10-Q

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 September30, 2005

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

For the transition period from ________ to _________

Commission File Number 000-29187-87

CARRIZO OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

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

1000 Louisiana Street, Suite 1500, Houston, TX	77002
(Address of principal executive offices)	(Zip Code)

(713) 328-1000

(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 [X] NO [ ]

Indicate by check mark whether the registrant is a shell company (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 October 28, 2005, the latest practicable date, was 24,243,920.

CARRIZO OIL & GAS, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER30, 2005

INDEX

PART I. FINANCIAL INFORMATION			PAGE
	Item 1.	Consolidated Balance Sheets (Unaudited)
		As of December 31, 2004 and September 30, 2005	2
		Consolidated Statements of Income (Unaudited)
		For the three and nine-month periods ended September 30, 2004 and 2005	3
		Consolidated Statements of Cash Flows (Unaudited)
		For the nine-month periods ended September 30, 2004 and 2005	4
		Notes to Consolidated Financial Statements	5
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	20
	Item 3.	Quantitative and Qualitative Disclosure About
		Market Risk	39
	Item 4.	Controls and Procedures	40
PART II. OTHER INFORMATION
	Items 1-6.		42
SIGNATURES			44

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	December 31,		September 30,
ASSETS	2004		2005
	(In thousands)
	Except Share Amounts
CURRENT ASSETS:
Cash and cash equivalents	$	5,668	$	50,037
Accounts receivable, trade (net of allowance for doubtful accounts of
$325 at December 31, 2004 and September 30, 2005)		12,738		20,160
Advances to operators		1,614		521
Other current assets		1,614		6,376
Total current assets		21,634		77,094
PROPERTY AND EQUIPMENT, net full-cost method of accounting for oil
and natural gas properties (including unevaluated costs of properties of $45,067 and
$68,169 at December 31, 2004 and September 30, 2005, respectively)		205,482		278,146
INVESTMENT IN PINNACLE GAS RESOURCES, INC.		5,229		4,241
DEFERRED FINANCING COSTS		1,633		6,071
OTHER ASSETS		57		148
	$	234,035	$	365,700
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade	$	21,358	$	13,270
Accrued liabilities		7,516		20,870
Advances for joint operations		1,808		5,785
Fair value of derivative financial instruments		-		6,033
Current maturities of long-term debt		90		1,555
Total current liabilities		30,772		47,513
LONG-TERM DEBT, NET OF CURRENT MATURITIES		62,884		147,868
ASSET RETIREMENT OBLIGATION		1,407		1,937
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS		-		1,670
DEFERRED INCOME TAXES		18,113		20,514
COMMITMENTS AND CONTINGENCIES		-		-
SHAREHOLDERS' EQUITY:
Warrants (334,210 and none outstanding at December 31,
2004 and September 30, 2005, respectively)		80		-
Common stock, par value $0.01 (40,000,000 shares authorized with 22,161,457 and
24,222,115 issued and outstanding at December 31, 2004 and
September 30, 2005, respectively)		221		242
Additional paid-in capital		99,766		124,301
Retained earnings		20,733		27,490
Unearned compensation - Restricted stock		-		(1,003	)
Accumulated other comprehensive income (loss)		59		(4,832	)
		120,859		146,198
	$	234,035	$	365,700

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	For the Three						For the Nine
	Months Ended						Months Ended
	September 30,						September 30,
	2004			2005			2004			2005
	(In thousands except per share amounts)
OIL AND NATURAL GAS REVENUES	$	12,274		$	17,574		$	35,107		$	49,353
COSTS AND EXPENSES:
Oil and natural gas operating expenses
(exclusive of depreciation shown separately below)		2,126			2,240			5,849			7,069
Depreciation, depletion and amortization		3,709			4,701			10,562			14,390
General and administrative		1,296			1,923			5,075			6,232
Accretion expense related to asset retirement obligations		8			18			21			54
Stock based compensation		(139	)		1,915			617			2,945
Total costs and expenses		7,000			10,797			22,124			30,690
OPERATING INCOME		5,274			6,777			12,983			18,663
OTHER INCOME AND EXPENSES:
Loss on extinguishment of debt		-			(3,721	)		-			(3,721	)
Equity in loss of Pinnacle Gas Resources, Inc.		(252	)		(411	)		(853	)		(988	)
Other income and expenses		521			(73	)		538			(292	)
Interest income		22			445			45			520
Interest expense		(865	)		(3,475	)		(1,195	)		(6,845	)
Interest expense, related parties		-			-			(1,079	)		-
Capitalized interest		769			1,671			2,092			3,896
INCOME BEFORE INCOME TAXES		5,469			1,213			12,531			11,233
INCOME TAXES (Note 4)		(2,079	)		(634	)		(4,820	)		(4,475	)
NET INCOME		3,390			579			7,711			6,758
DIVIDENDS AND ACCRETION ON PREFERRED STOCK		-			-			350			-
NET INCOME AVAILABLE TO COMMON SHAREHOLDERS	$	3,390		$	579		$	7,361		$	6,758
BASIC EARNINGS PER COMMON SHARE	$	0.15		$	0.02		$	0.38		$	0.29
DILUTED EARNINGS PER COMMON SHARE	$	0.15		$	0.02		$	0.34		$	0.28
WEIGHTED AVERAGE SHARES OUTSTANDING:
BASIC		21,909,855			24,198,152			19,255,156			23,302,734
DILUTED		23,004,082			25,003,002			21,546,329			24,123,244

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,
	2004			2005
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	7,711		$	6,758
Adjustment to reconcile net income to net
cash provided by operating activities-
Depreciation, depletion and amortization		10,562			14,390
Accretion of discounts on asset retirement obligations and debt		213			340
Loss on extinguishment of debt		-			3,365
Stock based compensation		617			2,945
Equity in loss of Pinnacle Gas Resources, Inc.		853			988
Deferred income taxes		4,652			4,278
Other		-			511
Changes in assets and liabilities-
Accounts receivable		(2,275	)		(7,422	)
Other assets		(1,925	)		(2,846	)
Accounts payable		(889	)		(6,677	)
Other liabilities		(88	)		2,189
Net cash provided by operating activities		19,431			18,819
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(58,954	)		(92,273	)
Change in capital expenditure accrual		5,688			7,502
Proceeds from the sale of properties		-			9,000
Advances to operators		424			1,087
Advances for joint operations		(1,440	)		3,977
Net cash used in investing activities		(54,282	)		(70,707	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from the sale of common stock:
Secondary offering, net of offering costs		23,421			-
Private placement, net of offering costs		-			17,169
Warrants exercised		-			1,000
Stock options exercised and other		1,027			1,302
Advances under the Borrowing Base Facility		19,000			30,024
Net proceeds from debt issuance		-			153,600
Debt repayments		(7,504	)		(100,624	)
Deferred loan costs		(873	)		(6,214	)
Net cash provided by financing activities		35,071			96,257
NET INCREASE IN CASH AND CASH EQUIVALENTS		220			44,369
CASH AND CASH EQUIVALENTS, beginning of period		3,322			5,668
CASH AND CASH EQUIVALENTS, end of period	$	3,542		$	50,037
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest (net of amounts capitalized)	$	182		$	-
Cash paid for income taxes	$	-		$	-

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.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

The consolidated financial statements included herein have been prepared by Carrizo Oil & Gas, Inc. (the “Company”), and are unaudited. 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 U.S. 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, 2004.

Reclassifications

Certain reclassifications have been made to prior period’s financial statements to conform to the current presentation.

Critical Accounting Policies and Use of Estimates

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

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of undeveloped properties, future income taxes and related assets/liabilities, bad debts, derivatives, contingencies and litigation. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

The significant estimates are based on current assumptions that may be materially effected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the market value of the Company’s common stock and corresponding volatility and the Company’s ability to generate future taxable income. Future changes to these assumptions may affect these significant estimates materially in the near term.

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. Such 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 $1.3 million and $1.6 million for the nine months ended September 30, 2004 and 2005, respectively. Maintenance and repairs are expensed as incurred.

Oil and natural gas properties are amortized based on the unit-of-production method using estimates of proved reserve quantities. Investments in unproved properties are not amortized until proved reserves associated with the projects can be determined or until they are impaired. Unevaluated properties are evaluated periodically for impairment on a property-by-property basis. If the results of an assessment indicate that the properties are impaired, the amount of impairment is added to the proved oil and natural gas property

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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 Mcfe for the nine months ended September 30, 2004 and 2005 was $1.79 and $2.09, respectively.

Dispositions of oil and natural gas properties are accounted for 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.

Effective February 1, 2005, the Company sold to a private company its interest in the Patterson Prospect Area in St. Mary Parish, Louisiana, including the Shadyside #1 well and any anticipated follow-up wells, for approximately $9.0 million. The Company’s average daily production from the Shadyside #1 during the fourth quarter 2004 was approximately 970 Mcfe per day. Proceeds from the sale were used in the 2005 Barnett Shale and Gulf Coast drilling program and for general corporate purposes.

In April 2005, the Company acquired assets in the Barnett Shale for approximately $4.1 million. This acquisition consisted of approximately 600 net acres and working interests in 14 existing gross wells (7.3 net) with an estimated 5.4 Bcfe of proved reserves, based upon the Company’s internal estimates. All of the interests in the wells acquired related to wells in which the Company already had an interest. The consideration paid for this acquisition was approximately $2.3 million in cash and 112,697 shares of the Company’s Common Stock.

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, based on current economic and operating conditions. If net capitalized costs exceed this limit, the excess is charged to operations through depreciation, depletion and amortization. During the year-end close of 2003, a computational error was identified in the ceiling test calculation which overstated the tax basis used in the computation to derive the after-tax present value (discounted at 10%) of future net revenues from proved reserves. This tax basis error was also present in each of the previous ceiling test computations dating back to 1997. This error only affected the after-tax computation, used in the ceiling test calculation and the unaudited supplemental oil and natural gas disclosure and did not impact: (1) the pre-tax valuation of the present value (discounted at 10%) of future net revenues from proved reserves, (2) the proved reserve volumes, (3) the Company’s EBITDA or future cash flows from operations, (4) the net deferred tax liability, (5) the estimated tax basis in oil and natural gas properties, or (6) the estimated tax net operating losses.

After discovering this computational error, the ceiling tests for all quarters since 1997 were recomputed and it was determined that no write-down of oil and natural gas assets was necessary in any of the years from 1997 to 2003. However, based upon the oil and natural gas prices in effect on March 31, 2003 and September 30, 2003, the unamortized cost of oil and natural gas properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in pricing and/or the addition of proved reserves subsequent to those dates sufficiently increased the present value of the oil and natural gas assets and removed the necessity to record a write-down in these periods. Using the prices in effect and estimated proved reserves on March 31, 2003 and September 30, 2003, the after-tax write-down would have been approximately $1.0 million and $6.3 million, respectively, had we not taken into account the subsequent improvements. These improvements at September 30, 2003 included estimated proved reserves attributable to the Company’s Shadyside # 1 well (which the Company subsequently sold in February 2005). Because of the volatility of oil and natural gas prices, no assurance can be given that we will not experience a write-down in future periods.

Depreciation of other property and equipment is provided using the straight-line method based on estimated useful lives ranging from five to 10 years.

Loss on Early Extinguishment of Long-Term Debt

On July 21, 2005, the Company entered into the Second Lien Credit Facility (see Note 2) and used a portion of the net proceeds from that facility to redeem the balances outstanding under the Senior Subordinated Notes ($29.6 million), and the Senior Subordinated Secured Notes ($22.5 million). In connection with the repayment of this indebtedness, the Company recorded a $3.7 million loss on early extinguishment of debt in our 2005 third quarter primarily attributable to the write-off of deferred loan costs and unamortized debt discount which totaled $3.4 million of the total loss incurred.

Supplemental Cash Flow Information

The Statement of Cash Flows for the nine months ended September 30, 2004 does not include interest paid-in-kind of $1.1 million, the net exercise of $0.7 million of warrants, the conversion of $7.5 million of preferred stock into common stock and the $0.3 million relinquishment of interests in certain leases to RMG in lieu of principal payments on a note payable. The Statement of Cash Flows for

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the nine months ended September 30, 2005 does not include interest paid-in-kind of $1.3 million, the net exercise of $80,000 of warrants and the acquisition of $2.0 million of oil and gas properties in exchange for the Company’s common stock.

Stock-Based Compensation

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 and earnings per share would have been as follows:

	For the three months ended
	September 30,
	2004			2005
	(In thousands except
	per share amounts)
Net income available to common
shareholders, as reported	$	3,390		$	579
Add (Deduct): Stock based employee compensation expense
recognized, net of tax		(90	)		1,157
Less: Total stock-based employee compensation
expense determined under fair value method for all
awards, net of related tax effects		(145	)		(402	)
Pro forma net income available
to common shareholders, proformed	$	3,155		$	1,334
Net income per common share, as reported:
Basic	$	0.15		$	0.02
Diluted		0.15			0.02
Pro Forma net income per common share, as if
the fair value method had been applied to all awards:
Basic	$	0.14		$	0.06
Diluted		0.14			0.05

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	For the nine months ended
	September 30,
	2004			2005
	(In thousands except
	per share amounts)
Net income available to common
shareholders, as reported	$	7,361		$	6,758
Add: Stock based employee compensation expense
recognized, net of tax		401			1,801
Less: Total stock-based employee compensation
expense determined under fair value method for all
awards, net of related tax effects		(658	)		(245	)
Pro forma net income available
to common shareholders	$	7,104		$	8,314
Net income per common share, as reported:
Basic	$	0.38		$	0.29
Diluted		0.34			0.28
Pro Forma net income per common share, as if
the fair value method had been applied to all awards:
Basic	$	0.37		$	0.36
Diluted		0.33			0.34

Diluted earnings per share amounts for the three months September 30, 2004 and 2005 are based upon 23,004,082 and 25,003,002 shares, respectively, that include the dilutive effect of assumed stock option and warrant conversions of 1,094,227 and 804,850 shares, respectively. Diluted earnings per share amounts for the nine months ended September 30, 2004 and 2005 are based upon 21,546,329 and 24,123,244 shares, respectively, that include the dilutive effect of assumed stock option and warrant conversion of 2,291,173 and 820,510 shares, respectively.

Repriced options are accounted for as compensatory options using variable plan accounting treatment in accordance with FASB Interpretation No. 44, “Accounting for Certain Transactions involving Stock Based Compensation − An Interpretation of APB Opinion No. 25” (FIN 44). Under variable plan accounting, compensation expense is adjusted for increases or decreases in the fair market value of the Company’s common stock to the extent that the market value exceeds the exercise price of the option. Variable plan accounting is applied to the repriced options until the options are exercised, forfeited, or expire unexercised.

The Company records deferred compensation based on the closing price of the Company’s stock on the issuance date for restricted stock. The deferred compensation is amortized to stock based compensation expense ratably over the vesting period of the restricted shares (one to three years). Deferred compensation amounted to $1.0 million as of September 30, 2005.

Derivative Instruments and Hedging Activities

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 between the cash flow hedge and the hedged item is recognized currently in income. Gains and losses accumulated in other comprehensive income (loss) 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, 2004 and September 30, 2005 were designated as cash flow hedges.

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.

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The Company typically uses fixed rate swaps and costless collars to hedge its exposure to material changes in the price of oil and natural gas and variable interest rates on long-term debt. 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.

Major Customers

The Company sold oil and natural gas production representing more than 10% of its oil and natural gas revenues as follows:

	For the Three Months						For the Nine Months
	Ended September 30,						Ended September 30,
	2004			2005			2004			2005
Cokinos Natural Gas Company		16	%		-			21	%		-
Chevron/Texaco		-			14	%		-			15	%
WMJ Investments Corp.		11	%		-			13	%		-
Texon L.P.		10	%		-			16	%		-
Liberty Gathering		-			10	%		-			-
Reichman Petroleum		10	%		12	%		-			-

Earnings Per 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
	2004		2005		2004		2005		2004		2005
Basic Earnings per Common Share:
Net income available to common shareholders	$	3,390	$	579		21,909,855		24,198,152	$	0.15	$	0.02
Dilutive effect of Stock Options, Warrants,
and Preferred Stock conversions		-		-		1,094,227		804,850
Diluted Earnings per Common Share
Net income available to common shareholders
plus assumed conversions	$	3,390	$	579		23,004,082		25,003,002	$	0.15	$	0.02

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	For the Nine Months Ended September 30,
	(In thousands except share and per share amounts)
	Income				Shares				Per-Share Amount
	2004		2005		2004		2005		2004		2005
Basic Earnings per Common Share:
Net income available to common shareholders	$	7,361	$	6,758		19,255,156		23,302,734	$	0.38	$	0.29
Dilutive effect of Stock Options, Warrants,
and Preferred Stock conversions		-		-		2,291,173		820,510
Diluted Earnings per Common Share
Net income available to common shareholders
plus assumed conversions	$	7,361	$	6,758		21,546,329		24,123,244	$	0.34	$	0.28

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 30,000 and zero stock options, during the three and nine months ended September 30, 2004 and 2005, 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.

Recently Issued Accounting Pronouncements

On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123(R)”). SFAS No. 123(R) will require companies to measure all employee stock-based compensation awards using a fair value method and record such expense in their consolidated financial statements. In addition, the adoption of SFAS No. 123(R) requires additional accounting and disclosure related to the income tax and cash flow effects resulting from share-based payment arrangements. SFAS No. 123(R) was effective beginning as of the first interim or annual reporting period beginning after June 15, 2005. On April 14, 2005, the SEC adopted a new rule that defers the effective date of SFAS No. 123(R) and allows companies to implement the provisions of SFAS No. 123(R) at the beginning of their next fiscal year. The Company will adopt the provisions of SFAS No. 123(R) during the first quarter of 2006 using the modified prospective method for transition. The Company believes it is likely that the impact of the requirements of SFAS No. 123(R) will significantly impact the Company’s future results of operations and continues to evaluate it to determine the degree of significance.

2. LONG-TERM DEBT:

At December 31, 2004 and September 30, 2005, long-term debt consisted of the following:

	December 31,			September 30,
	2004			2005
	(In thousands)
First Lien Credit Facility	$	18,000		$	-
Second Lien Credit Facility (1)		-			149,356
Senior Secured Notes (2)		16,268			-
Senior Subordinated Notes (2)		28,584			-
Capital lease obligations		122			48
Other		-			19
		62,974			149,423
Less: current maturities		(90	)		(1,555	)
	$	62,884		$	147,868

__________________

(1)   Amount has been reduced by $0.3 million for the fair value of an interest rate swap derivative financial instrument.

(2)   Amounts are net of discount of $2.0 million as of December 31, 2004.

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First Lien Credit Facility

On September 30, 2004, the Company entered into a Second Amended and Restated Credit Agreement with Hibernia National Bank and Union Bank of California, N.A. (the “First Lien Credit Facility”), which matures on September 30, 2007. The First Lien Credit Facility provides for (1) a revolving line of credit of up to the lesser of the Facility A Borrowing Base and $75.0 million and (2) a term loan facility of up to the lesser of the Facility B Borrowing Base and $25.0 million. It is secured by substantially all of the Company’s assets and is guaranteed by the Company’s wholly-owned subsidiary.

Prior to the July 21, 2005 amendment of the First Lien Credit Facility, the Facility A Borrowing Base was scheduled to be redetermined by the lenders semi-annually on each November 1 and May 1. The Company and the lenders may each request one unscheduled borrowing base redetermination subsequent to each scheduled redetermination. The Facility A Borrowing Base will at all times equal the Facility A Borrowing Base most recently redetermined by the lenders, less quarterly borrowing base reductions required subsequent to such redetermination. Before the July 2005 amendment of the First Lien Credit Facility, the borrowing base reductions were $4.0 million per quarter. Currently there are no predetermined quarterly borrowing base reductions. The lenders will reset the Facility A Borrowing Base amount at each scheduled and each unscheduled borrowing base redetermination date.

If the outstanding principal balance of the revolving loans under the First Lien Credit Facility exceeds the Facility A Borrowing Base at any time (including, without limitation, due to a quarterly borrowing base reduction (as described above)), the Company has the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, pledge additional collateral sufficient in the lenders' opinion to increase the Facility A Borrowing Base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Those payments would be in addition to any payments that may come due as a result of a borrowing base reduction. Otherwise, any unpaid principal or interest will be due at maturity.

For each revolving loan, the interest rate will be, at the Company’s option, (1) the eurodollar rate, plus an applicable margin equal to 2.375% if the amount borrowed is greater than or equal to 90% of the Facility A Borrowing Base, 2.0% if the amount borrowed is less than 90%, but greater than or equal to 50% of the Facility A Borrowing Base, or 1.625% if the amount borrowed is less than 50% of the Facility A Borrowing Base; or (2) the Base Rate, plus an applicable margin of 0.375% if the amount borrowed is greater than or equal to 90% of the Facility A Borrowing Base. The interest rate on each term loan will be, at the Company’s option, (1) the eurodollar rate, plus an applicable margin to be determined by the lenders; or (2) the Base Rate, plus an applicable margin to be determined by the lenders. 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.

Before the July 21, 2005 amendment, noted below, the Company was subject to the following covenants under the terms of the First Lien Credit Facility. These covenants, as amended, include the following financial covenants: (1) a minimum current ratio of 1.0 to 1.0 (including availability under the borrowing base), (2) a minimum quarterly debt services coverage of 1.25 times, (3) a minimum shareholders’ equity equal to $108.8 million, plus 100% of all subsequent common and preferred equity contributed by shareholders subsequent to December 31, 2004, plus 50% of all positive earnings occurring subsequent to December 31, 2004, and (4) a maximum total recourse debt to EBITDA ratio (as defined in the First Lien Credit Facility) of not more than 3.0 to 1.0. The First Lien Credit Facility also places restrictions on additional indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, asset pledges and mortgages, change of control, repurchase or redemption for cash of the Company’s common stock, speculative commodity transactions and other matters.

On April 27, 2005, the Company amended the First Lien Credit Facility to, among other things, add a provision restricting loans from the Company to its subsidiaries or guarantors of the First Lien Credit Facility if the proceeds of such loans will be invested in an entity in which the Company holds an equity interest.

On July 21, 2005, in connection with entering into the Second Lien Credit Facility, as defined and discussed below in this Note 2, the Company amended the First Lien Credit Facility to among other things, provide for (1) an adjustment to the maximum total net recourse debt to EBITDA (as defined in the First Lien Credit Facility, as amended) ratio, such that the maximum is 3.5 to 1.0 through September 30, 2006, 3.25 to 1.0 through December 31, 2006 and 3.0 to 1.0 thereafter; (2) an adjustment to the covenant regarding maintenance of a minimum shareholders’ equity, such that the quarterly minimum is $115.0 million plus 100% of all subsequent common and preferred equity contributed by shareholders subsequent to March 31, 2005, plus 50% of all positive earnings occurring subsequent to March 31, 2005; (3) an adjustment to the covenant regarding maintenance of a minimum EBITDA to interest expense ratio, such that the minimum is 2.75 to 1.0 through September 30, 2006 and 3.0 to 1.0 thereafter; and (4) Facility A Borrowing Base redeterminations are scheduled at the end of each calendar quarter; (5) quarterly borrowing base reductions are reduced from $4.0

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million to zero; and (6) the addition of other provisions and a consent which permits the indebtedness incurred and the liens granted under the Second Lien Credit Facility.

The Facility A Borrowing Base, under the First Lien Credit Facility, as of December 31, 2004 and September 30, 2005 was $30.0 million and $20.0 million, respectively. In connection with entering into the Second Lien Credit Facility, effective July 21, 2005, and until the September 30, 2005 redetermination, we elected to set our borrowing base at $10.0 million commensurate with our financing needs in the near term but $10.0 million below the $20.0 million borrowing base availability approved by the lenders.

At December 31, 2004, amounts outstanding under the First Lien Credit Facility totaled $18.0 million with an additional $12.0 million available for future borrowings. At September 30, 2005, there were no amounts outstanding under the First Lien Credit Facility. At December 31, 2004 and at September 30, 2005, no letters of credit were issued and outstanding under the First Lien Credit Facility.

Second Lien Credit Facility

On July 21, 2005, the Company entered into a Second Lien Credit Agreement with Credit Suisse, as administrative agent and collateral agent (the “Agent”) and the lenders party thereto (the “Second Lien Credit Facility”) that matures on July 21, 2010. The Second Lien Credit Facility provides for a term loan facility in an aggregate principal amount of $150.0 million. It is secured by substantially all of the Company’s assets and is guaranteed by the Company’s subsidiary. The liens securing the Second Lien Credit Facility are second in priority to the liens securing the First Lien Credit Facility, as more fully described in the intercreditor agreement among the Company, the Agent, the agent under the First Lien Credit Facility and the lenders dated July 21, 2005.

A portion of the proceeds from the Second Lien Credit Facility were used to (1) repay and cancel all outstanding indebtedness under the Subordinated Notes and the Senior Secured Notes; (2) repay, at the Company’s election, existing indebtedness under the First Lien Credit Facility; and (3) to pay associated transaction costs. The remaining proceeds are expected to be used to partially fund the Company’s ongoing capital expenditures program and for other general corporate purposes.

The interest rate on each base rate loan will be (1) the greater of the Agent’s prime rate and the federal funds effective rate plus 0.5%, plus (2) a margin of 5.0%. The interest rate on each eurodollar loan will be the adjusted LIBOR rate plus a margin of 6.0%. Interest on eurodollar loans is payable on either the last day of each period or every three months, whichever is earlier. Interest on base rate loans is payable quarterly.

The Company is subject to certain covenants under the terms of the Second Lien Credit Facility. These covenants include, but are not limited to, the maintenance of the following financial covenants: (1) a minimum current ratio of 1.0 to 1.0 including availability under the borrowing base under the First Lien Credit Facility; (2) a minimum quarterly interest coverage ratio of 2.75 to 1.0 through June 30, 2006 and 3.0 to 1.0 thereafter; (3) a minimum quarterly proved reserve coverage ratio of 1.5 to 1.0 through September 30, 2006 and 2.0 to 1.0 thereafter; and (4) a maximum total net recourse debt to EBITDA (as defined in the Second Lien Credit Facility) ratio of not more than 3.5 to 1.0 through June 30, 2006 and 3.25 to 1.0 thereafter. The Second Lien Credit Facility also places restrictions on additional indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of the Company’s common stock, speculative commodity transactions, transactions with affiliates and other matters.

The Second Lien Credit Facility is subject to customary events of default. Subject to certain exceptions, if an event of default occurs and is continuing, the Agent may accelerate amounts due under the Second Lien Credit Facility (except for a bankruptcy event of default, in which case such amounts will automatically become due and payable). If an event of default occurs under the Second Lien Credit Facility as a result of an event of default under the First Lien Credit Facility, the Agent may not accelerate the amounts due under the Second Lien Credit Facility until the earlier of 45 days after the occurrence of the event resulting in the default and acceleration of the loans under the First Lien Credit Facility.

Rocky Mountain Gas, Inc. Note

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 Rocky Mountain Gas, Inc. (“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. All of these amounts have been paid. The RMG note was secured solely by CCBM’s interests in the oil and natural gas leases in Wyoming and Montana. In connection with the Company’s investment in Pinnacle Gas Resources, Inc. (“Pinnacle”), 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

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properties contributed to Pinnacle. During the second quarter of 2004, CCBM relinquished a portion of its interests in certain oil and natural gas leases to RMG and reduced the principal due on the RMG note by $0.3 million.

Capital Leases

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 was 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 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. Depreciation on the capital leases for the three months ended September 30, 2004 and 2005 amounted to $11,000 and $10,000 respectively. Depreciation on the capital leases for the nine months ended September 30, 2004 and 2005 amounted to $34,000 and $32,000, respectively, and accumulated depreciation on the leased equipment at December 31, 2004 and September 30, 2005 amounted to $124,000 and $156,000, respectively.

Senior Subordinated Notes and Related Securities

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 (23A SBIC), L.P.), 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 was amortized over the life of the notes. Interest payments were due quarterly commencing on March 31, 2000. As amended as described below, the Subordinated Notes allowed the Company, until December 2005, to increase the amount of the Subordinated Notes for 60% of the interest which would otherwise be payable in cash. As of December 31, 2004 and the July 21, 2005 repayment date, the outstanding balance of the Subordinated Notes had been increased by $6.8 million and $7.6 million respectively, for such interest paid in kind. During 2004, Mellon Ventures, L.P., JPMorgan Partners (23A SBIC), Steven A. Webster and Douglas A. P. Hamilton exercised warrants to purchase 276,019, 2,208,152, 92,006 and 92,006 shares of common stock, respectively, on a cashless exercise basis for a total of 205,692, 1,684,949, 70,205 and 70,205 shares of common stock, respectively, and Paul B. Loyd, Jr., exercised warrants for cash to purchase 92,006 shares for a total of 92,006 shares of common stock. As a result, no warrants to purchase shares of common stock remain outstanding from the warrants originally issued in December 1999.

On June 7, 2004, an unaffiliated third party (the “Subordinated Notes Purchaser”) purchased all the outstanding Subordinated Notes from the original note holders. In exchange for a $0.4 million amendment fee, certain terms and conditions of the Subordinated Notes were amended, to provide for, among other things, (1) a one year extension of the maturity to December 15, 2008, (2) a one year extension, through December 15, 2005, of the paid-in-kind (“PIK”) interest option to pay-in-kind 60% of the interest due each period by increasing the principal balance by a like amount (the “PIK option”), (3) an additional one year option to extend the PIK option through December 15, 2006 at an annual interest rate on the deferred amount of 10% and the payment of a one-time amendment fee equal to 0.5% of the principal then outstanding and (4) additional flexibility to obtain a separate project financing facility in the future. The amendment fee was amortized over the remaining life of the Subordinated Notes using the effective interest method.

The Company was 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, (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 (d) a limitation on the Company’s Total Debt (as defined in the securities purchase agreement) to 3.5 times EBITDA for any twelve month period.

As discussed above, the Subordinated Notes were repaid in full in connection with entering into the Second Lien Credit Facility in July 2005.

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Senior Secured Subordinated Notes

On October 29, 2004, the Company entered into a Note Purchase Agreement (the “Senior Secured Notes Purchase Agreement”) with PCRL Investments L.P. (the “Senior Secured Notes Purchaser”). Pursuant to the Senior Secured Notes Purchase Agreement, the Company could issue up to $28.0 million aggregate principal amount of 10% Senior Secured Subordinated Secured Notes due 2008 (the “Senior Secured Notes”) for a purchase price equal to 90% of the principal amount of the Senior Secured Notes then issued. On October 29, 2004 and May 31, 2005, the Senior Secured Notes Purchaser purchased $18.0 million and $4.0 million aggregate principal amount of the Senior Secured Notes for a purchase price of $16.2 million and $3.6 million, respectively. The debt discounts were amortized to interest expense using the effective interest method.

The Senior Secured Notes were secured by a second lien on substantially all of the Company’s current proved producing reserves and non-reserve assets, guaranteed by the Company’s subsidiary, and subordinated to the Company’s obligations under the First Lien Credit Facility. The Senior Secured Notes bore interest at 10% per annum, payable quarterly on the 5th day of March, June, September and December of each year beginning March 5, 2005. The principal on the Senior Secured Notes was due December 15, 2008, and the Company had the option to prepay the Senior Secured Notes at any time. The Senior Secured Notes included an option that allowed the Company to pay-in-kind 50% of the interest due until June 5, 2007 by increasing the principal due by a like amount. At the July 21, 2005 repayment date, the outstanding balance of the Senior Subordinated Secured Notes had been increased by $0.5 million for such interest paid-in-kind. Subject to certain conditions, the Company had the option to pay the interest on and principal of (at maturity or upon prepayment) the Senior Secured Notes with the Company’s common stock, as long as the Secured Note Purchaser did not hold more than 9.99% of the number of shares of the Company’s common stock outstanding immediately after giving effect to such payment. The value of such shares issued as payment on the Senior Secured Notes was determined based on 90% of the volume weighted average trading price during a specified period of days beginning with the date of the payment notice and ending before the payment date. Issuance costs related to the transaction were $0.5 million and were amortized over the life of the Senior Secured Notes using the effective interest method.

As contemplated by the Secured Senior Notes Purchase Agreement, the Company also entered into a registration rights agreement with the Senior Secured Note Purchaser (the “Registration Rights Agreement”). In the event the Company chose to issue shares of its common stock as payment of interest on the principal of the Senior Secured Notes, the Registration Rights Agreement provides registration rights with respect to such shares. The Company was generally required to file a resale shelf registration statement to register the resale of such shares under the Securities Act of 1933 (the “Securities Act”) if such shares are not freely tradable under Rule 144(k) under the Securities Act. The Company was subject to certain covenants under the terms of the Registration Rights Agreement, including the requirement that the registration statement be kept effective for resale of shares subject to certain “blackout periods,” when sales may not be made. In certain circumstances, including those relating to (1) delisting of the Company’s common stock, (2) blackout periods in excess of a maximum length of time, (3) certain failures to make timely periodic filings with the Securities and Exchange Commission, or (4) certain delays or failures to deliver stock certificates, the Company may be required to repurchase common stock issued as payment on the Senior Secured Notes and, in certain of these circumstances, to pay damages based on the market value of its common stock. In certain situations, the Company is required to indemnify the holders of registration rights under the Registration Rights Agreement, including, without limitation, for liabilities under the Securities Act.

The Senior Secured Notes Purchase Agreement included certain representations, warranties and covenants by the parties thereto. The Company was subject to certain covenants under the terms of the Senior Secured Notes Purchase Agreement, including, without limitation, the maintenance of the following financial covenants: (1) a maximum total recourse debt to EBITDA ratio of not more than 3.50 to 1.0, (2) a minimum EBITDA to interest expense ratio of 2.50 to 1.0, and (3) as of April 30, 2005, a minimum tangible net worth of $12.5 million in excess of the Company’s tangible net worth as of September 30, 2004. Upon a change of control, any holders of the Senior Secured Notes could require the Company to repurchase such holders' Senior Secured Notes at a price equal to then outstanding principal amount of such Senior Secured Notes, together with all interest accrued on such Senior Secured Notes through the date of repurchase. The Senior Secured Notes Purchase Agreement also placed restrictions on additional indebtedness, dividends to stockholders, liens, investments, mergers, acquisitions, asset dispositions, asset pledges and mortgages, repurchase or redemption for cash of the Company’s common stock, speculative commodity transactions and other matters. The Senior Secured Notes Purchaser is an affiliate of the Subordinated Notes Purchaser.

As discussed above, the Senior Secured Notes were repaid in full in connection with entering into the Second Lien Credit Facility in July 2005.

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3.   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 natural 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”). The Company accounts for its interest in Pinnacle using the equity method. CCBM no longer has a drilling obligation in connection with the oil and natural gas leases contributed to Pinnacle.

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, and their nominees constitute a majority of Pinnacle’s board of directors.

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 acreage prospective for coalbed methane development in the Powder River Basin of Wyoming from Gastar Exploration, Ltd. 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.

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. As of June 30, 2003, approximately $1.1 million of the remaining balance of CCBM’s obligation to RMG was scheduled to be paid in monthly installments of approximately $52,805 through November 2004 and a balloon payment on December 31, 2004. All of these amounts have been paid. The RMG note was 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 acreage in 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. Other than indirectly through Pinnacle, CCBM currently has no proved reserves of, and is no longer receiving revenue from, coalbed methane gas.

In March 2004, Credit Suisse First Boston Private Equity Entities (the “CSFB Parties”) contributed additional funds of $11.8 million into Pinnacle to fund its 2004 development program, which increased the CSFB Parties’ ownership to 66.7% on a fully diluted basis assuming we and RMG each elect not to exercise our available options.

In March 2005, Pinnacle entered into a purchase and sale agreement to acquire additional undeveloped acreage, which would also significantly increase its development program budget in 2005. CCBM and the other Pinnacle shareholders were given the option to participate in the equity contribution into Pinnacle needed to finance this acquisition and its development program in 2005. Should the Company maintain its proportionate ownership interest in Pinnacle on a fully diluted basis, the Company estimates that it would be required to contribute approximately $3.2 million by December 31, 2006. If CCBM did not make an equity contribution, and, as a result, its fully diluted ownership in Pinnacle has been reduced to 17.1%. There can be no assurance regarding CCBM’s level of participation in future equity contributions to Pinnacle, if any.

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As of September 30, 2005, on a fully diluted basis, assuming that all parties exercised their Pinnacle Warrants and Pinnacle Stock Options, the CSFB Parties, CCBM and RMG would have ownership interests of approximately 65.8%, 17.1% and 17.1%, respectively.

For accounting purposes, the Pinnacle contribution in 2003 was 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 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 sheets as of December 31, 2004 and September 30, 2005.

4.   INCOME TAXES:

The Company provides deferred income taxes at the rate of 35%, which also approximates its statutory rate that amounted to $2.1 million and $0.6 million for the three-month periods ended September 30, 2004 and 2005, respectively, and $4.8 million and $4.5 million for the nine-month periods ended September 30, 2004 and 2005, respectively. The rate for the three month period ended September 30, 2005 was greater than 35% primarily as a result of the preferred dividend and valuation allowance on Pinnacle.

5.   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 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.

In September 2005, the Company entered into an agreement to purchase over an 18 month period a non-exclusive license to certain geophysical data at a cost which will range from $2.0 million to $2.5 million, contingent upon whether the Company exercises an option to acquire additional data under the agreement.

6.   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 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 was convertible into common stock by the investors at a conversion price of $5.70 per share, subject to adjustments, and was initially convertible into 1,052,632 shares of common stock. Dividends on the Series B Preferred Stock were 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, 2003 and through the conversion dates specified below, the outstanding balance of the Series B Preferred Stock was increased by $1.2 million (11,987 shares) and $1.5 million (15,133 shares), respectively, for dividends paid in kind. The Series B Preferred Stock was 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 also participated in any dividends declared on the common stock. Holders of the Series B Preferred Stock would have received a liquidation preference upon the liquidation of, or certain mergers or sales of substantially all assets involving, the Company. Such holders also had the option of receiving a change of control repayment price upon certain deemed change of control transactions. Mellon Ventures, Inc. converted all of its Series B Preferred Stock (approximately 49,938 shares) into 876,099 shares of common stock on May 25, 2004. Steven A. Webster converted all of his Series B Preferred Stock (approximately 25,195 shares) into 442,026 shares of common stock on June 30, 2004. As a result, no shares of Series B Preferred Stock remain outstanding. The total value of the Series B Preferred Stock upon conversion was $7.5 million and was reclassified to shareholders’ equity following the conversion.

The warrants had a five-year term and entitled 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 were exercisable on a cashless

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exercise basis. During 2004 Mellon Ventures, Inc. exercised all of its 168,422 warrants on a cashless exercise basis for a total of 36,570 shares of common stock and, during the first quarter of 2005, Mr. Webster exercised all of his 84,210 warrants on a cashless basis, receiving a total of 54,669 shares of common stock.

Net proceeds of the sale of the Series B Preferred Stock were approximately $5.8 million and were used primarily to fund the Company’s ongoing exploration and development program and general corporate purposes.

7.   SHAREHOLDERS’ EQUITY:

In the first quarter of 2004, the Company completed the public offering of 6,485,000 shares of common stock at $7.00 per share generating net proceeds of approximately $23.4 million. The offering included 3,655,500 newly issued shares offered by the Company and 2,829,500 shares offered by certain selling shareholders. The Company did not receive any proceeds from the shares sold by the selling shareholders. The Company used part of the net proceeds from this offering to accelerate its drilling program and to retain larger interests in portions of its drilling prospects that the Company otherwise would sell down or for which the Company would seek joint partners and for general corporate purposes. Initially, the Company used a portion of the net proceeds to repay the $7.0 million outstanding principal amount under its revolving credit facility and to complete an $8.2 million Barnett Shale acquisition on February 27, 2004.

In January 2005, all of the remaining 250,000 warrants that were originally issued to affiliates of Enron were exercised for 250,000 shares of the Company’s common stock. The net cash proceeds from the exercise of the warrants amounted to $1.0 million.

On June 13, 2005, the Company sold 1.2 million shares of the Company’s common stock to institutional investors (the “Investors”) at a price of $15.25 per share in a private placement (the “Private Placement”), a 4.7% discount to the closing price on the NASDAQ stock market for the Company’s common stock the day prior to closing. The number of shares sold was approximately 5% of the fully diluted shares outstanding before the offering. The net proceeds of the Private Placement, after deducting placement agents’ fees but before paying offering expenses, were approximately $17.2 million. The Company used the proceeds from the Private Placement to fund a portion of its capital expenditure program for 2005, including the drilling programs in the Barnett Shale and onshore Gulf Coast areas, and for other corporate purposes.

In connection with the Private Placement, the Company was required to file a resale shelf registration statement to register the resale of the shares sold under the Securities Act and will be required to cause the registration statement to become and be kept effective for resale of shares for two years from the date of their original sale. In certain situations, the Company is required to indemnify the investors in the Private Placement, including without limitation, for certain liabilities under the Securities Act.

The Company issued 7,382,773 and 2,060,658 shares of common stock during the nine months ended September 30, 2004 and 2005, respectively. The shares issued during the nine months ended September 30, 2004 consisted of 3,655,500 shares issued through the 2004 public offering, 2,159,627 shares issued through the exercise of warrants, 1,318,124 shares issued through the conversion of Series B Preferred Stock and 249,522 shares issued through the exercise of options granted under the Company’s Incentive Plan. The shares issued during the nine months ended September 30, 2005 consisted of 1,200,000 shares issued in the Private Placement, 127,068 shares issued in connection with the acquisition of certain oil and gas properties, 304,669 shares issued through the exercise of warrants, 80,065 shares issued as restricted stock awards to employees and 348,856 shares issued through the exercise of options granted under the Company’s Incentive Plan.

8.   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 termination or 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

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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, 2004 and September 30, 2005, the unrealized gain/(loss) on oil and natural gas hedges was $59,000 and ($5.0) million, net of tax of $34,000 and ($2.7) million, respectively, remained in accumulated other comprehensive income (loss) related to the valuation of the Company’s hedging positions.

Total oil hedged under swaps and collars during the three months ended September 30, 2004 and 2005 was 30,600 Bbls and 27,600 Bbls, respectively. Total natural gas hedged under swaps and collars during the three months ended September 30, 2004 and 2005 was 1,012,000 MMBtu and 966,000 MMBtu, respectively. Total oil hedged under swaps and collars during the nine months ended September 30, 2004 and 2005 was 84,900 Bbls and 99,300 Bbls, respectively. Total natural gas hedged under swaps and collars during the nine months ended September 30, 2004 and 2005 were 2,739,000 MMBtu and 2,926,000 MMBtu, respectively. The net losses realized by the Company under such hedging arrangements were ($0.3) million and ($0.8) million for the three months ended September 30, 2004 and 2005, respectively, and are included in oil and natural gas revenues. The net loss realized by the Company under such hedging arrangements was ($0.7) million in each of the nine-month periods ended September 30, 2004 and 2005, and is included in oil and natural gas revenues.

At September 30, 2004 and 2005 the Company had the following outstanding hedge positions:

As of September 30, 2004
	Contract Volumes
Quarter	BBls		MMbtu		Average Fixed Price		Average Floor Price		Average Ceiling Price
Fourth Quarter 2004		9,300			$	38.85
Fourth Quarter 2004		15,300					$	41.21	$	50.00
Fourth Quarter 2004				1,197,000				4.71		6.94
First Quarter 2005		18,000						40.00		50.00
First Quarter 2005				810,000				5.09		8.00
Second Quarter 2005				364,000				5.25		7.15
Second Quarter 2005				91,000		6.03
Third Quarter 2005				368,000				5.25		7.40
Third Quarter 2005				92,000		6.03
Fourth Quarter 2005				276,000				5.25		7.92
Fourth Quarter 2005				92,000		6.03

As of September 30, 2005
	Contract Volumes
Quarter	BBls		MMbtu		Average Fixed Price		Average Floor Price		Average Ceiling Price
Fourth Quarter 2005				874,000			$	6.74	$	9.24
Fourth Quarter 2005				92,000	$	6.03
Fourth Quarter 2005		9,200						57.00		62.55
First Quarter 2006				722,000				8.02		9.84
Second Quarter 2006				455,000				6.45		8.00
Third Quarter 2006				460,000				6.49		8.32
Fourth Quarter 2006				368,000				7.25		8.75
First Quarter 2007				360,000				7.50		9.45
Second Quarter 2007				273,000				6.68		8.08
Third Quarter 2007				276,000				6.80		8.20
Fourth Quarter 2007				276,000				6.92		8.32
First Quarter 2008				182,000				7.25		8.65

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During October 2005, the Company entered into costless collar arrangements covering 366,000 MMBtu of natural gas production for April 2006 through September 2006 with an average floor price of $8.50 per MMBtu and an average ceiling price of $14.125 per MMBtu.

During the third quarter of 2005, the Company entered into interest rate swap agreements, designated as fair value hedges, with respect to amounts outstanding under the Second Lien Credit Facility. These arrangements are designed to manage the Company’s exposure to interest rate fluctuations during the period beginning January 1, 2006 through June 30, 2007 by effectively exchanging existing obligations to pay interest based on floating rates for obligations to pay interest based on fixed LIBO rates. At September 30, 2005, unrealized gains that remained in other comprehensive income related to the valuation of these swap arrangements totaled $175,000, net of taxes of $94,000.

The Company’s outstanding hedge positions under these interest rate swap agreements at September 30, 2005 are as follows (dollars in thousands):

	Notional		Fixed
Quarter	Amount		LIBO Rate
First Quarter 2006	$	149,250		4.394	%
Second Quarter 2006		148,875		4.394	%
Third Quarter 2006		148,500		4.394	%
Fourth Quarter 2006		148,125		4.394	%
First Quarter 2007		147,750		4.507	%
Second Quarter 2007		147,375		4.507	%

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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. You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2004 and the unaudited financial statements included elsewhere herein.

General Overview

We 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, we began obtaining 3-D seismic data and optioning to lease substantial acreage in 1995 and began drilling our 3-D based prospects in 1996. In 2004, we drilled 71 gross wells (27.3 net), including 38 gross wells in the onshore Gulf Coast area and 33 gross wells in the Barnett Shale play, with a success rate of 92%. During the nine months ended September 30, 2005, we were apparently successful in 49 of the 52 (29.5 net) wells drilled. We had apparent drilling success in 12 of 15 gross (4.6 net) wells in the onshore Gulf Coast area, 29 of 29 gross (17.3 net) wells in the Barnett Shale area and eight of eight gross (7.6 net) wells in the East Texas area. We have completed 26 of these apparent successful wells and 23 are in the process of being completed. In 2005, we plan to drill 26 gross wells (10.2 net) in the onshore Gulf Coast area, 45 gross wells (28.5 net) in our Barnett Shale area and nine gross wells (9.0 net) in our East Texas area. 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, our cash flow, success of drilling programs, weather delays and other factors. If we drill the number of wells we have budgeted for 2005, depreciation, depletion and amortization, oil and natural gas operating expenses and production are expected to increase over levels incurred in 2004.

Since our initial public offering, we have grown primarily through the exploration of properties within our project areas, although we consider acquisitions from time to time and may in the future complete acquisitions that we find attractive. In 2004 and 2005 we completed asset acquisitions in our Barnett Shale project area described below in “—Barnett Shale Activity.”

2004 Public Offering and 2005 Private Placement of Common Stock

In the first quarter of 2004, we completed the public offering of 6,485,000 shares of our common stock at $7.00 per share. The offering included 3,655,500 newly issued shares offered by us and 2,829,500 shares offered by certain selling shareholders. Our net proceeds of approximately $23.4 million from this offering were used: (1) to accelerate our drilling program, (2) to retain larger interests in portions of our drilling prospects that we otherwise would sell down (or for which we would seek joint partners), (3) to fund a portion of our activities in the Barnett Shale area and (4) for general corporate purposes. We did not receive any proceeds from the shares sold by the selling shareholders.

In the second quarter of 2005, we sold 1.2 million shares of our common stock (or approximately 5% of the fully diluted shares outstanding before the offering) to institutional investors at a price of $15.25 per share in a private placement (the “Private Placement”), a 4.7% discount to the close price on the Nasdaq stock market for our common stock the day prior to pricing. The net proceeds from the Private Placement, after the placement agents’ fees but before offering expenses, were approximately $17.2 million. We intend to use these proceeds from the Private Placement to fund a portion of our 2005 capital expenditure program, including our drilling programs in the Barnett Shale and onshore Gulf Coast areas, and for other corporate purposes. In connection with the Private Placement, we were required to file a resale shelf registration statement to register the resale of the shares sold under the Securities Act and will be required to cause the registration statement to become and be kept effective for resale of shares for two years from the date of their original sale. In certain situations, we are required to indemnify the investors in the Private Placement, including without limitation, for certain liabilities under the Securities Act.

Barnett Shale Activity

In mid-2003, we became active in the Barnett Shale play located in Tarrant and Parker counties in Northeast Texas. Our activity accelerated as a result of the acquisition on February 27, 2004 of working interests and acreage in certain oil and gas wells located in the Newark East Field in Denton County, Texas in the Barnett Shale trend for $8.2 million. This acquisition included non-operated working interests in properties ranging from 12.5% to 45% over 3,800 gross acres, or an average working interest of 39%. The acquisition included 21 existing gross wells (6.7 net) and interests in approximately 1,500 net acres, which provide another estimated 31 gross drill sites: five of which were drilled in 2004, 21 of which will target proved undeveloped reserves and five of which will be exploratory.

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In April 2005, we acquired assets in the Barnett Shale for approximately $4.1 million. This acquisition consisted of approximately 600 net acres and working interests in 14 existing gross wells (7.3 net) with an estimated 5.4 MMcfe of proved reserves, based upon our internal estimates. All of the interests in the wells acquired related to wells in which we already had an interest. The consideration paid for this acquisition was $2.3 million in cash and 112,697 shares of our common stock.

Initially, we financed our Barnett Shale activities with our available cash on hand. We financed a portion of our 2004 capital expenditure program for the Barnett Shale area with funds from the October 2004 issuance of the 10% Senior Subordinated Secured Notes. In June and July 2005, we completed the Private Placement and entered into the Second Lien Credit Facility (see “2004 Public Offering and 2005 Private Placement Common Stock” above and “Financing Arrangements − Second Lien Credit Facility and Refinancing,” below), a portion of the net proceeds of which will be used to partially fund our ongoing capital expenditure program, including our drilling programs in the Barnett Shale and onshore Gulf Coast areas.

In the Barnett Shale area, we drilled 33 gross wells (13.7 net) in 2004 and 29 gross wells (17.3 net) during the nine months ended September 30, 2005, all of which were apparent successes. We plan to drill 45 gross wells (28.5 net) in this area in 2005, based upon our available proceeds from the Second Lien Credit Facility, the available funds under the First Lien Credit Facility (as defined below in “Financing Arrangements − First Lien Credit Facility”) and achieving expected operating cash flows. For the quarter ended September 30, 2005 our average daily production was approximately 5.6 MMcfe/d, with 54 gross wells on line and another 27 gross wells in various stages of testing, completion and awaiting pipeline hookup. Currently we estimate our production rate to be approximately 6.5 MMcfe/d.

In addition to our drilling activity, we have continued to expand our Barnett Shale acreage position, growing our net leasehold acreage from approximately 4,100 to 30,700 to 75,000 acres, at the end of 2003, 2004 and September 2005, respectively. Similarly, we have increased our estimated number of exploratory drilling locations (horizontal) in the Barnett Shale area from 21 to 152 to 383 locations, at the end of 2003, 2004 and September 2005, respectively, and we have increased our estimated number of developmental locations from four to 40 to 52 horizontal locations, at the end of 2003, 2004 and September 2005, respectively.

Recent Developments

Effective February 1, 2005, we sold to a private company our interest in the Patterson Prospect Area in St. Mary Parish, Louisiana, including the Shadyside #1 well and any anticipated follow-up wells, for approximately $9.0 million. Our average daily production from the Shadyside #1 during the fourth quarter 2004 was approximately 970 Mcfe per day. Proceeds from the sale were used in the 2005 Barnett Shale and Gulf Coast drilling program and for general corporate purposes.

On or about April 30, 2005, two of our top producing wells - the Delta Farms #1 and the Beach House #1, were shut in for workovers. The workover on the Beach House #1 has been completed, and it was put online on July 1, 2005. The Beach House #1 currently averages approximately 0.5 MMcfe/d net compared to 2.0 MMcfe/d net prior to the workover. The workover on the Delta Farms #1 also has been completed, and it was put online on July 14, 2005. The Delta Farms #1 currently averages approximately 0.9 MMcfe/d net compared to 2.0 MMcfe/d net prior to the workover. While the production levels of these wells have continued to improve in the near term, we cannot predict whether the production levels will continue to improve or approach their pre-shut in production levels. We also experienced moderate disruption to our third quarter production due to wells shut-in from Hurricanes Katrina and Rita, including the recently worked over Delta Farms #1 and Beach House #1 wells.  By the middle of October 2005, all such wells had been put back on line to sales.

Accordingly, the combined impact of shut-in wells from the aforementioned hurricanes and workovers on our third quarter average daily production was a reduction of approximately 2.0 MMcfe per day.

On July 21, 2005, we entered into the Second Lien Credit Facility agreement providing for a term loan facility in an aggregate principal amount of $150.0 million. A portion of the net proceeds from the Second Lien Credit Facility were used to repay the Subordinated Notes, the Senior Secured Notes and our outstanding indebtedness under the First Lien Credit Facility. See “Financing Arrangements − Second Lien Credit Facility and Refinancing.” In connection with the retirement of the Subordinated Notes and the Senior Secured Notes, the Company recorded a $3.7 million pre-tax charge for early debt extinguishment costs during the third quarter of 2005 primarily attributable to the write off of unamortized deferred loan costs and debt discounts.

After completing our scheduled May 2005 borrowing base redetermination under the First Lien Credit Facility, our prior borrowing base of $33.0 million was increased to $39.0 million, effective June 30, 2005 through July 21, 2005. This borrowing base included the impact of the workovers completed on the Delta Farms #1 and Beach House #1 wells. In connection with entering into the Second

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Lien Credit Facility, effective July 21, 2005, we elected to set our borrowing base at $10.0 million commensurate with our financing needs in the near term but $10.0 million below the $20.0 million borrowing base availability approved by the lenders. Subsequently, we completed our scheduled redetermination on September 30, 2005, increasing our borrowing base availability to $20.0 million.

Pinnacle Gas Resources, Inc.

During the second quarter of 2001, we acquired interests in natural gas and oil leases in Wyoming and Montana in areas prospective for coalbed methane and subsequently began to drill wells on those leases. During the second quarter of 2003, we (through CCBM, our wholly-owned subsidiary) contributed our interests in certain of these leases to a newly formed company, Pinnacle Gas Resources, Inc. (“Pinnacle”). In exchange for this contribution, we received 37.5% of the common stock of Pinnacle and options to purchase additional Pinnacle common stock. We account for our interest in Pinnacle using the equity method. As a result, our contributed operations and reserves are no longer directly reflected in our financial statements.

In March 2004, Credit Suisse First Boston Private Equity Entities (the “CSFB Parties”) contributed additional funds of $11.8 million into Pinnacle to fund its 2004 development program, which increased the CSFB Parties’ ownership to 66.7% on a fully diluted basis assuming we and RMG each elect not to exercise our available options.

In March 2005, Pinnacle entered into a purchase and sale agreement to acquire additional undeveloped acreage, which would also significantly increase its development program budget in 2005. CCBM and the other Pinnacle shareholders were given the option to participate in the equity contribution into Pinnacle needed to finance this acquisition and its development program in 2005. Should we maintain our proportionate ownership interest in Pinnacle on a fully diluted basis, we estimate that we would be required to contribute approximately $3.2 million by December 31, 2006. If CCBM did not make an equity contribution, and, as a result, its fully diluted ownership in Pinnacle has been reduced to 17.1%. There can be no assurance regarding CCBM’s level of participation in future equity contributions to Pinnacle, if any.

As of September 30, 2005, on a fully diluted basis, assuming that all parties exercised their Pinnacle Warrants and Pinnacle Stock Options, the CSFB Parties, CCBM and RMG would have ownership interests of approximately 65.8%, 17.1% and 17.1%, respectively.

In addition to our interest in Pinnacle, we have maintained interests in approximately 162,000 gross acres in the Castle Rock coalbed methane project area in Montana and the Oyster Ridge project area in Wyoming. Our discussion of future drilling and capital expenditures does not reflect operations conducted through Pinnacle.

Hedging

Our financial results are largely dependent on a number of factors, including commodity prices. Commodity prices are outside of our control and historically have been and are expected to remain volatile. Natural gas prices in particular have remained volatile during the last few years and more recently oil prices have become volatile. Commodity prices are affected by changes in market demands, overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. As a result, we cannot accurately predict future natural gas, natural gas liquids and crude oil prices, and therefore, cannot accurately predict revenues.

Because natural gas and oil prices are unstable, we periodically enter into price-risk-management transactions such as swaps, collars, futures and options to reduce our exposure to price fluctuations associated with a portion of our natural gas and oil production and to achieve a more predictable cash flow. The use of these arrangements limits our ability to benefit from increases in the prices of natural gas and oil. Our hedging arrangements may apply to only a portion of our production and provide only partial protection against declines in natural gas and oil prices.

Results of Operations

Three Months Ended September 30, 2005,

Compared to the Three Months Ended September 30, 2004

Oil and natural gas revenues for the three months ended September 30, 2005 increased 43% to $17.6 million from $12.3 million for the same period in 2004. Production volumes for natural gas during the three months ended September 30, 2005 increased from 1.6 Bcf for the three months ended September 30, 2004 to 1.9 Bcf in the third quarter of 2005. Average natural gas prices increased 34% to $7.65 per Mcf in the third quarter of 2005 from $5.69 per Mcf in the same period in 2004. Production volumes for oil in the third

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quarter of 2005 decreased 27% to 53 MBbls from 73 MBbls for the same period in 2004. Average oil prices increased 44% to $62.84 per barrel in the third quarter of 2005 from $43.57 per barrel in the same period in 2004. The increase in natural gas production volume was principally due to production from new wells in the Barnett Shale, Encinitas Project and the Peters Ranch areas. These volumes increases were partially offset by: (1) production declines from the Beach House #1 and Louisiana Delta Farms #1, which were shut-in for workovers during the second and third quarters of this year, (2) the temporary shut-in of a number of wells as a result of the Katrina and Rita hurricanes and (3) the sale of the Shadyside #1 in the first quarter of 2005. The decrease in oil production volume was principally due to production declines from the Beach House #1 and Louisiana Delta Farms #1. Oil and natural gas revenues include the impact of hedging activities as discussed above under “General Overview.”

The results for the 2005 period were affected by well shut-ins due to hurricanes Katrina and Rita and selected workovers, as described in “General Overview - Recent Developments.” The following table summarizes production volumes, average sales prices and operating revenues for our oil and natural gas operations for the three months ended September 30, 2004 and 2005:

					2005 Period
					Compared to 2004 Period
	September 30				Increase			% Increase
	2004		2005		(Decrease)			(Decrease)
Production volumes -
Oil and condensate (MBbls)		73		53		(20	)		(27	)%
Natural gas (MMcf)		1,602		1,858		256			16	%
Average sales prices - (1)
Oil and condensate (per Bbls)	$	43.57	$	62.84	$	19.27			44	%
Natural gas (per Mcf)		5.69		7.65		1.96			34	%
Operating revenues (In thousands)-
Oil and condensate	$	3,164	$	3,353	$	189			6	%
Natural gas		9,110		14,221		5,111			56	%
Total Operating Revenues	$	12,274	$	17,574	$	5,300			43	%

__________________

(1) Includes impact of hedging activities.

Oil and natural gas operating expenses for the three months ended September 30, 2005 increased 5% to $2.2 million from $2.1 million for the same period in 2004 primarily as a result of higher severance taxes related to increased revenues and higher lifting costs for new wells added in 2005. Operating expenses per equivalent unit decreased slightly to $1.03 per Mcfe in the third quarter of 2005 compared to $1.04 per Mcfe in the same period in 2004.

Depreciation, depletion and amortization (DD&A) expense for the three months ended September 30, 2005 increased 27% to $4.7 million ($2.16 per Mcfe) from $3.7 million ($1.82 per Mcfe) for the same period in 2004. 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, 2005 increased by $0.6 million to $1.9 million from $1.3 million for the same period in 2004 primarily as a result of higher salary and incentive compensation costs as a result of (1) increased staff and (2) annual salary raises and incentive bonuses.

Stock-based compensation expense increased to $1.9 million in the third quarter of 2005 from a $0.1 million benefit for the same period in 2004. The expense is recorded primarily from options to purchase our common stock that were repriced in 2000 which fluctuate in value with the market value of our common stock.

We incurred a $3.7 million loss in connection with the early retirement of the Senior Subordinated Notes and Senior Secured Notes in July 2005. The loss principally consisted of unamortized discount and deferred loan costs written-off on the repayment of the notes.

We recorded a $0.4 million after tax charge, or $0.02 per fully diluted share, on our equity interest in Pinnacle for the three months ended September 30, 2005. It is likely that Pinnacle will continue to record a valuation allowance on the deferred federal tax benefit generated from the operating losses incurred during at least the early development stages of Pinnacle’s coalbed methane projects. We

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have not recorded a deferred federal income tax benefit generated from these operating losses due to the uncertainty of future Pinnacle taxable income.

Capitalized interest increased to $1.7 million in the third quarter of 2005 from $0.8 million for the third quarter of 2004 as a result of the increased weighted average interest rate related to the Company entering into the Second Lien Credit Facility in July 2005 and due to the higher unproved property balance.

Income taxes decreased to $0.6 million for the three months ended September 30, 2005 from $2.1 million for the same period in 2004 as a result of lower taxable income based on the factors described above.

Net income available to common shareholders for the three months ended September 30, 2005 decreased by $2.8 million to $0.6 million for the third quarter of 2005 from $ 3.4 million for the same period in 2004 as a result of the factors described above.

Nine Months Ended September 30, 2005,

Compared to the Nine Months Ended September 30, 2004

Oil and natural gas revenues for the nine months ended September 30, 2005 increased 41% to $49.4 million from $35.1 million for the same period in 2004. Production volumes for natural gas during the nine months ended September 30, 2005 increased 31% to 5.8 Bcf from 4.4 Bcf for the same period in 2004. Average natural gas prices increased 15% to $6.78 per Mcf in the first nine months of 2005 from $5.89 per Mcf in the same period in 2004. Production volumes for oil in the first nine months of 2005 decreased 27% to 178 MBbls from 243 MBbls for the same period in 2004. Average oil prices increased 50% to $55.79 per barrel for the first nine months of 2005 from $37.14 per barrel in the same period in 2004. The increase in natural gas production volume was principally due to production from new wells in the Barnett Shale, Encinitas Project and Peters Ranch areas and due to initial production from the LL&E #1. The gas production volume increases were partially offset by: (1) production declines from the Delta Farms #1 and the Beach House #1 wells, which were shut-in for workovers during the second and third quarters of this year; (2) the temporary shut-in of a number of wells as a result of the Katrina and Rita hurricanes; and (3) the sale of the Shadyside #1 in the first quarter of 2005. The decrease in oil production volume was principally due to production declines from the aforementioned workovers, the hurricane related shut-ins, and a natural production decline for the Hankamer #1. 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 our oil and natural gas operations for the nine months ended September 30, 2004 and 2005:

					2005 Period
					Compared to 2004 Period
	September 30,				Increase			% Increase
	2004		2005		(Decrease)			(Decrease)
Production volumes -
Oil and condensate (MBbls)		243		178		(65	)		(27	)%
Natural gas (MMcf)		4,427		5,807		1,380			31	%
Average sales prices - (1)
Oil and condensate (per Bbls)	$	37.14	$	55.79	$	18.65			50	%
Natural gas (per Mcf)		5.89		6.78		0.89			15	%
Operating revenues (In thousands)-
Oil and condensate	$	9,031	$	9,957	$	926			10	%
Natural gas		26,076		39,396		13,320			34	%
Total Operating Revenues	$	35,107	$	49,353	$	14,246			41	%

__________________

(1) Includes impact of hedging activities.

Oil and natural gas operating expenses for the nine months ended September 30, 2005 increased to $7.1 million from $5.8 million for the same period in 2004 primarily as a result of higher severance taxes related to increased revenues and higher lifting costs for new wells added in 2005. Operating expenses per equivalent unit increased to $1.03 per Mcfe in the first nine months of 2005 compared to $0.99 per Mcfe in the same period in 2004.

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Depreciation, depletion and amortization (DD&A) expense for the nine months ended September 30, 2005 increased 36% to $14.4 million ($2.09 per Mcfe) from $10.6 million ($1.79 per Mcfe) for the same period in 2004. DD&A increased primarily due to increased production and expenses resulting from additional seismic and drilling costs.

General and administrative expense for the nine months ended September 30, 2005 increased by $1.1 million to $6.2 million from $5.1 million for the same period in 2004 primarily as a result of higher salary and incentive compensation costs as a result of (1) increased staff and (2) annual salary raises and incentive bonuses.

Stock based compensation expense was $2.9 million for the nine months ended September 30, 2005 compared to $0.6 million for the nine months ended September 30, 2004. The expense is derived primarily from options to purchase our common stock that were repriced in 2000, which fluctuate in value with the market value of our common stock.

We incurred a $3.7 million loss in connection with the early retirement of the Senior Subordinated Notes and Senior Secured Notes in July 2005. The loss principally consisted of unamortized discount and deferred costs written-off on the repayment of the notes.

We recorded a $1.0 million after tax charge, or $0.04 per fully diluted share, on our minority interest in Pinnacle for the nine months ended September 30, 2005. It is likely that Pinnacle will continue to record a valuation allowance on the deferred federal tax benefit generated from the operating losses incurred during at least the early development stages of Pinnacle’s coalbed methane projects. We have not recorded a deferred federal income tax benefit generated from these operating losses due to the uncertainty of future Pinnacle taxable income.

Capitalized interest increased to $3.9 million in the first nine months of 2005 from $2.1 million for the same period of 2004 as a result of the increased weighted average interest rate related to entering into the Second Lien Credit Facility and the higher unproved property balance.

Income taxes decreased to $4.5 million for the nine months ended September 30, 2004 from $4.8 million for the same period in 2004 as a result of lower taxable income.

Dividends and accretion of discount on preferred stock decreased to zero from $0.4 million in the first nine months of 2004 as the result of the conversion of all of the Series B Preferred Stock into common stock during the second quarter of 2004.

Net income available to common shareholders for the nine months ended September 30, 2005 decreased by $0.6 million to $6.8 million from $7.4 million for the same period in 2004 primarily as a result of the factors described above.

Liquidity and Capital Resources

During the nine months ended September 30, 2005, we made capital expenditures in excess of our net cash flows provided by operating activities, using the proceeds of $9.0 million from the sale of certain oil and natural gas properties (see “General Overview - Recent Developments” for further discussion of this property sale), $2.3 million of proceeds from the exercise of warrants and stock options, $17.2 million of net proceeds from the Private Placement and $3.6 million in net proceeds from the issuance of additional Senior Secured Notes. For future capital expenditures in 2005, we expect to use cash on hand, largely generated from the Second Lien Credit Facility and cash generated by operating activities and available draws on the First Lien Credit Facility to partially fund our planned drilling expenditures and fund leasehold costs and geological and geophysical costs on our exploration projects in 2005.

We may not be able to obtain financing as may be needed in the future on terms that would be acceptable to us. If we cannot obtain adequate financing, we anticipate that we may be required to limit or defer our planned oil and natural gas exploration and development program, thereby adversely affecting the recoverability and ultimate value of our oil and natural gas properties.

Our liquidity position was enhanced by our receipt of approximately $23.4 million in net proceeds from the completion of the 2004 public offering, the increases in availability of funds under the First Lien Credit Facility before entering into the Second Lien Credit Facility, the proceeds from the October 2004 sale of the Senior Secured Notes and, more recently, the $144.5 million net proceeds from the Second Lien Credit Facility, our $17.2 million Private Placement and the $9.0 million of net proceeds from the aforementioned property sale in February 2005. Our primary sources of future liquidity include funds generated by operations, proceeds from the issuance of various securities, including our common stock, preferred stock and warrants, and borrowings available under the First Lien Credit Facility.

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Cash flows provided by operating activities were $19.4 million and $18.8 million for the nine months ended September 30, 2004 and 2005, respectively. The decrease was primarily due to a change in working capital components and higher interest costs.

We have planned capital expenditures in 2005 of approximately $130.0 million to $135.0 million, of which $90.0 million is expected to be used for drilling activities in our project areas and the balance is expected to be used to fund 3-D seismic surveys and land acquisitions and capitalized interest and overhead costs. We plan to drill approximately 26 gross wells (10.2 net) in the onshore Gulf Coast area and 45 gross wells (28.5 net) in our Barnett Shale area and nine gross wells (9.0 net) in our East Texas areas in 2005. As described above, we completed our Second Lien Credit Facility financing to fund a portion of our acquisition, exploration and development program in 2005. The actual number of wells drilled and capital expended is dependent upon our available financing, cash flow, availability and cost of drilling rigs, land and partner issues and other factors.

We have continued to reinvest a substantial portion of our cash flows into increasing our 3-D prospect portfolio, improving our 3-D seismic interpretation technology and funding our drilling program. Oil and natural gas capital expenditures were $59.0 million (including our $8.2 million Barnett Shale acquisition) and $86.9 million (reduced by $11.8 million of proceeds from the aforementioned property sale and a seismic participation) for the nine months ended September 30, 2004 and 2005, respectively.

In September 2005, we entered into an agreement to purchase over an 18 month period a non-exclusive license to certain geophysical data at a cost which will range from $2.0 million to $2.5 million, contingent upon whether we exercise another option to acquire additional data under the agreement.

Our drilling efforts in the Gulf Coast region resulted in apparent successes in drilling 12 gross wells (4.6 net) during the nine months ended September 30, 2005. In our Barnett Shale area, we had apparent successes in drilling 29 gross wells (17.3 net) during the first nine months of 2005, and in our East Texas area, we had apparent successes in drilling eight gross wells (7.6 net) during that period. We have completed 26 of these wells and were in the process of completing 23 of these wells as of September 30, 2005.

Our Board of Directors recently approved a revised development plan for increased drilling activity in two tracts in the Camp Hill field in our East Texas area. During 2005, we have drilled seven gross wells (7.0 net) in this area, all of which are apparent successes. Over the next 18 months, we expect to drill between 55 and 60 gross wells (55 to 60 net) in this area at an estimated cost of approximately $4.2 million.

Through the end of the nine months of 2005, Pinnacle has reported that it has drilled 351 gross wells since inception and estimates that 93% of these wells have been completed. By 2004 year end, Pinnacle had completed the acquisition and/or drilling of 487 wells (or approximately 276 net). Of those wells, 484 encountered coal accumulations. Coalbed methane wells typically first produce water in a process called dewatering and then, as the water production declines, begin producing methane gas at an increasing rate. As the wells mature, the production peaks and begins declining.

As of August 31, 2005, of the 345 wells drilled by Pinnacle, (1) 256 are producing gas; (2) 18 remain in the completion/hook-up phase; (3) 46 are in the dewatering phase with no early indication as to gas production; (4) 22 are waiting on or being evaluated for workovers or redrill or plugging and abandonment; and (5) three of these wells did encounter coal accumulations.

As of August 31, 2005, of the 241 wells that Pinnacle had acquired, (1) 71 are producing gas, (2) 108 remain in the completion/hook-up phase; (3) 27 are in the dewatering phase with no early indication as to gas production; (4) 12 are waiting on or being evaluated for workovers or redrill or plugging and abandonment; (5) 18 that are producing gas at uneconomic rates are currently shut in; and (6) five have been plugged and abandoned.

The dewatering process may require significant time and resources, and there can be no assurance that a well that encounters coal accumulations will in fact produce gas in commercial quantities. The ultimate commercial success of the well will depend upon several factors, including the establishment of gas and/or water inflow, the presence of pipelines and infrastructure, the satisfaction of engineering or production issues and other risks and uncertainties associated with drilling activities.

Pinnacle reportedly added approximately 16.7 Bcfe of net proved reserves through development drilling through September 30, 2005, excluding the 10.4 Bcfe contributed or acquired at inception. Its gross operated production has increased by approximately 230% since its inception (to approximately 15.8 MMcf/d at September 30, 2005), and its total well count stands at 592 gross operated wells, according to Pinnacle. Because of the nature of coalbed methane wells that require an extended dewatering period before significant natural gas production, Pinnacle has not been able to complete its determination on commerciality of all of these wells.

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Financing Arrangements

First Lien Credit Facility

On September 30, 2004, we entered into a Second Amended and Restated Credit Agreement with Hibernia National Bank and Union Bank of California, N.A. (the “First Lien Credit Facility”), maturing on September 30, 2007. The First Lien Credit Facility provides for (1) a revolving line of credit of up to the lesser of the Facility A Borrowing Base and $75.0 million and (2) a term loan facility of up to the lesser of the Facility B Borrowing Base and $25.0 million (subject to the limit of the borrowing base, which is currently $20.0 million). It is secured by substantially all of our assets and is guaranteed by our subsidiary. The First Lien Credit Facility was amended on July 21, 2005 in connection with our new Second Lien Credit Facility and refinancing discussed in detail below.

The Facility A Borrowing Bases is scheduled to be redetermined by the lenders each quarter. In connection with our scheduled May 2005 borrowing base redetermination, our prior borrowing base of $33.0 million was increased to $39.0 million, effective June 30, 2005 through July 21, 2005. This borrowing base included the impact of the aforementioned workovers completed on the Delta Farms #1 and Beach House #1 wells. The Facility A Borrowing Base, under the First Lien Credit Facility, on December 31, 2004 and September 30, 2005 was $30.0 million and $20.0 million, respectively, of which $18.0 and zero, respectively, were drawn and outstanding. In connection with entering into the Second Lien Credit Facility, effective July 21, 2005, we elected to set our borrowing base at $10.0 million commensurate with our financing needs in the near term but $10.0 million below the $20.0 million borrowing base availability approved by the lenders.

The Facility A Borrowing Base will at all times equal the Facility A Borrowing Base most recently determined by the lenders, less quarterly borrowing base reductions required subsequent to such determination. The lenders will reset the Facility A Borrowing Base amount at each borrowing base determination date.

If the outstanding principal balance of the revolving loans under the First Lien Credit Facility exceeds the Facility A Borrowing Base at any time (including, without limitation, due to a borrowing base reduction ), we have the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, pledge additional collateral sufficient in the lenders' opinion to increase the Facility A Borrowing Base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Those payments would be in addition to any payments that may come due as a result of a borrowing base reduction. Otherwise, any unpaid principal or interest will be due at maturity.

For each revolving loan, the interest rate will be, at our option, (1) the eurodollar rate, plus an applicable margin equal to 2.375% if the amount borrowed is greater than or equal to 90% of the Facility A Borrowing Base, 2.0% if the amount borrowed is less than 90%, but greater than or equal to 50% of the Facility A Borrowing Base, or 1.625% if the amount borrowed is less than 50% of the Facility A Borrowing Base; or (2) the Base Rate, plus an applicable margin of 0.375% if the amount borrowed is greater than or equal to 90% of the Facility A Borrowing Base. The interest rate on each term loan will be, at our option, (1) the eurodollar rate, plus an applicable margin to be determined by the lenders; or (2) the Base Rate, plus an applicable margin to be determined by the lenders. 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.

Before the July 21, 2005 amendment, noted below, we were subject to certain covenants under the terms of the First Lien Credit Facility. These covenants, as amended, include, but are not limited to the maintenance of the following financial covenants: (1) a minimum current ratio of 1.0 to 1.0 (including availability under the borrowing base), (2) a minimum quarterly debt services coverage of 1.25 times, (3) a minimum shareholders’ equity equal to $108.8 million, plus 100% of all subsequent common and preferred equity contributed by shareholders subsequent to December 31, 2004, plus 50% of all positive earnings occurring subsequent to December 31, 2004, and (4) a maximum total recourse debt to EBITDA ratio (as defined in the First Lien Credit Facility) of not more than 3.0 to 1.0. These covenants were amended as described below in connection with the July 2005 amendment of the First Lien Credit Facility. The First Lien Credit Facility also places restrictions on additional indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, asset pledges and mortgages, change of control, repurchase or redemption for cash of our common stock, speculative commodity transactions and other matters.

On April 27, 2005 we amended the First Lien Credit Facility to, among other things, add a provision restricting loans from us to our subsidiaries or guarantors of the First Lien Credit Facility if the proceeds of such loans will be invested in an entity in which we hold an equity interest.

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In connection with entering into the Second Lien Credit Facility, we amended our First Lien Credit Facility on July 21, 2005. Such amendment included without limitation: (1) an adjustment to the maximum total net recourse debt to EBITDA (as defined in the First Lien Credit Facility) ratio, such that the maximum is 3.5 to 1.0 through September 30, 2006, 3.25 to 1.0 through December 31, 2006 and 3.0 to 1.0 thereafter; (2) an adjustment to the covenant regarding maintenance of a minimum shareholders’ equity, such that the quarterly minimum is $115.0 million plus 100% of all subsequent common and preferred equity contributed by shareholders subsequent to March 31, 2005, plus 50% of all positive earnings occurring subsequent to March 31, 2005; (3) an adjustment to the covenant regarding maintenance of a minimum EBITDA to interest expense ratio, such that the minimum is 2.75 to 1.0 through September 30, 2006 and 3.0 to 1.0 thereafter; and (4) the addition of other provisions and a consent which permits the indebtedness incurred and the liens granted under the Second Lien Credit Facility.

The Facility A Borrowing Base, under the First Lien Credit Facility, as of December 31, 2004 and September 30, 2005 was $30.0 million and $20.0 million, respectively. In connection with entering into the Second Lien Credit Facility, effective July 21, 2005, and until the September 30, 2005 redetermination, we elected to set our borrowing base at $10.0 million commensurate with our financing needs in the near term but $10.0 million below the $20.0 million borrowing base availability approved by the lenders.

At December 31, 2004, amounts outstanding under the First Lien Credit Facility totaled $18.0 million with an additional $12.0 million available for future borrowings. At September 30, 2005, there were no amounts outstanding under the First Lien Credit Facility. At December 31, 2004 and September 30, 2005, no letters of credit were issued and outstanding under the First Lien Credit Facility.

Second Lien Credit Facility and Refinancing

On July 21, 2005, we entered into a second lien credit agreement with Credit Suisse, as administrative agent and collateral agent (the “Agent”) and the lenders party thereto (the “Second Lien Credit Facility”) that matures on July 21, 2010. The Second Lien Credit Facility provides for a term loan facility in an aggregate principal amount of $150.0 million. It is secured by substantially all of our assets and is guaranteed by our subsidiary. The liens securing the Second Lien Credit Facility are second in priority to the liens securing the First Lien Credit Facility, as more fully described in an intercreditor agreement dated July 21, 2005 among us, the Agent, the agent under the First Lien Credit Facility and the lenders.

The net proceeds from the Second Lien Credit Facility, after arrangement and legal fees, were approximately $144.5 million. A portion of the net proceeds were used to: (1) retire the $52.9 million of outstanding obligations under the Subordinated Notes and the Senior Secured Notes and (2) repay, at our election, the $18.5 million outstanding indebtedness under the First Lien Credit Facility. We expect to continue to maintain the First Lien Credit Facility, currently with a $10.0 million undrawn borrowing base. We intend to use the remaining $73.1 million of net proceeds from the Second Lien Credit Facility to partially fund our ongoing capital expenditure program, including our drilling programs in the Barnett Shale and onshore Gulf Coast areas, and for general corporate purposes. In connection with these transactions, we recorded a $3.7 million pre-tax charge for the early extinguishment of long-term debt in the third quarter of 2005 primarily relating to the write off of unamortized discounts and deferred loan costs.

The interest rate on each base rate loan will be (1) the greater of the Agent’s prime rate and the federal funds effective rate plus 0.5%, plus (2) a margin of 5.0%. The interest rate on each eurodollar loan will be the adjusted LIBOR rate plus a margin of 6.0%. Interest on eurodollar loans is payable on either the last day of each interest period or every three months, whichever is earlier. Interest on base rate loans is payable quarterly.

Before the July 21, 2005 amendment noted below, we were subject to certain covenants under the terms of the Second Lien Credit Facility. These covenants include, but are not limited to, the maintenance of the following financial covenants: (1) a minimum current ratio of 1.0 to 1.0 including availability under the borrowing base under the First Lien Credit Facility; (2) a minimum quarterly interest coverage ratio of 2.75 to 1.0 through June 30, 2006 and 3.0 to 1.0 thereafter; (3) a minimum quarterly proved reserve coverage ratio of 1.5 to 1.0 through September 30, 2006 and 2.0 to 1.0 thereafter; and (4) a maximum total net recourse debt to EBITDA (as defined in the Second Lien Credit Facility) ratio of not more than 3.5 to 1.0 through June 30, 2006 and 3.25 to 1.0 thereafter. The Second Lien Credit Facility also places restrictions on additional indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, speculative commodity transactions, transactions with affiliates and other matters.

The Second Lien Credit Facility is subject to customary events of default. Subject to certain exceptions, if an event of default occurs and is continuing, the Agent may accelerate amounts due under the Second Lien Credit Facility (except for a bankruptcy event of default, in which case such amounts will automatically become due and payable). If an event of default occurs under the Second Lien Credit Facility as a result of an event of default under the First Lien Credit Facility, the Agent may not accelerate the amounts due

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under the Second Lien Credit Facility until the earlier of 45 days after the occurrence of the event resulting in the default and acceleration of the loans under the First Lien Credit Facility.

Rocky Mountain Gas Note

In June 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. All of these amounts have been paid. The RMG note was secured solely by CCBM’s interests in the oil and natural gas leases in Wyoming and Montana. In connection with our investment in Pinnacle, we 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. In the second quarter of 2004, we opted to exercise our right to cancel one-half of the remaining note payable to RMG, or approximately $0.3 million, in exchange for assigning one-half of our mineral interest in the Oyster Ridge leases to RMG.

Capital Leases

In December 2001, we 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, we 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, we 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, we 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. We have the option to acquire the equipment at the conclusion of the lease for $1 under all of these leases. Depreciation on the capital leases for the three months ended September 30, 2004 and 2005 amounted to $11,000 and $10,000, respectively. Depreciation on the capital leases for the nine months ended September 30, 2004 and 2005 amounted to $34,000 and $32,000, respectively, and accumulated depreciation on the leased equipment at December 31, 2004 and September 30, 2005 amounted to $124,000 and $156,000, respectively.

Senior Subordinated Notes and Related Securities

In December 1999, we 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. We 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 our 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 (23A SBIC), L.P.), 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. As amended and described below, the Subordinated Notes allow us, by annual election and we have historically elected, to increase the amount of the Subordinated Notes by 60% of the interest which would otherwise be payable in cash through December 15, 2006. As a result, our cash obligation on the Subordinated Notes will increase significantly after December 2006. As of December 31, 2004 and the July 21, 2005 retirement date, the outstanding balance of the Subordinated Notes had been increased by $6.8 million and $7.6 million, respectively, for such interest paid in kind. Concurrently with the sale of the Subordinated Notes, we sold to the original purchasers 3,636,634 shares of our common stock at a price of $2.20 per share and warrants expiring in December 2007 to purchase up to 2,760,189 shares of our common stock at an exercise price of $2.20 per share. For accounting purposes, the warrants were valued at $0.25 each.

In 2004, Mellon Ventures, L.P., JPMorgan Partners (23A SBIC), Steven A. Webster and Douglas A. P. Hamilton exercised warrants to purchase 276,019, 2,208,152, 92,006 and 92,006 shares of common stock, respectively, on a cashless exercise basis for a total of 205,692, 1,684,949, 70,205 and 70,205 shares of common stock, respectively, and Paul B. Loyd, Jr., exercised warrants to purchase 92,006 shares for a total of 92,006 shares of common stock. As a result, no warrants to purchase shares remain outstanding from the warrants originally issued in December 1999.

On June 7, 2004, an unaffiliated third party (the “Subordinated Notes Purchaser”) purchased all the outstanding Subordinated Notes from the original note holders. In exchange for a $0.4 million amendment fee, certain terms and conditions of the Subordinated Notes were amended, to provide for, among other things, (1) a one year extension of the maturity to December 15, 2008, (2) a one year extension, through December 15, 2005, of the paid-in-kind (“PIK”) interest option to pay-in-kind 60% of the interest due each period by increasing the principal balance by a like amount (the “PIK option”), (3) an additional one year option to extend the PIK option

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through December 15, 2006 at an annual interest rate on the deferred amount of 10% and the payment of a one-time fee equal to 0.5% of the principal then outstanding, (4) an increase and extension on the prepayment premium on the Subordinated Notes, (5) a modification of a covenant regarding maximum quarterly leverage that our Total Debt will not exceed 3.5 times EBITDA (as such terms are defined in the securities purchase agreement related to the Subordinated Notes) for the last 12 months at any time and (6) additional flexibility to obtain a separate project financing facility in the future. The amendment fee was amortized over the remaining life of the Subordinated Notes using the effective interest method.

We were subject to certain other covenants under the terms under 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, (c) a limitation of our capital expenditures to an amount equal to our EBITDA for the immediately prior fiscal year (unless approved by our Board of Directors) and (d) a limitation on our Total Debt (as defined in the securities purchase agreement related to the Subordinated Notes) to 3.5 times EBITDA for any twelve month period.

On July 21, 2005, the Subordinated Notes were repaid in full in connection with entering into the Second Lien Credit Facility. See “Financing Arrangements − Second Lien Credit Facility and Refinancing.”

Senior Secured Subordinated Notes

On October 29, 2004, we entered into a Note Purchase Agreement (the “Senior Secured Notes Purchase Agreement”) with PCRL Investments L.P. (the “Senior Secured Notes Purchaser”). Pursuant to the Senior Secured Notes Purchase Agreement, we could issue up to $28 million aggregate principal amount of our 10% Senior Secured Subordinated Notes due 2008 (the “Senior Secured Notes”) for a purchase price equal to 90% of the principal amount of the Senior Secured Notes then issued. On October 29, 2004 and May 31, 2005, the Senior Secured Notes Purchaser purchased $18.0 million and $4.0 million aggregate principal amount of the Senior Secured Notes for a purchase price of $16.2 million and $3.6 million, respectively. The debt discounts were amortized to interest expense using the effective interest method over the life of the notes.

The Senior Secured Notes were secured by a second lien on substantially all of our current proved producing reserves and non-reserve assets, guaranteed by our subsidiary, and subordinated to our obligations under the Credit Facility. The Senior Secured Notes bore interest at 10% per annum, payable quarterly on the 5th day of March, June, September and December of each year beginning March 5, 2005. The principal on the Senior Secured Notes was due December 15, 2008, and we had the option to prepay the Senior Secured Notes at any time. The Senior Secured Notes included an option that allows us to pay-in-kind 50% of the interest due until June 5, 2007 by increasing the principal due by a like amount. As of the July 21, 2005 retirement date, the outstanding balance of the Senior Secured Notes had been increased by $0.5 million for such interest paid-in-kind. Subject to certain conditions, we had the option to pay the interest on and principal of (at maturity or upon prepayment) the Senior Secured Notes with our common stock, as long as the Secured Note Purchaser would not hold more than 9.99% of the number of shares of our common stock outstanding immediately after giving effect to such payment. The value of such shares issued as payment on the Senior Secured Notes was determined based on 90% of the volume weighted average trading price during a specified period of days beginning with the date of the payment notice and ending before the payment date. Our issuance costs in aggregate related to the transactions were $0.5 million and were amortized over the life of the Senior Secured Notes using the effective interest method.

As contemplated by the Senior Secured Notes Purchase Agreement, we also entered into a registration rights agreement with the Senior Secured Note Purchaser (the “Registration Rights Agreement”). In the event that we chose to issue shares of our common stock as payment of interest on the principal of the Senior Secured Notes, the Registration Rights Agreement provides registration rights with respect to such shares. We were generally required to file a resale shelf registration statement to register the resale of such shares under the Securities Act of 1933 (the “Securities Act”) if such shares are not freely tradable under Rule 144(k) under the Securities Act. We were subject to certain covenants under the terms of the Registration Rights Agreement, including the requirement that the registration statement be kept effective for resale of shares subject to certain “blackout periods,” when sales may not be made. In certain circumstances, including those relating to (1) delisting of our common stock, (2) blackout periods in excess of a maximum length of time, (3) certain failures to make timely periodic filings with the Securities and Exchange Commission, or (4) certain delays or failures to deliver stock certificates, we may be required to repurchase common stock issued as payment on the Senior Secured Notes and, in certain of these circumstances, to pay damages based on the market value of our common stock. In certain situations, we are required to indemnify the holders of registration rights under the Registration Rights Agreement, including, without limitation, for liabilities under the Securities Act.

The Senior Secured Notes Purchase Agreement included certain representations, warranties and covenants by the parties thereto. We were subject to certain covenants under the terms of the Senior Secured Notes Purchase Agreement, including, without limitation, the

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maintenance of the following financial covenants: (1) a maximum total recourse debt to EBITDA ratio of not more than 3.50 to 1.0, (2) a minimum EBITDA to interest expense ratio of 2.50 to 1.0, and (3) as of April 30, 2005, a minimum tangible net worth of $12.5 million in excess of our tangible net worth as of September 30, 2004. Upon a change of control, any holders of the Senior Secured Notes could require us to repurchase such holders' Senior Secured Notes at a price equal to the then outstanding principal amount of such Senior Secured Notes, together with all interest accrued on such Senior Secured Notes through the date of repurchase. The Senior Secured Notes Purchase Agreement also places restrictions on additional indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, asset pledges and mortgages, repurchase or redemption for cash of our common stock, speculative commodity transactions and other matters. The Senior Secured Notes Purchaser is an affiliate of the Subordinated Notes Purchaser.

On July 21, 2005, the Senior Secured Notes were repaid in full in connection with entering into the Second Lien Credit Facility. See “Financing Arrangements − Second Lien Credit Facility and Refinancing.”

Series B Preferred Stock

In February 2002, we 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. We 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 was convertible into common stock by the investors at a conversion price of $5.70 per share, subject to adjustment for transactions including issuance of common stock or securities convertible into or exercisable for common stock at less than the conversion price, and is initially convertible into 1,052,632 shares of common stock. The approximate $5.8 million of net proceeds from this financing were used to fund our ongoing exploration and development program and general corporate purposes. In the first quarter of 2004, Mellon Ventures exercised all 168,422 of its 2002 Warrants on a cashless basis and received 36,570 shares which were sold in the 2004 public offering.

Mellon Ventures, Inc. converted all of its Series B Preferred Stock (approximately 49,938 shares) into 876,099 shares of common stock on May 25, 2004. Steven A. Webster converted all of his Series B Preferred Stock (approximately 25,195 shares) into 442,026 shares of common stock on June 30, 2004. As a result, no shares of Series B Preferred Stock remain outstanding.

The 2002 Warrants had a five-year term and entitled 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 were exercisable at any time after issuance. The 2002 Warrants were exercisable on a cashless exercise basis. During 2004 Mellon Ventures, Inc. exercised all of its 168,422 2002 Warrants on a cashless exercise basis for a total of 36,570 shares of common stock and during the first quarter of 2005 Mr. Webster exercised all of his 84,210 2002 Warrants on a cashless basis for a total of 54,669 shares of common stock.

Effects of Inflation and Changes in Price

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

Recently Issued Accounting Pronouncements

On December 16, 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123(R)”). SFAS No. 123(R) will require companies to measure all employee stock-based compensation awards using a fair value method and record such expense in their consolidated financial statements. In addition, the adoption of SFAS No. 123(R) requires additional accounting and disclosure related to the income tax and cash flow effects resulting from share-based payment arrangements. SFAS No. 123(R) was effective beginning as of the first interim or annual reporting period beginning after June 15, 2005. On April 14, 2005, the SEC recently adopted a new rule that defers the effective date of SFAS No. 123(R) and allows companies to implement the provisions of SFAS No. 123(R) at the beginning of their next fiscal year. We will adopt the provisions of SFAS No. 123(R) during the first quarter of 2006 using the modified prospective method for transition. We believe it is likely that the impact of the requirements of SFAS No. 123(R) will significantly impact our future results of operations and continue to evaluate it to determine the degree of significance.

Critical Accounting Policies

The following summarizes several of our critical accounting policies:

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Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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. The use of these estimates significantly affects our natural gas and oil properties through depletion and the full cost ceiling test, as discussed in more detail below.

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of undeveloped properties, future income taxes and related assets/liabilities, bad debts, derivatives, contingencies and litigation. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

The significant estimates are based on current assumptions that may be materially effected by changes to future economic conditions such as the market prices received for sales of volumes of oil and natural gas, interest rates, the market value of our common stock and corresponding volatility and our ability to generate future taxable income. Future changes to these assumptions may affect these significant estimates materially in the near term.

Oil and Natural Gas Properties

We account for investments in natural gas and oil properties using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of natural gas and oil properties are capitalized. These costs include lease acquisitions, seismic surveys, and drilling and completion equipment. We proportionally consolidate our interests in natural gas and oil properties. We capitalized compensation costs for employees working directly on exploration activities of $1.3 million and $1.5 million for the nine months ended September 30, 2004 and 2005, respectively. We expense maintenance and repairs as they are incurred.

We amortize natural gas and oil properties based on the unit-of-production method using estimates of proved reserve quantities. We do not amortize investments in unproved properties until proved reserves associated with the projects can be determined or until these investments are impaired. We periodically evaluate, on a property-by-property basis, unevaluated properties for impairment. If the results of an assessment indicate that the properties are impaired, we add the amount of impairment to the proved natural gas and oil 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 Mcfe for the nine months ended September 30, 2004 and 2005 was $1.79 and $2.09, respectively.

We account for dispositions of natural gas and oil 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. We have not had any transactions that significantly alter that relationship.

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, based on current economic and operating conditions (the “Full Cost Ceiling”). If net capitalized costs exceed this limit, the excess is charged to operations through depreciation, depletion and amortization.

In mid-March 2004, during the year-end close of our 2003 financial statements, it was determined that there was a computational error in the ceiling test calculation which overstated the tax basis used in the computation to derive our after-tax present value (discounted at 10%) of future net revenues from proved reserves. We further determined that this tax basis error was also present in each of our previous ceiling test computations dating back to 1997. This error only affected our after-tax computation, used in the ceiling test calculation and the unaudited supplemental oil and natural gas disclosure, and did not impact our: (1) pre-tax valuation of the present value (discounted at 10%) of future net revenues from proved reserves, (2) our proved reserve volumes, (3) our EBITDA or our future cash flows from operations, (4) our net deferred tax liability, (5) our estimated tax basis in oil and natural gas properties, or (6) our estimated tax net operating losses.

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After discovering this computational error, the ceiling tests for all quarters since 1997 were recomputed and it was determined that no write-down of our oil and natural gas assets was necessary in any of the years from 1997 to 2003. However, based upon the oil and natural gas prices in effect on March 31, 2003 and September 30, 2003, the unamortized cost of oil and natural gas properties exceeded the cost center ceiling. As permitted by full cost accounting rules, improvements in pricing and/or the addition of proved reserves subsequent to those dates sufficiently increased the present value of our oil and natural gas assets and removed the necessity to record a write-down in these periods. Using the prices in effect and estimated proved reserves existing on March 31, 2003 and September 30, 2003, the after-tax write-down would have been approximately $1.0 million and $6.3 million, respectively, had we not taken into account these subsequent improvements. These improvements at September 30, 2003 included estimated proved reserves attributable to our Shadyside #1 well, which we have since sold in February 2005. Because of the volatility of oil and natural gas prices, no assurance can be given that we will not experience a write-down in future periods. No write-down of our oil and natural gas assets was necessary during the nine months ended September 30, 2005.

In connection with our September 30, 2005 ceiling test computation, a price sensitivity study also indicated that a 20% increase in commodity prices at September 30, 2005 would have increased the pre-tax present value of future net revenues (“NPV”) by approximately $110.5 million. Conversely, a 20% decrease in commodity prices at September 30, 2005 would have reduced our NPV by approximately $110.5 million. The aforementioned price sensitivity and NPV is as of September 30, 2005 and, accordingly, does not include any potential changes in reserves due to fourth quarter 2005 performance, such as commodity prices, reserve revisions and drilling results.

The Full Cost Ceiling cushion at the end of September 2005 of approximately $171.0 million was based upon average realized oil and natural gas prices of $63.30 per Bbl and $10.72 per Mcf, respectively, or a volume weighted average price of $63.89 per BOE. This cushion, however, would have been zero on such date at an estimated volume weighted average price of $33.79 per BOE. A BOE means one barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids, which approximates the relative energy content of oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher, more often for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.

Under the full cost method of accounting, the depletion rate is the current period production as a percentage of the total proved reserves. Total proved reserves include both proved developed and proved undeveloped reserves. The depletion rate is applied to the net book value plus estimated future development costs to calculate the depletion expense.

We have a significant amount of proved undeveloped reserves, which are primarily oil reserves. We had 72.5 Bcfe and, based on internal estimates, 84.6 Bcfe of proved undeveloped reserves, representing 65% and 67% of our total proved reserves at December 31, 2004 and September 30, 2005, respectively. As of December 31, 2004 and September 30, 2005, a large portion of these proved undeveloped reserves, or approximately 45.7 Bcfe as of both dates, are attributable to our Camp Hill properties that we acquired in 1994. The estimated future development costs to develop our proved undeveloped reserves on our Camp Hill properties are relatively low, on a per Mcfe basis, when compared to the estimated future development costs to develop our proved undeveloped reserves on our other oil and natural gas properties. Furthermore, the average depletable life of our Camp Hill properties is considerably higher, or approximately 15 years, when compared to the depletable life of our remaining oil and natural gas properties of approximately 2.25 years. Accordingly, the combination of a relatively low ratio of future development costs and a relatively long depletable life on our Camp Hill properties has resulted in a relatively low overall historical depletion rate and DD&A expense. This has resulted in a capitalized cost basis associated with producing properties being depleted over a longer period than the associated production and revenue stream. It has also resulted in the build-up of nondepleted capitalized costs associated with properties that have been completely depleted.

We expect our relatively low historical depletion rate to continue until the high level of nonproducing reserves to total proved reserves is reduced and the life of our proved developed reserves is extended through development drilling and/or the significant addition of new proved producing reserves through acquisition or exploration. If our level of total proved reserves, finding cost and current prices were all to remain constant, this continued build-up of capitalized costs increases the probability of a ceiling test write-down.

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

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Oil and Natural Gas Reserve Estimates

The proved reserve data as of December 31, 2004 included in this document are estimates prepared by Ryder Scott Company, DeGolyer and MacNaughton and Fairchild & Wells, Inc., Independent Petroleum Engineers. We estimated the reserve data for all other dates. Reserve engineering is a subjective process of estimating underground accumulations of hydrocarbons that cannot be measured in an exact manner. The process relies on judgment and the interpretation of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires 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 our 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.

You should not assume that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate.

Our rate of recording depreciation, depletion and amortization expense for proved properties depends on our estimate of proved reserves. If these reserve estimates decline, the rate at which we record these expenses will increase. A 10% increase or decrease in our proved reserves would have increased or decreased our depletion expense by 10% for the three months ended September 30, 2005.

As of December 31, 2004, approximately 83% of our proved reserves were proved undeveloped and proved nonproducing. Moreover, some of the producing wells included in our reserve reports as of December 31, 2004 had produced for a relatively short period of time as of that date. Because most of our reserve estimates are calculated using volumetric analysis, those estimates are less reliable than estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure based on seismic analysis. In addition, realization or recognition of our proved undeveloped reserves will depend on our development schedule and plans. Lack of certainty with respect to development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved. We have from time to time chosen to delay development of our proved undeveloped reserves in the Camp Hill Field in East Texas in favor of pursuing shorter-term exploration projects with higher potential rates of return, adding to our lease position in this field and further evaluating additional economic enhancements for this field's development. The average life of the Camp Hill proved undeveloped reserves is approximately 15 years, with 50% of these reserves being booked over 8 years ago. Although we have recently accelerated the pace of the development of the Camp Hill project, there can be no assurance that the aforementioned discontinuance will not occur.

Derivative Instruments and Hedging Activities

Upon entering into a derivative contract, we designate 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 (loss) to the extent that the derivative is effective in offsetting changes in the fair value of the hedged item. Any ineffectiveness in the relationship between the cash flow hedge and the hedged item is recognized currently in income. Gains and losses accumulated in other comprehensive income (loss) associated with the cash flow hedge are recognized in earnings as oil and natural gas revenues when the forecasted transaction occurs. All of our derivative instruments at December 31, 2004 and September 30, 2005 were designated and effective as cash flow hedges.

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.

We typically use fixed rate swaps and costless collars to hedge our exposure to material changes in the price of natural gas and oil. We formally document all relationships between hedging instruments and hedged items, as well as our 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. We also formally assess, 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.

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For a discussion of the impact of changes in the prices of oil and gas on our hedging transactions, see “Volatility of Oil and Natural Gas Prices” below.

We have initiated a program designed to manage our exposure to interest rate fluctuations by entering into financial derivative instruments. The primary objective of this program is to reduce the overall cost of borrowing. We have entered into interest rate swap agreements with respect to amounts borrowed under the Second Lien Credit Facility, designated as fair value hedges, which effectively exchange existing obligations to pay interest based on floating rates for obligations to pay interest based on fixed LIBO rates.

Our Board of Directors sets all of our 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 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. We routinely assess the realizability of our deferred tax assets. We consider future taxable income in making such assessments. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, it is reduced by a valuation allowance. However, despite our attempt to make an accurate estimate, the ultimate utilization of our deferred tax assets is highly dependent upon our actual production and the realization of taxable income in future periods.

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

Our 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 our properties, are substantially dependent upon prevailing prices of oil and natural gas.

We periodically review the carrying value of our oil and natural gas properties under the full cost accounting rules of the Commission. See “—Critical Accounting Policies and Estimates—Oil and Natural Gas Properties.”

Total oil purchased and sold under swaps and collars during the three months ended September 30, 2004 and 2005 was 30,600 Bbls and 27,600 Bbls, respectively. Total natural gas purchased and sold under swaps and collars during the three months ended September 30, 2004 and 2005 was 1,012,000 MMBtu and 966,000 MMBtu, respectively. Total oil hedged under swaps and collars during the nine months ended September 30, 2004 and 2005 were 84,900 Bbls and 99,300 Bbls, respectively. Total natural gas hedged under swaps and collars during the nine months ended September 30, 2004 and 2005 were 2,739,000 MMBtu and 2,926,000 MMBtu, respectively. The net losses realized by us under such hedging arrangements were ($0.3) million and ($0.8) million for the three months ended September 30, 2004 and 2005, respectively, and are included in oil and natural gas revenues. The net loss realized by us under such hedging arrangements was ($0.7) million in each of the nine-month periods ended September 30, 2004 and 2005, respectively, and is included in oil and natural gas revenues.

To mitigate some of our commodity price risk, we engage periodically in certain other limited hedging activities including price swaps, costless collars and, occasionally, put options, in order to establish some price floor protection. We record the costs and any benefits derived from these price floors as a reduction or increase, as applicable, in natural gas and oil sales revenue upon settlement; these reductions and increases were not significant for any year presented in the financial information included in this report. The costs to purchase put options are amortized over the option period. We do not hold or issue derivative instruments for trading purposes.

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As of December 31, 2004 and September 30, 2005, the unrealized gain/(loss) on oil and natural gas hedges of $59,000 and ($5.0) million, net of tax of $34,000 and ($2.7) million, respectively, remained in accumulated other comprehensive income (loss) related to the valuation of our hedging positions.

While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of natural gas and oil. We enter into the majority of our hedging transactions with two counterparties and have a netting agreement in place with those counterparties. We do not obtain collateral to support the agreements but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, 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. In the event of nonperformance, we would be exposed again to price risk. We have some risk of financial loss because 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. Moreover, our hedging arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our hedges will vary from time to time.

Our natural gas derivative transactions are generally settled based upon the average of the reporting settlement prices on the NYMEX for the last three trading days of a particular contract month. Our oil derivative transactions are generally settled based on the average reporting settlement prices on the NYMEX for each trading day of a particular calendar month. For the month of September 2005, a $0.10 change in the price per Mcf of gas sold would have changed revenue by $59,000. A $0.70 change in the price per barrel of oil would have changed revenue by $11,000.

The table below summarizes our total natural gas production volumes subject to derivative transactions during the nine months ended September 30, 2005 and the weighted average NYMEX reference price for those volumes.

Natural Gas Swaps			Natural Gas Collars
Volumes (MMBtu)		183,000		Volumes (MMBtu)		2,743,000
Average price ($/MMBtu)	$	6.03		Average price ($/MMBtu)
				Floor	$	5.72
				Ceiling	$	7.77

The table below summarizes our total crude oil production volumes subject to derivative transactions for the nine months ended September 30, 2005 and the weighted average NYMEX reference price for those volumes.

Crude Oil Swaps			Crude Oil Collars
Volumes (MMBtu)		27,100		Volumes (Bbls)		72,200
Average price ($/Bbls)	$	50.19		Average price ($/Bbls)
				Floor	$	47.78
				Ceiling	$	60.33

At September 30, 2004 and 2005 we had the following outstanding hedge positions:

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As of September 30, 2004
	Contract Volumes
Quarter	BBls		MMbtu		Average Fixed Price		Average Floor Price		Average Ceiling Price
Fourth Quarter 2004		9,300			$	38.85
Fourth Quarter 2004		15,300					$	41.21	$	50.00
Fourth Quarter 2004				1,197,000				4.71		6.94
First Quarter 2005		18,000						40.00		50.00
First Quarter 2005				810,000				5.09		8.00
Second Quarter 2005				364,000				5.25		7.15
Second Quarter 2005				91,000		6.03
Third Quarter 2005				368,000				5.25		7.40
Third Quarter 2005				92,000		6.03
Fourth Quarter 2005				276,000				5.25		7.92
Fourth Quarter 2005				92,000		6.03

As of September 30, 2005
	Contract Volumes
Quarter	BBls		MMbtu		Average Fixed Price		Average Floor Price		Average Ceiling Price
Fourth Quarter 2005				874,000			$	6.74	$	9.24
Fourth Quarter 2005				92,000	$	6.03
Fourth Quarter 2005		9,200						57.00		62.55
First Quarter 2006				722,000				8.02		9.84
Second Quarter 2006				455,000				6.45		8.00
Third Quarter 2006				460,000				6.49		8.32
Fourth Quarter 2006				368,000				7.25		8.75
First Quarter 2007				360,000				7.50		9.45
Second Quarter 2007				273,000				6.68		8.08
Third Quarter 2007				276,000				6.80		8.20
Fourth Quarter 2007				276,000				6.92		8.32
First Quarter 2008				182,000				7.25		8.65

Forward Looking Statements

The statements contained in all parts of this document, including, but not limited to, those relating to our schedule, targets, estimates or results of future drilling, including the number, timing and results of wells, budgeted wells, increases in wells, the timing and risk involved in drilling follow-up wells, expected working or net revenue interests, planned expenditures, prospects budgeted and other future capital expenditures, risk profile of oil and natural gas exploration, acquisition of 3-D seismic data (including number, timing and size of projects), planned evaluation of prospects, probability of prospects having oil and natural gas, expected production or reserves, increases in reserves, acreage, working capital requirements, hedging activities, the ability of expected sources of liquidity to implement our business strategy, future hiring, future exploration activity, production rates, the exploration and development expenditures in the Barnett Shale trend, the Company’s initiatives designed to eliminate a material weakness in the Company’s internal control over financial reporting by increasing the level of the Company’s professional accounting staff, hiring a financial reporting professional, expanding the use of independent reviews of outside financial reporting experts and implementing a new fully-integrated accounting software system and the results of these initiatives and all 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,

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limited operating history, technological changes, significant capital requirements of the Company, the potential impact of government regulations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, availability of equipment, weather, availability of financing, the actual results of the initiatives designed to eliminate a material weakness in the Company’s internal control over financial reporting, availability of a qualified workforce to fill the Company’s accounting positions, completion of the implementation of the Company’s new accounting software system and the results of audits and assessments and other factors detailed in the Company's Annual Report on Form 10-K for the year ended December 31, 2004 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. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement and the Company undertakes no obligation to update or revise any forward looking statement.

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ITEM 3- 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, 2004 except for the Company’s hedging activity subsequent to December 31, 2004 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 2 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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Index

ITEM 4- CONTROLS AND PROCEDURES

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

In accordance with Exchange Act Rules 13a-15 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. As described in more detail in our Form 10-K/A filed on May 2, 2005 (the “10-K/A”), we identified a material weakness in the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) in connection with the work related to Management’s Annual Report on Internal Control over Financial Reporting. As a result of this material weakness, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2004, the Company’s disclosure controls and procedures were not effective. Because the control deficiencies leading to such material weakness (a manually intensive accounting system and the absence of a financial reporting director) are still present, our Chief Executive Officer and Chief Financial Officer have concluded that as of the end of the period covered by this report, the Company’s disclosure controls and procedures are not effective. The Company has outlined a number of initiatives, as discussed below, that it believes will remediate this material weakness in 2005.

Closing Cycle

Upon completion of the Company’s Sarbanes-Oxley Compliance assessment for its report included in the 10-K/A, the Company identified the following control deficiencies present in its closing cycle.

·   The accounting system is a manually intensive system, requiring the extensive use of spreadsheets to accumulate data and prepare the underlying support for reconciliations, account analysis and routine journal entries, all of which increases the review time and chance for error.

·   The current vacancy on the accounting staff for a financial reporting director, partially remedied by reliance upon independent financial reporting consultants for review of critical accounting areas and disclosures and material non-standard transactions.

As described below, when considered in the aggregate, these deficiencies constituted a material weakness over the effectiveness of detection and monitoring controls over the financial statement close process. These deficiencies ultimately affect the accuracy of our financial statement reporting and disclosures. As a result, management has previously concluded that our internal controls over financial reporting were not effective as of December 31, 2004. The Company had previously noted conditions related to the sufficiency of review applied to the financial statement closing process in connection with the finalization of its 2003 financial statements.

The manual year-end closing processes were performed substantially by our accounting and finance staff, with some reliance on contract professionals and financial reporting consultants. The combination of our manual, review intensive accounting system and the absence of a financial reporting director placed greater burdens of detailed reviews upon our middle and upper-level accounting professionals which, in turn compromised the level of their qualitative review of the financial statements and disclosures in the time available. These review procedures are an important component of our controls surrounding the closing process. As a result, we believe that the lack of a financial reporting director, the greater demands on the time of our accounting staff and their overall workload resulted in inadequate staffing, supervision and financial reporting expertise in our accounting department, which constituted a material weakness in our internal controls as of December 31, 2004.

Accordingly, in connection with the audit of our 2004 financial results, Pannell Kerr Forster of Texas, P.C. (“PKF”), our independent registered public accounting firm, detected a number of errors and/or omissions, none of which were material, individually or in aggregate, but were an indication that the aforementioned material weakness was present at December 31, 2004, increasing the likelihood to more than remote that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected. The most notable of these errors related to stock based compensation expense and related footnote

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Index

disclosures. Correcting adjustments were recorded by the Company prior to the finalization of its 2004 financial statements. The Company has implemented procedures to prevent these specific errors from occurring in the future. However, the additional initiatives (outlined below), are needed to remediate the material weakness in our internal controls, and thus lower the risk level to remote of other potential material errors or omissions.

While there can be no assurance in this regard, we expect that the following initiatives will eliminate this material weakness in 2005: (1) increasing the level of our professional accounting staff, including the successful placement of a financial reporting professional (recruiting efforts were begun in the second half of 2004), (2) expanding the use of independent reviews by outside financial reporting experts during the vacancy of our financial reporting position, and (3) completing our transition to a new fully-integrated accounting software system (data conversion began in 2004) to automate processes and improve qualitative reviews. Until these initiatives are fully implemented, we will continue to rely on manual processes and require additional commitment of resources to the closing process to produce our financial records and reports. As of the date of the filing of this report, we have implemented the initiative described in (2) above but have not yet completed the initiatives described in (1) and (3) above. We have successfully filled the financial reporting manager vacancy described in the clause (1) initiative and this financial reporting manager is expected to start work in November 2005. The project team has made significant progress toward completing the transition to a new fully-integrated accounting software system described in the clause (3) initiative and, accordingly, we expect that the transition to the new system will be completed during the fourth quarter of 2005.

Changes in Internal Control over Financial Reporting. There have not been any changes in the Company's internal control over financial reporting during the fiscal quarter ended September 30, 2005 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting. As described above, the Company identified a material weakness in the Company's internal control over financial reporting and has described a number of planned changes to its internal control over financial reporting during 2005 designed to remediate this weakness. This Item 4 should be read in conjunction with Item 9A included in the 10-K/A.

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Index

PART II. OTHER INFORMATION

Item 1 - Legal Proceedings

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.

Item 2 - Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 3 - Defaults Upon Senior Securities

None

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

None.

Item 5 - Other Information

None

Item 6 - Exhibits

Exhibits required by Item 601 of Regulation S-K are as follows:

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).
†10.1	—	Second Lien Agreement dated as of July 21, 2005 among Carrizo Oil & Gas, Inc., CCBM, Inc., the Lenders named therein and Credit Suisse, as collateral agent and administrative agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on July 22, 2005).
†10.2	—	Stock Pledge and Security Agreement dated as of July 21, 2005 by Carrizo Oil & Gas, Inc. in favor of Credit Suisse, as collateral agent (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 22, 2005).
†10.3	—	Commercial Guaranty dated as of July 21, 2005 by CCBM, Inc. in favor of Credit Suisse (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on July 22, 2005).
†10.4	—	Third Amendment dated as of July 21, 2005 to the Second Amended and Restated Credit Agreement among Carrizo Oil & Gas, Inc., CCBM, Inc. and Hibernia National Bank and Union Bank of California, N.A., as agents. (incorporated herein by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on July 22, 2005).
†10.5	—	Amendment No.6 to the Amended and Restated Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on August 19, 2005).

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

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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.

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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 9, 2005	By: /s/S. P. Johnson, IV
	President and Chief Executive Officer
	(Principal Executive Officer)
Date: November 9, 2005	By: /s/Paul F. Boling
	Chief Financial Officer
	(Principal Financial and Accounting Officer)

- 44 -

EX-31.1

Exhibit 31.1

CERTIFICATIONS

PRINCIPAL EXECUTIVE OFFICER

I, S.P. Johnson, IV, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Carrizo Oil & Gas, Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this quarterly report based on such evaluation; and

d) disclosed in this quarterly report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 9, 2005	/s/S. P. Johnson, IV
	S.P. Johnson IV
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

PRINCIPAL FINANCIAL OFFICER

I, Paul F. Boling, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Carrizo Oil & Gas, Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and we have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this quarterly report based on such evaluation; and

d) disclosed in this quarterly report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: November 9, 2005	/s/Paul F. Boling
	Paul F. Boling
	Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, S.P. Johnson, IV, President and Chief Executive Officer of Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), hereby certify, to my knowledge, that:

(1) the Company’s Quarterly Report on Form 10-Q for the three months ended September 30, 2005 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

    Dated:November 9, 2005   /s/S. P. Johnson, IV Name: S.P. Johnson, IV President and Chief Executive Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, Paul Boling, Vice President and Chief Financial Officer of Carrizo Oil & Gas, Inc., a Texas corporation (the “Company”), hereby certify, to my knowledge, that:

(1) the Company’s Quarterly Report on Form 10-Q for the three months ended September 30, 2005 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

    Dated:November 9, 2005   /s/Paul F. Boling Name: Paul F. Boling Vice President and Chief Financial Officer

The foregoing certification is being furnished solely pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to Carrizo Oil & Gas, Inc. and will be retained by Carrizo Oil & Gas, Inc. and furnished to the Securities and Exchange Commission or its staff upon request.