of the following financial covenants: (i) a minimum current ratio of 1.0 to 1.0 (including availability under the borrowing base), (ii) a minimum quarterly debt services coverage of 1.25 times, and (iii) a minimum shareholders equity equal to $56.0 million,plus100% of all subsequent common and preferred equity contributed by shareholders,plus50% of all positive earning occurring subsequent to such quarter end, all ratios as more particularly discussed in the credit facility.The Hibernia Facility also places restrictions on additional indebtedness, dividends to non-preferred stockholders, liens, investments, mergers, acquisitions, asset dispositions, asset pledges and mortgages, change of control, repurchase or redemption for cash of the Company’s common or preferred stock, speculative commodity transactions, and other matters.

On June 29, 2001, CCBM issued a non-recourse promissory note payable in the amount of $7.5 million to RMG as consideration for certain interests in oil and natural gas leases held by RMG in Wyoming and Montana. The RMG note was payable in 41-monthly principal payments of $0.1 million plus interest at 8% per annum commencing July 31, 2001 with the balance due December 31, 2004. The RMG note is secured solely by CCBM’s interests in the oil and natural gas leases in Wyoming and Montana. At December 31, 2002 and September 30, 2003, the outstanding principal balance of this note was $5.3 million and $1.0 million, respectively. In connection with the Company’s investment in Pinnacle, the Company received a reduction in the principal amount of the RMG note of approximately $1.5 million and relinquished the right to receive certain revenues related to the properties contributed to Pinnacle.

In December 2001, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $0.2 million. The lease is payable in one payment of $11,323 and 35 monthly payments of $7,549 including interest at 8.6% per annum. In October 2002, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $3,462 including interest at 6.4% per annum. In May 2003, the Company entered into a capital lease agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $3,030 including interest at 5.5% per annum. In August 2003, the Company entered into a capital lease

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agreement secured by certain production equipment in the amount of $0.1 million. The lease is payable in 36 monthly payments of $2,179 including interest at 6.0% per annum. Under all of these leases the Company has the option to acquire the equipment at the conclusion of the lease for $1. DD&A on the capital leases for the three months ended September 30, 2002 and 2003 amounted to $6,000 and $14,000, respectively. DD&A on the capital leases for the nine months ended September 30, 2002 and 2003 amounted to $18,000 and $35,000 respectively, and accumulated DD&A on the leased equipment at December 31, 2002 and September 30, 2003 amounted to $28,000 and $62,000, respectively.

In December 1999, the Company consummated the sale of $22.0 million principal amount of 9% Senior Subordinated Notes due 2007 (the “Subordinated Notes”) and $8.0 million of common stock and Warrants. The Company sold $17.6 million, $2.2 million, $0.8 million, $0.8 million and $0.8 million principal amount of Subordinated Notes; 2,909,092, 363,636, 121,212, 121,212 and 121,212 shares of the Company’s common stock and 2,208,152, 276,019, 92,006, 92,006 and 92,006 Warrants to CB Capital Investors, L.P. (now known as JPMorgan Partners, LLC), Mellon Ventures, L.P., Paul B. Loyd, Jr., Steven A. Webster and Douglas A.P. Hamilton, respectively. The Subordinated Notes were sold at a discount of $0.7 million, which is being amortized over the life of the notes. Interest payments are due quarterly commencing on March 31, 2000. The Company may elect, until December 2004, to increase the amount of the Subordinated Notes for 60% of the interest which would otherwise be payable in cash. As of December 31, 2002 and September 30, 2003, the outstanding balance of the Subordinated Notes had been increased by $3.9 million and $5.7 million, respectively, for such interest paid in kind.

The Company is subject to certain covenants under the terms of the Subordinated Notes securities purchase agreement, including but not limited to: (a) maintenance of a specified tangible net worth, (b) maintenance of a ratio of EBITDA (earnings before interest, taxes, depreciation and amortization) to quarterly Debt Service (as defined in the agreement) of not less than 1.00 to 1.00, and (c) a limitation of its capital expenditures to an amount equal to the Company’s EBITDA for the immediately prior fiscal year (unless approved by the Company’s Board of Directors and a JPMorgan Partners, LLC appointed director), as well as limits on the Company’s ability to (i) incur indebtedness, (ii) incur or allow liens, (iii) engage in mergers, consolidation, sales of assets and acquisitions, (iv) declare dividends and effect certain distributions (including restrictions on distributions upon the Common Stock), (v) engage in transactions with affiliates and (vi) make certain repayments and prepayments, including any prepayment of the subordinated debt, indebtedness that is guaranteed or credit-enhanced by any affiliate of the Company, and prepayments that effect certain permanent reductions in revolving credit facilities. EBITDA was part of a negotiated covenant with the purchasers and is presented here as a disclosure of our covenant obligations.

In February 2002, the Company consummated the sale of 60,000 shares of Series B Preferred Stock and 2002 Warrants to purchase 252,632 shares of Common Stock for an aggregate purchase price of $6.0 million. The Company sold $4.0 million and $2.0 million of Series B Preferred Stock and 168,422 and 84,210 Warrants to Mellon Ventures, Inc. and Steven A. Webster, respectively. The Series B Preferred Stock is convertible into Common Stock by the investors at a conversion price of $5.70 per share, subject to adjustment, and is initially convertible into 1,052,632 shares of Common Stock. The approximately $5.8 million net proceeds of this financing were used to fund the Company’s ongoing exploration and development program and for general corporate purposes.

Dividends on the Series B Preferred Stock will be payable in either cash at a rate of 8% per annum or, at the Company’s option, by payment in kind of additional shares of the Series B Preferred Stock at a rate of 10% per annum. At December 31, 2002 and June 30, 2003 the outstanding balance of the Series B Preferred Stock had been increased by $0.5 million (5,294 shares) and $0.9 million (8,559 shares), respectively, for dividends paid in kind. At September 30, 2003, the Company has accrued a dividend of $0.2 million (1,714 shares) that is payable on December 31, 2003. In addition to the foregoing, if the Company declares a cash dividend on the Common Stock of the Company, the holders of shares of Series B Preferred Stock are entitled to receive for each share of Series B Preferred Stock a cash dividend in the amount of the cash dividend that would be received by a holder of the Common Stock into which such share of Series B Preferred Stock is convertible on the record date for such cash dividend. Unless all accrued dividends on the Series B Preferred Stock shall have been paid and a sum sufficient for the payment thereof set apart, no distributions may be paid on any Junior Stock (which includes the Common Stock) (as defined in the Statement of Resolutions for the Series B Preferred Stock) and no redemption of any Junior Stock shall occur other than subject to certain exceptions.

The Series B Preferred Stock is required to be redeemed by the Company at any time after the third anniversary of its initial issuance upon request from any holder at a price per share equal to Purchase Price/Dividend Preference (as defined below). The Company may redeem the Series B Preferred Stock after the third anniversary of its issuance, at a price per share equal to the Purchase Price/Dividend Preference and, prior to that time, at varying preferences to the Purchase Price/Dividend Purchase. “Purchase Price/Dividend Preference” is defined to mean, generally, $100 plus all cumulative and accrued dividends.

In the event of any dissolution, liquidation or winding up or certain mergers or sales or other disposition by the Company of all or substantially all of its assets, the holder of each share of Series B Preferred Stock then outstanding will be entitled to be paid out of the

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assets of the Company available for distribution to its shareholders, the greater of: (i) $100 in cash plus all cumulative and accrued dividends and (ii) in certain circumstances, the “as-converted” liquidation distribution, if any, payable in such Liquidation with respect to each share of Common Stock.

Upon the occurrence of certain events constituting a “Change of Control” (as defined in the Statement of Resolutions), the Company is required to make an offer to each holder of Series B Preferred Stock to repurchase all of such holder’s Series B Preferred Stock at an offer price per share of Series B Preferred Stock in cash equal to 105% of the Change of Control Purchase Price, which is generally defined to mean $100 plus all cumulative and accrued dividends.

The 2002 Warrants have a five-year term and entitle the holders to purchase up to 252,632 shares of Carrizo’s Common Stock at a price of $5.94 per share, subject to adjustment, and are exercisable at any time after issuance. For accounting purposes, the 2002 Warrants were recorded at a value of $0.06 per 2002 Warrant.

Effects of Inflation and Changes in Price

The Company’s results of operations and cash flows are affected by changing oil and gas prices. If the price of oil and gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that the Company is required to bear for operations, as well as an increase (decrease) in revenues. Inflation has had a minimal effect on the Company.

Critical Accounting Policies

The following summarizes several of our critical accounting policies:

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from these estimates.

Oil and Natural Gas Properties

Investments in oil and natural gas properties are accounted for using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. These costs include lease acquisitions, seismic surveys, and drilling and completion equipment. The Company proportionally consolidates its interests in oil and natural gas properties. The Company capitalized compensation costs for employees working directly on exploration activities of $0.7 million and $1.1 million for the nine months ended September 30, 2002 and 2003, respectively. The Company expenses maintenance and repairs as they are incurred.

The Company authorizes oil and natural gas properties based on the unit-of-production method using estimates of proved reserve quantities. The Company does not amortize investments in unproved properties until proved reserves associated with the projects can be determined or until they are impaired. The Company evaluates unevaluated properties periodically for impairment on a property-by-property basis. If the results of an assessment indicate that the properties are impaired, the Company adds the amount of impairment to the proved oil and natural gas property costs to be amortized. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per thousand cubic feet equivalent (Mcfe) for the nine months ended September 30, 2002 and 2003 was $1.44 and $1.56, respectively.

The Company accounts for dispositions of oil and natural gas properties as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves.

The net capitalized costs of proved oil and natural gas properties are subject to a “ceiling test”, which limits such costs to the estimated present value, discounted at a 10% interest rate, of future net revenues from proved reserves (the “NPV”), based on current economic and operating conditions. The Company includes Asset Retirement Obligation costs, liabilities and related discounted cash flows in its ceiling test calculations. If net capitalized costs exceed this limit, the excess is charged to operations through depreciation, depletion and amortization. No write-down of the Company’s oil and natural gas assets was necessary for the nine months ended September 30, 2002 or 2003. In concert with this determination, a price sensitivity study also indicated that a 20 percent increase in commodity prices at September 30, 2003 would have increased the Company’s NPV by approximately $15.8 million. Conversely, a 20 percent decrease in commodity prices at September 30, 2003 would have reduced the Company’s NPV by approximately $18.4 million. This would have caused the Company’s unamortized cost of proved oil and gas properties to exceed the cost pool ceiling by approximately $18.1 million. The company’s afore mentioned price sensitivity and NPV is as of September 30, 2003 and, accordingly, does not include any potential changes in reserves due to fourth quarter, performance, such as commodity prices, reserve revisions and drilling results, including two potential high impact wells that are currently drilling. Based on oil and natural gas prices in effect on December 31, 2001, the unamortized cost of oil and natural gas

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properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in pricing subsequent to December 31, 2001 removed the necessity to record a write-down. Using prices in effect on December 31, 2001 the pretax write-down would have been approximately $0.7 million. Because of the volatility of oil and natural gas prices, no assurance can be given that the Company will not experience a write-down in future periods.

The Company depreciates other property and equipment using the straight-line method based on estimated useful lives ranging from five to 10 years.

Oil and Natural Gas Reserve Estimates

The process of estimating quantities of proved reserves is inherently uncertain, and the reserve data included in this document are estimates prepared by the Company. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact manner. The process relies on interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires certain economic assumptions regarding drilling and operating expense, capital expenditures, taxes and availability of funds. The SEC mandates some of these assumptions such as oil and natural gas prices and the present value discount rate.

Proved reserve estimates prepared by others may be substantially higher or lower than the Company’s estimates. Because these estimates depend on many assumptions, all of which may differ from actual results, reserve quantities actually recovered may be significantly different than estimated. Material revisions to reserve estimates may be made depending on the results of drilling, testing, and rates of production.

It should not be assumed that the present value of future net cash flows is the current market value of the Company’s estimated proved reserves. In accordance with SEC requirements, the Company based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate.

The Company’s rate of recording depreciation, depletion and amortization expense for proved properties is dependent on the Company’s estimate of proved reserves. If these reserve estimates change, the rate at which the Company records these expenses will change.

Derivative Instruments and Hedging Activities

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 133 “Accounting for Derivative Instruments and Hedging Activities”. This statement, as amended by SFAS No. 137 and SFAS No. 138, establishes standards of accounting for and disclosures of derivative instruments and hedging activities. This statement requires all derivative instruments to be carried on the balance sheet at fair value with changes in a derivative instrument’s fair value recognized currently in earnings unless specific hedge accounting criteria are met. SFAS No. 133 was effective for the Company beginning January 1, 2001 and was adopted by the Company on that date. In accordance with the current transition provisions of SFAS No. 133, the Company recorded a cumulative effect transition adjustment of $2.0 million (net of related tax expense of $1.1 million) in accumulated other comprehensive income to recognize the fair value of its derivatives designated as cash flow hedging instruments at the date of adoption.

Upon entering into a derivative contract, the Company designates the derivative instruments as a hedge of the variability of cash flow to be received (cash flow hedge). Changes in the fair value of a cash flow hedge are recorded in other comprehensive income to the extent that the derivative is effective in offsetting changes in the fair value of the hedged item. Any ineffectiveness in the relationship

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between the cash flow hedge and the hedged item is recognized currently in income. Gains and losses accumulated in other comprehensive income associated with the cash flow hedge are recognized in earnings as oil and natural gas revenues when the forecasted transaction occurs. All of the Company’s derivative instruments at December 31, 2002 and September 30, 2003 were designated and effective as cash flow hedges except certain options described below under “Volatility of Oil and Natural Gas Prices”.

When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at fair value on the balance sheet with future changes in its fair value recognized in future earnings.

The Company typically uses fixed rate swaps and costless collars to hedge its exposure to material changes in the price of natural gas and oil. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objectives and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated cash flow hedges to forecasted transactions. The Company also formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions.

The Company’s Board of Directors sets all of the Company’s hedging policy, including volumes, types of instruments and counterparties, on a quarterly basis. These policies are implemented by management through the execution of trades by either the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with the authorized counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. The Board of Directors also reviews the status and results of hedging activities quarterly.

Income Taxes

Under Statement of Financial Accounting Standards No. 109 (“SFAS No. 109”), “Accounting for Income Taxes”, deferred income taxes are recognized at each year end for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. Valuation allowances are established when necessary to reduce the deferred tax asset to the amount expected to be realized.

Contingencies

Liabilities and other contingencies are recognized upon determination of an exposure, which when analyzed indicates that it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.

Volatility of Oil and Natural Gas Prices

The Company’s revenues, future rate of growth, results of operations, financial condition and ability to borrow funds or obtain additional capital, as well as the carrying value of its properties, are substantially dependent upon prevailing prices of oil and natural gas. Historically, the markets for oil and natural gas have been volatile, and such markets are likely to continue to be volatile in the future. Prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the control of the Company. These factors include the level of consumer product demand, weather conditions, domestic and foreign governmental regulations, the price and availability of alternative fuels, political conditions in the Middle East, the foreign supply of oil and natural gas, the price of foreign imports and overall economic conditions. It is impossible to predict future oil and natural gas price movements with certainty. Declines in oil and natural gas prices may materially adversely affect the Company’s financial condition, liquidity, and ability to finance planned capital expenditures and results of operations. Lower oil and natural gas prices also may reduce the amount of oil and natural gas that the Company can produce economically. Oil and natural gas prices have declined in the recent past and there can be no assurance that prices will recover or will not decline further.

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Total oil purchased and sold under swaps and collars during the three months ended September 30, 2002 and 2003 was 33,600 Bbls and 24,400 Bbls, respectively. Total natural gas purchased and sold under swaps and collars during the three months ended September 30, 2002 and 2003 was 731,000 MMBtu and 828,000 MMBtu, respectively. Total oil purchased and sold under swaps and collars during the nine months ended September 30, 2002 and 2003 was 79,100 Bbls and 150,700 Bbls, respectively. Total natural gas purchased and sold under swaps and collars during the nine months ended September 30, 2002 and 2003 was 3,094,000 MMBtu and 2,187,000 MMBtu, respectively. The net losses realized by the Company under such hedging arrangements were $0.1 million and $0.1 million for the three months ended September 30, 2002 and 2003, respectively, and are included in oil and natural gas revenues. The net losses realized by the Company under such hedging arrangements were $0.4 million and $1.8 million for the nine months ended September 30, 2002 and 2003, respectively, and are included in oil and natural gas revenues.

At December 31, 2002 and September 30, 2003 the Company had the following outstanding hedge positions:

As of December 31, 2002
	Contract Volumes		Average Fixed Price		Average Floor Price		Average Ceiling Price
Quarter	BBls	MMbtu	Average Fixed Price		Average Floor Price		Average Ceiling Price
First Quarter 2003	27,000		$	24.85
First Quarter 2003	36,000				$	23.50	$	26.50
First Quarter 2003		540,000				3.40		5.25
Second Quarter 2003	27,300			24.85
Second Quarter 2003	36,000					23.50		26.50
Second Quarter 2003		546,000				3.40		5.25
Third Quarter 2003		552,000				3.40		5.25
Fourth Quarter 2003		552,000				3.40		5.25

As of September 30, 2003
	Contract Volumes		Average Fixed Price		Average Floor Price		Average Ceiling Price
Quarter	BBls	MMbtu	Average Fixed Price		Average Floor Price		Average Ceiling Price
Fourth Quarter 2003	30,700		$	30.22
Fourth Quarter 2003		552,000				3.40		5.25
First Quarter 2004		546,000				4.10		7.00
Second Quarter 2004		273,000				4.00		5.20
Third Quarter 2004		276,000				4.00		5.20
Fourth Quarter 2004		93,000				4.00		5.20

During October 2003, the Company entered into swap arrangements covering 30,200 Bbls of oil for November 2003 through February 2004 production with an average fixed price of $30.26.

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In addition to the hedge positions above, during the second quarter of 2003, the Company acquired options to sell 6,000 MMBtu of natural gas per day for the period July 2003 through August 2003 (552,000 MMBtu) at $8.00 per MMBtu for approximately $119,000. The Company acquired these options to protect its cash position against potential margin calls on certain natural gas derivatives due to large increases in the price of natural gas. These options were classified as derivatives. As of September 30, 2003, these options had expired and a charge of $28,000 and $119,000 has been included in other income and expense for the three and nine months ended September 30, 2003, respectively.

New Accounting Pronouncements

The FASB issued Interpretation 46, “Consolidation of Variable Interest Entities” (“FIN 46”), in January 2003. FIN 46 requires the consolidation of certain types of entities in which a company absorbs a majority of another entity’s expected losses, receives a majority of the other entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interests in the other entity. The Company has identified no transactions or related entities that required consolidation under this interpretation.

Forward Looking Statements

The statements contained in all parts of this document, including, but not limited to, those relating to the Company’s schedule, targets, estimates or results of future drilling, budgeted wells, increases in wells, budgeted and other future capital expenditures, use of offering proceeds, outcome and effects of litigation, expected production or reserves, increases in reserves, acreage working capital requirements, hedging activities, the ability of expected sources of liquidity to implement its business strategy, level of capital involved in the North Sea project area, the application of FIN 46 to Pinnacle, the effect of accounting pronouncements, and any other statements regarding future operations, financial results, business plans and cash needs and other statements that are not historical facts are forward looking statements. When used in this document, the words “anticipate”, “estimate”, “expect”, “may”, “project”, “believe” and similar expression are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to the Company’s dependence on its exploratory drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, the Company’s dependence on its key personnel, factors that affect the Company’s ability to manage its growth and achieve its business strategy, risks relating to, limited operating history, technological changes, significant capital requirements of the Company, the potential impact of government regulations in the United States and elsewhere, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, availability of equipment, weather and other factors detailed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2002 and other filings with the Securities and Exchange Commission. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated.

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ITEM 3A – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For information regarding our exposure to certain market risks, see “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2002 except for the Company’s hedging activity subsequent to December 31, 2002 as described above in “Volatility of Oil and Natural Gas Prices”. There have been no material changes to the disclosure regarding our exposure to certain market risks made in the Annual Report. For additional information regarding our long-term debt, see Note 4 of the Notes to Unaudited Consolidated Financial Statements in Item 1 of Part I of this Quarterly Report on Form 10-Q.

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ITEM 4 – CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, 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 of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2003 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There has been no change in our internal controls over financial reporting that occurred during the three months ended September 30, 2003 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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PART II. OTHER INFORMATION

Item 1 - Legal Proceedings

Item 2 - Changes in Securities and Use of Proceeds

Pursuant to an exchange election provided in a letter agreement, dated May 1, 2001, with certain participants in the Carrizo 2001 Seismic and Acreage Program (the “2001 Program”), the Company issued to those participants who exercised their election approximately 168,000 shares of its common stock in exchange for the participants’ entire interest in the 2001 Program, including approximately 350 square miles of 3-D seismic data and working interests in certain producing properties. The exchange transaction was effective on October 10, 2003 and was valued at approximately $1.2 million using the closing price of the Company’s common stock on that date. Such transaction was exempt from the registration requirements of the Securities Act of 1933, as amended, by virtue of Section 4(2) thereof as a transaction not involving any public offering.

Item 3 - Defaults Upon Senior Securities

None.

Item 4 - Submission of Matters to a Vote of Security Holders

None.

Item 5 - Other Information

None.

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Item 6 - Exhibits and Reports on Form 8-K

Exhibits

Exhibit Number		Description

†2.1	—	Combination Agreement by and among the Company, Carrizo Production, Inc., Encinitas Partners Ltd., La Rosa Partners Ltd., Carrizo Partners Ltd., Paul B. Loyd, Jr., Steven A. Webster, S.P. Johnson IV, Douglas A.P. Hamilton and Frank A. Wojtek dated as of September 6, 1997 (incorporated herein by reference to Exhibit 2.1 to the Company’s Registration Statement on Form S-1 (Registration No. 333-29187)).

†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	—	Amended and Restated Bylaws of the Company, as amended by Amendment No. 1 (incorporated herein by reference to Exhibit 3.2 to the Company’s Registration Statement on Form 8-A (Registration No. 000-22915) Amendment No. 2 (incorporated herein by reference to Exhibit 3.2 to the Company’s Current Report on Form 8-K dated December 15, 1999) and Amendment No. 3 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K dated February 20, 2002).

†3.3	—	Statement of Resolution dated February 20, 2002 establishing the Series B Convertible Participating Preferred Stock providing for the designations, preferences, limitations and relative rights, voting, redemption and other rights thereof (incorporated herein by reference to Exhibit 99.2 to the Company’s Current Report on Form 8-K dated February 20, 2002).

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.

†	Incorporated herein by reference as indicated.

Reports on Form 8-K

The Company filed a Current Report on Form 8-K on August 6, 2003 (information furnished not filed) and a Current Report on Form 8-K on August 21, 2003 (information furnished not filed).

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Carrizo Oil & Gas, Inc.
	(Registrant)

Date: November 7, 2003	By:	/s/S. P. Johnson, IV
		President and Chief Executive Officer (Principal Executive Officer)

Date: November 7, 2003	By:	/s/Paul F. Boling
		Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

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Positive
Negative
Uncertain
Constraining
Legalese
Litigious
Readability	H.S. junior Avg

Carrizo Oil & Gas (CRZO) Inactive 10-Q2003 Q3 Quarterly report

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