Edgar Filing: CARRIZO OIL & GAS INC

form10q.htm

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2008

[ ] 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 a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer [X]	Accelerated filer []

Non-accelerated filer [ ]	Smaller reporting company [ ]
(Do not check if a smaller reporting company)

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 November 1, 2008, the latest practicable date, was 30,748,906.

CARRIZO OIL & GAS, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2008

INDEX

PART I. FINANCIAL INFORMATION			PAGE

	Item 1.	Consolidated Balance Sheets
		As of September 30, 2008 (Unaudited) and December 31, 2007	2

		Consolidated Statements of Operations (Unaudited)
		For the three and nine-month periods ended September 30, 2008 and 2007	3

		Consolidated Statements of Cash Flows (Unaudited)
		For the nine-month periods ended September 30, 2008 and 2007	4

		Notes to Consolidated Financial Statements (Unaudited)	5

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

	Item 3.	Quantitative and Qualitative Disclosure About Market Risk	26

	Item 4.	Controls and Procedures	27


PART II. OTHER INFORMATION

	Items 1-6.		28

SIGNATURES			30

Index

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

	September 30,		December 31,
ASSETS	2008		2007
	(Unaudited)
	(In thousands, except per share amounts)
CURRENT ASSETS:
Cash and cash equivalents	$	9,023	$	8,026
Accounts receivable, trade (net of allowance for doubtful accounts of $1,264 and $1,430
at September 30, 2008 and December 31, 2007, respectively)		27,971		26,411
Advances to operators		1,195		1,113
Fair value of derivative financial instruments		7,384		1,829
Prepayments and deposits		3,576		3,913
Other current assets		72		324
Total current assets		49,221		41,616

PROPERTY AND EQUIPMENT, net full-cost method of accounting for oil
and natural gas properties (including unevaluated costs of properties of $343,004 and
$124,373 at September 30, 2008 and December 31, 2007, respectively)		1,063,184		646,810
DEFERRED FINANCING COSTS, NET		9,162		5,921
INVESTMENTS		5,075		11,071
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS		4,574		-
OTHER ASSETS		1,691		3,245
TOTAL ASSETS	$	1,132,907	$	708,663

LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
Accounts payable, trade	$	47,652	$	49,700
Accrued liabilities		52,730		36,091
Advances for joint operations		418		872
Current maturities of long-term debt		-		2,251
Fair value of derivative financial instruments		-		2,755
Total current liabilities		100,800		91,669

LONG-TERM DEBT, NET OF CURRENT MATURITIES		462,057		252,250
ASSET RETIREMENT OBLIGATION		6,955		5,869
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS		-		1,050
DEFERRED INCOME TAXES		69,146		46,321
DEFERRED CREDITS		671		783

COMMITMENTS AND CONTINGENCIES		-		-

SHAREHOLDERS' EQUITY:
Common stock, par value $0.01 (90,000 shares authorized; 30,747 and
28,009 issued and outstanding at September 30, 2008 and
December 31, 2007, respectively)		307		280
Additional paid-in capital		379,149		239,672
Retained earnings		113,625		65,344
Accumulated other comprehensive income, net of tax		197		5,425
Total shareholders' equity		493,278		310,721
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	1,132,907	$	708,663

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

-2-

Index

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2008			2007			2008			2007
	(In thousands except per share amounts)
OIL AND NATURAL GAS REVENUES	$	58,527		$	30,305		$	179,475		$	85,808

COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of depreciation, depletion
and amortization shown separately below)		10,427			6,940			28,047			17,203
Third party gas purchases		2,980			-			5,576			-
Depreciation, depletion and amortization		13,922			10,190			41,874			29,033
General and administrative (inclusive of stock-based compensation expense of
$1,560 and $1,058 for the three months ended September 30, 2008 and 2007,
respectively, and $4,547 and $3,050 for the nine months ended September 30, 2008
and 2007, respectively)		5,809			4,360			17,908			13,577
Accretion expense related to asset retirement obligations		58			89			173			265

TOTAL COSTS AND EXPENSES		33,196			21,579			93,578			60,078

OPERATING INCOME		25,331			8,726			85,897			25,730

OTHER INCOME AND EXPENSES:
Net gain (loss) on derivatives (Note 7)		77,686			1,917			(357	)		286
Other income, net		15			6			64			262
Gain (loss) on early extinguishment of debt		16			-			(5,689	)		-
Interest income		43			131			251			585
Interest expense		(5,297	)		(7,018	)		(16,694	)		(19,701	)
Capitalized interest		3,866			2,921			11,211			8,326

INCOME BEFORE INCOME TAXES		101,660			6,683			74,683			15,488
INCOME TAX EXPENSE (Note 4)		(35,461	)		(2,450	)		(26,402	)		(5,663	)

NET INCOME	$	66,199		$	4,233		$	48,281		$	9,825

OTHER COMPREHENSIVE INCOME (LOSS):
Increase (decrease) in market value of investment in Pinnacle Gas
Resources, Inc., net of taxes		(3,684	)		(4,399	)		(5,228	)		5,991

COMPREHENSIVE INCOME (LOSS)	$	62,515		$	(166	)	$	43,053		$	15,816

BASIC EARNINGS PER COMMON SHARE	$	2.18		$	0.16		$	1.62		$	0.38

DILUTED EARNINGS PER COMMON SHARE	$	2.14		$	0.16		$	1.59		$	0.37

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC		30,424			26,142			29,842			25,836
DILUTED		30,973			26,982			30,452			26,668

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

-3-

Index

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Nine
	Months Ended
	September 30,
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	48,281		$	9,825
Adjustment to reconcile net income to net cash provided by operating activities-
Depreciation, depletion and amortization		41,874			29,033
Fair value gain (loss) of derivative financial instruments		(13,933	)		5,311
Accretion of discounts on asset retirement obligations and debt		173			265
Stock-based compensation		4,547			3,050
Provision for allowance for doutbful accounts		(166	)		(243	)
Deferred income taxes		25,998			5,290
Loss on extenguishment of debt		4,601			-
Other		3,550			1,169
Changes in operating assets and liabilities
Accounts receivable		(1,394	)		(3,276	)
Other assets/liabilities		(3,015	)		(2,514	)
Accounts payable		6,847			1,897
Accrued liabilities		8,995			(308	)
Net cash provided by operating activities		126,358			49,499

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(456,696	)		(150,514	)
Change in capital expenditure accrual		(1,573	)		(3,484	)
Proceeds from the sale of properties		2,280			1,405
Advances to operators		(83	)		963
Advances for joint operations		(453	)		(651	)
Other		(2,771	)		64
Net cash used in investing activities		(459,296	)		(152,217	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from debt issuance and borrowings		590,034			129,000
Debt repayments		(382,156	)		(96,693	)
Proceeds from common stock offering, net of offering costs		135,077			72,003
Proceeds from stock options exercised		240			790
Deferred loan costs and other		(9,260	)		(3,214	)
Net cash provided by financing activities		333,935			101,886

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		997			(832	)

CASH AND CASH EQUIVALENTS, beginning of period		8,026			5,408

CASH AND CASH EQUIVALENTS, end of period	$	9,023		$	4,576

CASH PAID FOR INTEREST (NET OF AMOUNTS CAPITALIZED)	$	1,872		$	9,867

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

-4-

Index

CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles. The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries 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, 2007 (the “2007 Form 10-K”).

Unconsolidated Investments

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

The Company’s investment in Pinnacle Gas Resources, Inc. (“Pinnacle”) is classified as available-for-sale. The Company adjusts the book value to fair market value through Other Comprehensive Income, net of taxes.

Reclassifications

Certain reclassifications have been made to the prior period’s financial statements to conform to the current presentation. These reclassifications had no effect on total assets, shareholders’ equity or net income.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the periods reported. 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, the collectability of outstanding accounts receivable, fair values of derivatives, stock-based compensation expense, contingencies and the results of current and future 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 estimates is a function of the quality and quantity of available data and the application of engineering and geological interpretation and judgment to available data. Subsequent drilling, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates may be affected by 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 affected by changes to future economic conditions such as the market prices received for sales of oil and natural gas volumes, interest rates, the market value and volatility of the Company’s common stock and corresponding volatility and the Company’s ability to generate future taxable income. Future changes in these assumptions may materially affect these significant estimates in the near term.

-5-

Index

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 employee-related costs for employees working directly on exploration activities of $5.2 million and $3.3 million for the nine months ended September 30, 2008 and 2007, respectively. Maintenance and repairs are expensed as incurred.

Depreciation, depletion and amortization (“DD&A”) of proved oil and natural gas properties is based on the unit-of-production method using estimates of proved reserve quantities. Investments in unproved properties are not subject to DD&A 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 have been impaired, the amount of such impairment is determined and added to the proved oil and natural gas property costs subject to DD&A. The depletable 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 quarters ended September 30, 2008 and 2007 was $2.24 and $2.26, 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.

Net capitalized costs are limited to a “ceiling-test” based on the estimated future net revenues, discounted at 10% per annum, from proved oil and natural gas reserves, based on current economic and operating conditions (“Full Cost Ceiling”). If net capitalized costs exceed this limit, the excess is charged to earnings. For the nine-month periods ended September 30, 2008 and 2007, the Company did not have any charges associated with its ceiling test.

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

Supplemental Cash Flow Information

The adjustment of the investment in Pinnacle of $(5.2) million, net of tax and $6.0 million, net of tax is excluded from the Statement of Cash Flows for the nine months ended September 30, 2008 and 2007, respectively. The Company paid approximately $32,000 for federal income taxes during the nine months ended September 30, 2008 and paid no federal income taxes during the same period in 2007.

Stock-Based Compensation

The Company records stock-based compensation as prescribed by the SFAS No. 123 (R). The compensation expense associated with stock options is based on the grant-date fair value of the options and recognized over the vesting period. Restricted stock is recorded as deferred compensation based on the closing price of the Company’s stock on the issuance date and is amortized to stock-based compensation expense ratably over the vesting period of the restricted shares (generally one to three years).

The Company recognized the following stock-based compensation expense for the nine months ended September 30:

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2008		2007		2008		2007
	(In millions)
Stock Option Expense	$	-	$	0.1	$	0.2	$	0.3
Restricted Stock Expense		1.5		1.0		4.3		2.8

Total Stock-Based Compensation Expense	$	1.5	$	1.1	$	4.5	$	3.1

-6-

Index

Derivative Instruments

The Company uses derivatives to manage price risk underlying its oil and natural gas production. The Company also used derivatives to manage the variable interest rate on its Second Lien Credit Facility that was terminated in May 2008. Accordingly, the Company’s remaining interest rate swap positions (covering the period from May 28, 2008 to December 31, 2008) were settled, resulting in a $3.3 million loss.

Upon entering into a derivative contract, the Company either designates the derivative instrument as a hedge of the variability of cash flow to be received (cash flow hedge) or the derivative must be accounted for as a non-designated derivative. All of the Company’s derivative instruments are treated as non-designated derivatives and the unrealized gain (loss) related to the mark-to-market valuation is included in the Company’s earnings.

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.

The Company’s Board of Directors sets all risk management policies and reviews volumes, types of instruments and counterparties on a quarterly basis. These policies require that derivative instruments be executed only by the President or Chief Financial Officer after consultation and concurrence by the President, Chief Financial Officer and Chairman of the Board. The master contracts with approved counterparties identify the President and Chief Financial Officer as the only Company representatives authorized to execute trades. The Board of Directors also reviews the status and results of derivative activities at least quarterly.

Major Customers

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

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
Cokinos Natural Gas Company		11	%		17	%		11	%		10	%
Houston Pipeline Co.		-			14	%		-			13	%
Crosstex Energy Services, Ltd.		10	%		15	%		11	%		15	%
Energy Transfer Partners, L.P.		-			16	%		-			12	%
DTE Energy Trading, Inc.		37	%		-			36	%		-

Earnings Per Share

Supplemental earnings per share information is provided below:

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2008		2007		2008		2007
	(In thousands, except
	per share amounts)
Net income	$	66,199	$	4,233	$	48,281	$	9,825

Average common shares outstanding
Weighted average common shares outstanding		30,424		26,142		29,842		25,836
Stock options and restricted stock		549		840		610		832
Diluted weighted average common shares outstanding		30,973		26,982		30,452		26,668

Earnings per common share
Basic	$	2.18	$	0.16	$	1.62	$	0.38
Diluted	$	2.14	$	0.16	$	1.59	$	0.37

-7-

Index

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 issuable during the periods. The Company did not exclude any stock options or shares of restricted stock from the calculation of dilutive shares for the three and nine months ended September 30, 2008 and 2007. Shares of common stock subject to issuance pursuant to the conversion features of the 4.375% Convertible Senior Notes due 2028 (see Note 2) did not have an effect on the calculation of dilutive shares for the three and nine-month periods ended September 30, 2008.

Recently Issued Accounting Pronouncements

In March 2008, the Financial Accounting Standards Board (FASB) issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS No. 161”). This standard is intended to improve financial reporting by requiring transparency about the location and amounts of derivative instruments in an entity’s financial statements, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of SFAS No. 161 are effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company does not believe the adoption of SFAS No. 161 will have a significant effect on its consolidated financial position, results of operations or cash flows.

In May 2008, the FASB issued FASB Staff Position (FSP) Accounting Principles Board (APB) 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement).” This FSP clarifies that convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are not addressed by paragraph 12 of APB Opinion No. 14, “Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants.” Additionally, this FSP specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008. The Company expects a significant impact to its financial disclosures upon adoption of this FSP but has not yet determined the full impact.

In June 2008, the FASB issued FSP Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share. The Company does not currently expect a material impact to its consolidated financial statements and disclosures upon adoption.

2.	LONG-TERM DEBT

Long-term debt consisted of the following at September 30, 2008 and December 31, 2007:

	September 30,		December 31,
	2008		2007
	(In thousands)
Convertible Senior Notes	$	373,750	$	-
Second Lien Credit Facility		-		220,500
Senior Secured Revolving Credit Facility		88,000		34,000
Other		307		1
		462,057		254,501
Current maturities		-		(2,251	)

	$	462,057	$	252,250

Convertible Senior Notes

-8-

Index

$100.06. This conversion rate is subject to adjustment upon certain corporate events. In addition, if certain fundamental changes occur on or before June 1, 2013, the Company will in some cases increase the conversion rate for a holder electing to convert notes in connection with such fundamental change; provided, that in no event will the total number of shares issuable upon conversion of a note exceed 14.7406 per $1,000 principal amount of notes (subject to adjustment in the same manner as the conversion rate). The maximum number of shares that could be issued upon exercise of all of the outstanding Senior Convertible Notes, assuming the issuance of the maximum number of shares issuable pursuant to the provision in the preceding sentence, but subject to adjustment for other corporate events, is 5,509,299. Holders may convert the notes only under the following conditions: (a) during any calendar quarter if the last reported sale price of Carrizo common stock exceeds 130 percent of the conversion price for at least 20 trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter, (b) during the five business days after any five consecutive trading day period in which the trading price per $1,000 principal amount of the notes is equal to or less than 97% of the conversion value of such notes, (c) during specified periods if specified distributions to holders of Carrizo common stock are made or specified corporate transactions occur, (d) prior to the close of business on the business day preceding the redemption date if the notes are called for redemption or (e) on or after March 31, 2028 and prior to the close of business on the business day prior to the maturity date of June 1, 2028. The holders of the Convertible Senior Notes may require the Company to repurchase the notes on June 1, 2013, 2018 and 2023, or upon a fundamental corporate change at a repurchase price in cash equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. The Company may redeem notes at any time on or after June 1, 2013 at a redemption price equal to 100 percent of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any.

The Convertible Senior Notes are unsecured obligations of the Company and will rank equal to all future senior unsecured debt but rank second in priority to the Senior Secured Revolving 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 and the lenders party thereto (the “Second Lien Credit Facility”). The Second Lien Credit Facility, as amended, provided for a term loan facility in an aggregate principal amount of $225.0 million. In May 2008, the Company repaid in full the $219.9 million outstanding under the Second Lien Credit Facility and terminated the facility in connection with the issuance of its Convertible Senior Notes.

Senior Secured Revolving Credit Facility

On May 25, 2006, the Company entered into a Senior Secured Revolving Credit Facility (“Senior Credit Facility”), which originally matured May 25, 2010. The Senior Credit Facility provides for a revolving credit facility up to the lesser of the borrowing base and $200.0 million. It is secured by substantially all of the Company’s assets and is guaranteed by all of the Company’s U.S. subsidiaries.

The borrowing base is determined by the lenders at least semi-annually. The Company may request one unscheduled borrowing base determination subsequent to each scheduled determination and the lenders may request unscheduled determinations at any time. At September 30, 2008, the borrowing base was $165.0 million and the Company had $88.0 million of borrowings outstanding under the Senior Credit Facility.

Prior to the amendment described below, the annual interest rate on each base rate borrowing was (a) the greatest of the agent’s Prime Rate, the Base CD Rate plus 1.0% and the Federal Funds Effective Rate plus 0.5%, plus (b) a margin between 0.25% and 1.75% (depending on the then-current level of borrowing base usage). The interest rate on each Eurodollar loan was the adjusted London Interbank Offered (“LIBO”) rate plus a margin between 1.5% to 3.0% (depending on the then-current level of borrowing base usage). At September 30, 2008, the average interest rate for amounts outstanding under the Senior Credit Facility was 4.5%.

In October 2008, the Company entered into the seventh amendment to the Senior Credit Facility. Pursuant to the seventh amendment, the six bank syndicate agreed to (1) increase the borrowing base to $222.5 million; (2) extend the maturity date to October 29, 2012; (3) change the semi-annual borrowing base redetermination dates to March 31 and September 30; (4) change the interest rate provisions as described below; and (5) replace JPMorgan with Guaranty Bank as the administrative agent bank.

As amended, the annual interest rate on each base rate borrowing will be (a) the greatest of the agent’s Prime Rate, the Base CD Rate plus 1.0% and the Federal Funds Effective Rate plus 0.5%, plus (b) a margin between 0.75% and 2.25% (depending on the then-current level of borrowing base usage), but such interest rate can never be lower than the adjusted Daily LIBO rate on such day plus a margin between 2.0% to 3.5% (depending on the current level of borrowing base usage). The interest rate on each Eurodollar loan

-9-

Index

will be the adjusted daily LIBO rate plus a margin between 2.0% to 3.5% (depending on the then-current level of borrowing base usage). At October 31, 2008, the average interest rate for amounts outstanding under the Senior Credit Facility was 5.3%.

The Company is subject to certain covenants and events of default under the terms of the Senior Credit Facility. See the Company’s 2007 Form 10-K for further discussion.

3.	INVESTMENTS

Investments consisted of the following at September 30, 2008 and December 31, 2007:

	September 30,		December 31,
	2008		2007
	(In thousands)
Pinnacle Gas Resources, Inc.	$	3,052	$	11,071
Oxane Materials, Inc.		2,023		-

	$	5,075	$	11,071

Pinnacle Gas Resources, Inc.

In 2003, the Company and its wholly-owned subsidiary CCBM, Inc. (“CCBM”) contributed their interests in certain natural gas and oil leases in Wyoming and Montana in areas prospective for coalbed methane to a newly formed entity, Pinnacle Gas Resources, Inc. (“Pinnacle”).

The Company classifies the Pinnacle investment as available-for-sale and adjusts the investment to fair value through Other Comprehensive Income. At September 30, 2008, the Company reported the fair value of the stock at $3.1 million (based on the closing price of Pinnacle’s common stock on September 30, 2008).

In June 2007, the Company sold 41,894 shares of Pinnacle stock for net proceeds of $0.4 million and recognized a $0.3 million gain, which is included in other income and expenses, net on the Consolidated Statements of Operations. As of September 30, 2008, the Company owned 2,422,238 shares of Pinnacle common stock.

Oxane Materials, Inc.

In May 2008, the Company entered into a strategic alliance agreement with Oxane Materials, Inc. (“Oxane”) in connection with the development of a proppant product to be used in the Company’s exploration and production program. The Company contributed approximately $2.0 million to Oxane in exchange for warrants to purchase Oxane common stock and for certain exclusive use and preferential purchase rights with respect to the proppant. The Company simultaneously invested an additional $500,000 in a convertible promissory note from Oxane. The convertible promissory note accrues interest at a rate of 6% per annum and will convert into preferred stock no later than December 2009. The Company accounts for the investment using the cost method.

4.	INCOME TAXES

The Company provided deferred federal income taxes at the rate of 35% (which also approximates its statutory rate) that amounted to a federal tax expense of $35.4 million and $2.3 million for the three-month periods ended September 30, 2008 and 2007, respectively, and a federal tax expense of $26.0 million and $5.3 million for the nine-month periods ended September 30, 2008 and 2007, respectively.

On January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 prescribes a measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, FIN 48 provides guidance regarding uncertain tax positions relating to derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company classifies interest and penalties associated with income taxes as interest expense. At September 30, 2008, the Company had no material uncertain tax positions and the tax years 2003 through 2007 remained open to review by federal and various state tax jurisdictions.

-10-

Index

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 currently expect these matters to have a material adverse effect on the operations or 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.

6.	SHAREHOLDERS’ EQUITY

The following is a summary of changes in the Company’s common stock for the nine-month periods ended September 30:

	2008			2007
	(In thousands)
Shares outstanding at January 1		28,009			25,981
Equity offering		2,588			1,800
Restricted stock issued, net of forfeitures		98			116
Employee stock options exercised		58			86
Common stock repurchased and retired for tax withholding obligation		(6	)		(4	)
Shares outstanding at September 30		30,747			27,979

In February 2008, the Company completed an underwritten public offering of 2,587,500 shares of its common stock at a price of $54.50 per share. The number of shares sold was approximately 9.2% of the Company’s outstanding shares before the offering. The Company received proceeds of approximately $135.1 million, net of expenses.

In September 2007, the Company sold 1,800,000 shares of its common stock to certain qualified investors in a registered direct offering at a price of $41.40 per share. The number of shares sold was approximately 6.8% of the Company’s fully diluted shares outstanding before the offering. The Company received proceeds of approximately $72.0 million, net of expenses.

7.	DERIVATIVE INSTRUMENTS

The Company enters into swaps, options, collars and other derivative contracts to manage price risks associated with a portion of anticipated future oil and natural gas production. The Company also used interest rate swap agreements to manage the Company’s exposure to interest rate fluctuations on the Second Lien Credit Facility that was terminated in May 2008.

The Company accounts for its oil and natural gas derivatives and interest rate swap agreements as non-designated hedges. These derivatives are marked-to-market at each balance sheet date and the unrealized gains (losses) along with the realized gains (losses) associated with the cash settlements of derivative instruments are reported as Net gain (loss) on derivatives, in Other Income and Expenses in the Consolidated Statements of Operations. For the three and nine month periods ended September 30, 2008 and 2007, the Company recorded the following related to its derivatives:

-11-

Index

	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2008			2007			2008			2007
	(In millions)
Realized gains (losses):
Natural gas and oil derivatives	$	(4.1	)	$	2.8		$	(9.8	)	$	5.4
Interest rate swaps - Second Lien Debt Outstanding		-			-			(1.2	)		0.2
Loss on interest rate swap settlement related to
Second Lien Credit Facility(1)		-			-			(3.3	)		-
		(4.1	)		2.8			(14.3	)		5.6

Unrealized gains (losses):
Natural gas and oil derivatives		81.7			1.0			11.1			(3.5	)
Interest rate swaps		-			(1.9	)		2.8			(1.8	)
		81.7			(0.9	)		13.9			(5.3	)

Net gain (loss) on derivatives	$	77.6		$	1.9		$	(0.4	)	$	0.3

__________

(1)

In May 2008, the Company repaid its outstanding borrowings under the Second Lien Facility and terminated the facility. In connection with the termination of the facility, the Company settled its interest rate swaps and realized a $3.3 million loss on the remaining positions covering the period from May 28, 2008 to December 31, 2008.

At September 30, 2008, the Company had the following outstanding derivative positions:

	Natural Gas				Natural Gas
	Swaps				Collars
			Average				Average		Average
Quarter	MMbtu		Fixed Price(1)		MMBtu		Floor Price(1)		Ceiling Price(1)
Fourth Quarter 2008		276,000	$	7.94		3,036,000	$	7.13	$	8.82
First Quarter 2009		-		-		2,520,000		7.37		9.10
Second Quarter 2009		-		-		2,548,000		7.12		8.85
Third Quarter 2009		-		-		2,576,000		7.16		8.88
Fourth Quarter 2009		-		-		2,576,000		7.17		8.90
First Quarter 2010		-		-		1,620,000		7.92		9.63
Second Quarter 2010		-		-		1,638,000		7.18		8.89
Third Quarter 2010		-		-		1,656,000		7.35		9.06
Fourth Quarter 2010		-		-		1,656,000		7.45		9.16
First Quarter 2011		-		-		450,000		9.70		11.70
Second Quarter 2011		-		-		455,000		8.25		10.25
Third Quarter 2011		-		-		460,000		8.65		10.65
Fourth Quarter 2011		-		-		460,000		8.85		10.85
First Quarter 2012		-		-		455,000		9.55		11.55
Second Quarter 2012		-		-		455,000		8.35		10.35

-12-

Index

	Oil Collars
			Average		Average
Quarter	Bbls		Floor Price(2)		Ceiling Price (2)
Fourth Quarter 2008		18,400	$	100.85	$	114.23
First Quarter 2009		9,000		131.65		151.65
Second Quarter 2009		9,100		131.40		151.40
Third Quarter 2009		9,200		130.85		150.85
Fourth Quarter 2009		9,200		130.35		150.35

__________

(1) Based on Houston Ship Channel and Waha spot prices.

(2) Based on West Texas intermediate index prices.

At September 30, 2008, approximately 95% of the Company’s open natural gas hedges were with JPMorgan Chase Bank, N.A. New York (“JPMC”), and the remaining 5% were with Shell Energy North America (US), L.P. The open oil hedge positions were all arranged with JPMC. On October 29, 2008, the open derivative positions with JPMC were novated and substituted with Credit Suisse as the counterparty to each such arrangement.

During the first and second quarter of 2007, the Company entered into interest swap agreements covering amounts outstanding under the Second Lien Credit Facility. These arrangements were designed to manage the Company’s exposure to interest rate fluctuations through December 31, 2008 by effectively exchanging existing obligations to pay interest based on floating rates with obligations to pay interest based on fixed LIBOR. In connection with the Company’s repayment of borrowings under and termination of the Second Lien Credit Facility, following the issuance of the Convertible Senior Notes in May 2008, the remaining open derivative positions on interest rates were cash settled, resulting in a realized loss of $3.3 million on the remaining positions covering the period from May 28, 2008 to December 31, 2008.

The fair value of the outstanding derivatives at September 30, 2008 and December 31, 2007 was a net asset of $11.9 million and a net liability of $2.0 million, respectively.

8.	FAIR VALUE MEASUREMENTS

Effective January 1, 2008, the Company adopted Financial Accounting Standards Board (“FASB”) Statement No. 157, “Fair Value Measurements” (“SFAS No. 157”), which defines fair value, establishes a framework for measuring fair value, establishes a fair value hierarchy based on the quality of inputs used to measure fair value and enhances disclosure requirements for fair value measurements. The implementation of SFAS No. 157 did not cause a change in the method of calculating fair value of assets or liabilities, with the exception of incorporating a measure of the Company’s own nonperformance risk or that of its counterparties as appropriate, which was not material. The primary impact from adoption was additional disclosures.

The Company elected to implement SFAS No. 157 with the one-year deferral permitted by FASB Staff Position No. FAS 157-2, “Effective Date of FASB Statement No. 157,” issued February 2008, which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities measured at fair value, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis.

SFAS No. 157 establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2 – Other inputs that are observable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

Level 3 – Unobservable inputs for which there is little or no market data and which the Company makes its own assumptions about how market participants would price the assets and liabilities.

-13-

Index

The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets:
Investment in Pinnacle Gas Resources, Inc.	$	3,052	$	-	$	-	$	3,052
Oil and natural gas derivatives		-		11,958		-		11,958

Total	$	3,052	$	11,958	$	-	$	15,010

Oil and natural gas derivatives are valued by a third-party consultant using valuation models that are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Effective January 1, 2008 the Company adopted SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of SFAS No. 115” (“SFAS No. 159”). SFAS No. 159 allows companies to choose to measure financial instruments and other items at fair value that previously were not required to be measured at fair value. The Company elected not to present any financial instruments or other items at fair value that were not required to be at fair value prior to the adoption of SFAS No. 159.

9.	RELATED PARTY TRANSACTIONS

In order to expand the Company’s ongoing lease acquisition efforts in the Marcellus Shale play, the Company elected to enter into a lease option agreement in August 2008 with ACP II Marcellus, LLC (“ACP II”). The Company’s Chairman of the Board, Steven A. Webster, serves as Co-Managing Partner and President of ACP II’s controlling entity, Avista Capital Holdings, LP. Strategically, this lease option arrangement allowed the Company to temporarily control important acreage positions during periods that the Company lacked sufficient capital or did not wish to use its own capital to directly acquire such oil and gas leases. The terms and conditions of the lease option arrangement with ACP II were generally consistent with lease option arrangements the Company has traditionally entered into with other third parties. This lease option arrangement provided the Company the option to purchase leases from ACP II through February 15, 2009 at up to 108% of ACP II’s original cost of acquiring the leases. ACP II paid approximately $27.5 million for the oil and gas leases under the lease option agreement. The Company never exercised its option to purchase any of these leases from ACP II. In connection with its joint venture arrangement described in Note 10 below, ACP II elected to contribute these leases into the joint venture at its cost and the lease option agreement was terminated.

10.	SUBSEQUENT EVENT

Marcellus Shale Joint Venture. Effective as of August 1, 2008, the Company entered into a joint venture arrangement with an affiliate of Avista, a private equity firm focused on investments in the energy, media and healthcare sectors. This joint venture was entered into by the Company following a process in which a special committee of the Company’s Board of Directors directed management to seek proposals from several private equity and mezzanine lenders in order to establish an advantageous structure to exploit the Company’s Marcellus Shale acreage. Under the terms of the joint venture, the Company and an affiliate of Avista Capital Partners II, LP (“Avista”), have each committed to contribute up to $150 million in cash and properties to acquire and develop acreage in the Marcellus Shale play, including the dedication of all of their respective Marcellus leasehold. At the time the joint venture was formed, the joint venture controlled approximately 155,000 net acres in the play. The Company’s contribution of properties to the joint venture will be reflected as a reduction of natural gas and oil properties for accounting purposes.

The Company will serve as operator of the joint venture properties under a joint operating agreement with Avista and will provide all geotechnical, land and accounting support. An operating committee composed of one representative of each party will provide overall supervision and direction of joint operations. Each representative has a vote equal to the participating interest in the properties and operations of the party it represents. Avista or its designee has the right to become a co-operator of the properties if Avista sells to an unaffiliated third party all of its membership interests or substantially all of its assets or if the Company defaults under the terms of any pledge of its interest in the properties.

-14-

Index

Avista has agreed to fund 100% of the joint venture’s next approximately $71.5 million of expenditures related to the Marcellus Shale play (the “Initial Cash Contribution”), currently projected to be spent over the course of the next eight to twelve months. After the Initial Cash Contribution has been funded by Avista, the parties will thereafter share all costs on joint venture operations in accordance with their participating interests, which the Company expects will generally be 50/50 thereafter.

Subject to specified exceptions, net cash flow from hydrocarbon production from the properties and sale proceeds from the dedicated properties will be allocated first to the joint venture partners in proportion to their respective investments (with property dedications generally valued on a cost basis) until Avista has recovered its investment, then 100% to the Company until it recovers approximately $33.5 million, and then in accordance with the parties’ participating interests. The Company has agreed to jointly market Avista’s share of the production from the properties with its own until the cash flows and sale proceeds are being allocated in accordance with the parties’ participating interests under the joint operating agreement. In addition to the Company’s share in the production and sale proceeds from joint venture properties, it also acquired in the transaction an interest in Avista that entitles the Company to increasing percentages of Avista’s profits if Avista’s members receive a return of their investment and specified internal rates of return on these investments are achieved. The Company’s interest in Avista provides consent rights only in limited, specified circumstances and generally does not entitle the Company to vote or participate in the management of Avista, which is controlled by its members and affiliates.

As part of the transaction, and subject to certain exceptions, the parties have agreed to enter into an area of mutual interest covering the Marcellus Shale play, wherein any lease, royalty or mineral rights acquired by one party within the area must be offered in proportionate share to the other on the same terms and conditions. The area of mutual interest will remain in place until certain specified events occur, at which time the area of mutual interest will only continue to apply to those areas where the joint venture is active.

Each party’s ability to transfer its interest in the joint venture to third parties is subject in most instances to preferential purchase rights for transfers of less than 10% of its interest in joint venture properties, or to “tag along” rights for most other transfers. Avista’s tag along rights do not apply upon the change of control of the Company’s ultimate parent entity.

Steven A. Webster, Chairman of the Company’s Board of Directors, serves as Co-Managing Partner and President of Avista Capital Holdings LP, which has the ability to control Avista. As previously disclosed, the Company has been a party to prior arrangements with affiliates of Avista Capital Holdings, LP in respect of the Company’s investment in Pinnacle Gas Resources, Inc.

-15-

Index

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, 2007 and the unaudited financial statements included elsewhere herein.

General Overview

Our third quarter 2008 included revenues and volumes from oil and gas production of $55.4 million and 6.0 Bcfe, respectively. The key drivers to our results for the three and nine-month periods ended September 30, 2008 included the following:

Drilling program. Our success is largely dependent on the results of our drilling program. During the nine months ended September 30, 2008, we drilled 80 gross wells (63.4 net wells) with an apparent success rate of 98% that was comprised of: (a) 57 of 57 gross wells (44.1 net wells) in the Barnett Shale area; (b) five of seven gross wells (3.3 net wells) in the onshore Gulf Coast area; (c) 15 of 15 gross wells (15.0 net wells) in the Camp Hill area and (d) one of one well (1.0 net) in other areas. We also drilled 12 gross service wells (12.0 net wells) in the Camp Hill area and one appraisal well (0.2 net) in the North Sea.

Production. Our third quarter production of 6.0 Bcfe, or 65.0 MMcfe/d, increased 35% from the third quarter 2007 production of 4.4 Bcfe primarily due to new production from 36 wells in the Barnett Shale. Production from the third quarter 2008 was approximately 0.1 Bcfe, or 2% lower than the second quarter 2008 production of 6.1 Bcfe, largely due to normal production declines, delays in obtaining easements to construct gathering lines in the Barnett Shale and down time attributable to Hurricanes Gustav and Ike.

Commodity prices. Natural gas prices were strong during the third quarter of 2008 compared to 2007 prices. We realized $8.78 per Mcf for natural gas (excluding the impact of derivatives) during the third quarter of 2008, 39% higher than the $6.33 per Mcf that we received in the third quarter of 2007 but 13% lower than the $10.12 per Mcf we received in the second quarter of 2008.

Capital funding. In order to fund our growth, we have taken steps to enhance our liquidity. In February 2008, we received approximately $135.1 million in net proceeds from an underwritten public offering of 2.59 million shares of our common stock. The net proceeds were used in part to pay down the $85.0 million then outstanding under the Senior Credit Facility. In May 2008, we received net proceeds of approximately $365.3 million from the issuance of the Senior Convertible Notes. Part of the proceeds were used to repay $75.0 million of outstanding debt under the Senior Credit Facility and the $219.9 million outstanding under the Second Lien Credit Facility. In October 2008, our borrowing base under the Senior Credit Facility was also increased to $222.5 million. In connection with the formation of our joint venture in the Marcellus Shale play, Avista agreed to fund 100% of the joint venture’s next approximately $71.5 million of expenditures related to the play. After this amount has been funded, the parties will share all costs on joint venture projects in accordance with their participating interests in the properties, which we expect will be generally 50/50, pursuant to the joint operating agreement.

Outlook

Production growth and historically sustainable prices are key to our future success and to continue our success:

In the last quarter of 2008 we currently plan to drill 25 gross wells (16.6 net) in the Barnett Shale area, three gross wells (3.0 net) in our Camp Hill field and three gross wells (2.2 net) in other areas. 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 2008, depreciation, depletion and amortization, oil and natural gas operating expenses and production are expected to increase over levels incurred in 2007. Our ability to drill this number of wells is heavily dependent upon the timely access to oilfield services, particularly drilling rigs, and availability of capital.

We plan to continue the development of the Barnett Shale. During the third quarter of 2008, we had six Company-operated rigs in the Barnett Shale: four in Southeast Tarrant County, one in Denton County and one in Parker County. As of November 5, 2008, we had 43 gross wells awaiting completion or pipeline connections. We expect to bring these wells online in the next six months.

-16-

Index

·	We plan to continue the development of the Marcellus Shale in the Northeastern United States, primarily through our new joint venture.

In the North Sea, our joint venture in the license immediately east of the Huntington Field (block 22/14a) recently announced the results of two wells. One of these wells appears to establish that a small portion of the Huntington Field extends beyond our block and onto block 22/14a. The other well appears to have found a separate oil accumulation unconnected to the Huntington field. These results will necessitate unitization and/or joint development of the field, which will likely delay development of the field.

·	We expect to continue to hedge production to decrease our exposure to reductions in natural gas and oil prices. At September 30, 2008, we had hedged approximately 22,837,000 MMBtus of natural gas production through 2012 and 54,900 Bbls of oil production through 2009.

Results of Operations

Three Months Ended September 30, 2008,

Compared to the Three Months Ended September 30, 2007

Revenues from oil and natural gas production for the three months ended September 30, 2008 increased 83% to $55.5 million from $30.3 million for the same period in 2007. Production volumes for natural gas for the three months ended September 30, 2008 increased 40% to 5.7 Bcf from 4.1 Bcf for the same period in 2007. Average natural gas prices, excluding the impact of the loss from our cash settled derivatives of $3.8 million and gain of $2.8 million for the quarters ended September 30, 2008 and 2007, respectively, increased to $8.78 per Mcf in the third quarter of 2008 from $6.33 per Mcf in the same period in 2007. Average oil prices for the quarter ended September 30, 2008 increased 59% to $120.09 per barrel from $75.40 per barrel in the same period in 2007. The increase in natural gas production volume was due primarily to production from 36 new company-operated wells in the Barnett Shale partially offset by natural production declines and downtime attributable to Hurricanes Gustav and Ike.

The following table summarizes production volumes, average sales prices and operating revenues (excluding the impact of derivatives) for the three months ended September 30, 2008 and 2007:

					2008 Period
	Three Months Ended				Compared to 2007 Period
	September 30,				Increase			% Increase
	2008		2007		(Decrease)			(Decrease)
Production volumes
Oil and condensate (MBbls)		43		59		(16	)		(27	)%
Natural gas (MMcf)		5,724		4,080		1,644			40	%
Average sales prices
Oil and condensate (per Bbl)	$	120.09	$	75.40	$	44.69			59	%
Natural gas (per Mcf)		8.78		6.33		2.45			39	%
Operating revenues (In thousands)
Oil and condensate	$	5,194	$	4,457	$	737			17	%
Natural gas		50,233		25,848		24,385			94	%
Other		3,100		-		3,100			100	%

Total Operating Revenues	$	58,527	$	30,305	$	28,222			93	%

Oil and natural gas operating expenses for the three months ended September 30, 2008 increased 50% to $10.4 million from $6.9 million for the same period in 2007 primarily as a result of (a) higher lifting costs of $2.5 million primarily attributable to increased production and the increased number of producing wells, (b) increased transportation and other product costs of $0.5 million mainly attributable to the Barnett Shale area and (c) increased severance tax expense of $0.9 million associated with increased production revenue. These increased costs were partially offset by lower workover expenses of $0.4 million.

-17-

Index

Depreciation, depletion and amortization (DD&A) expense for the three months ended September 30, 2008 increased 37% to $13.9 million ($2.33 per Mcfe) from $10.2 million ($2.30 per Mcfe) for the same period in 2007. This increase was primarily due to an increase in production volumes and a slight increase in the depletion rate attributable to higher overall finding costs of new reserves.

General and administrative expense for the three months ended September 30, 2008 increased by $1.4 million to $5.8 million from $4.4 million for the corresponding period in 2007 primarily as a result of increased stock-based compensation of $0.5 million due to increased issuance of stock awards and higher stock prices and increased compensation costs of $0.5 million related to an increased number of employees.

The net gain on derivatives of $77.6 million in the third quarter of 2008 was comprised of $4.1 million of realized loss on net cash settled derivatives and $81.7 million of net unrealized mark-to-market gain on derivatives. The net gain on derivatives of $1.9 million in the third quarter of 2007 was comprised of $2.8 million of realized gain on net cash settled derivatives and $(0.9) million of net unrealized mark-to-market loss on derivatives.

Interest expense and capitalized interest for the three months ended September 30, 2008 were $5.3 million and $(3.9) million, respectively, as compared to $7.0 million and $(2.9) million for the same period in 2007. The decline in net interest expense is attributable primarily to lower interest rates and higher capitalized costs associated with the increase of unproved leasehold costs in 2008. These decreases were partially offset by higher average outstanding borrowings during 2008.

Nine Months Ended September 30, 2008,

Compared to the Nine Months Ended September 30, 2007

Revenues from oil and natural gas production for the nine months ended September 30, 2008 increased by 102% to $173.7 million from $85.8 million for the same period in 2007. Production volumes for natural gas for the nine months ended September 30, 2008 increased to 17.6 Bcf from 10.8 Bcf for the same period in 2007. Average natural gas prices, excluding the impact of the loss from our cash settled derivatives of $8.7 million and gain of $5.4 million for the nine months ended September 30, 2008 and 2007, respectively, increased 31% to $8.98 per Mcf in the first nine months of 2008 from $6.88 per Mcf in the same period in 2007. Average oil prices for the nine months ended September 30, 2008 increased 72% to $112.19 per barrel from $65.22 per barrel in the same period in 2007. The increase in natural gas production volume was due primarily to the addition of new Barnett Shale wells, the addition of three wells in the Gulf Coast during the first and second quarters of 2007 and second quarter of 2008 and the successful recompletion of the Galloway Gas Unit II well #1.

The following table summarizes production volumes, average sales prices and operating revenues (excluding the impact of derivatives) for the nine months ended September 30, 2008 and 2007:

					2008 Period
	Nine Months Ended				Compared to 2007 Period
	September 30,				Increase			% Increase
	2008		2007		(Decrease)			(Decrease)
Production volumes
Oil and condensate (MBbls)		144		182		(38	)		(21	)%
Natural gas (MMcf)		17,555		10,753		6,802			63	%
Average sales prices
Oil and condensate (per Bbl)	$	112.19	$	65.22	$	46.97			72	%
Natural gas (per Mcf)		8.98		6.88		2.10			31	%
Operating revenues (In thousands)
Oil and condensate	$	16,131	$	11,881	$	4,250			36	%
Natural gas		157,564		73,927		83,637			113	%
Other		5,780		-		5,780			100	%

Total Operating Revenues	$	179,475	$	85,808	$	93,667			109	%

Oil and natural gas operating expenses for the nine months ended September 30, 2008 increased $10.8 million to $28.0 million from $17.2 million for the same period in 2007 primarily as a result of (a) higher lifting costs of $6.0 million primarily attributable to increased production and the increased number of producing wells, (b) increased severance taxes of $1.8 million due to increased

-18-

Index

production revenue and (c) increased transportation and other product costs of $3.2 million due to higher prices of services and increased production.

DD&A expense for the nine months ended September 30, 2008 increased 44% to $41.9 million ($2.27 per Mcfe) from $29.0 million ($2.45 per Mcfe) for the same period in 2007. This increase was primarily due to an increase in production volumes, partially offset by a decrease in the depletion rate attributable to lower overall finding costs of new reserves.

General and administrative expense for the nine months ended September 30, 2008 increased by $4.3 million to $17.9 million from $13.6 million for the corresponding period in 2007 due primarily to (a) increased salary and related employee costs of $1.2 million, (b) increased stock based compensation of $1.5 million due to increased issuance of stock awards and higher stock prices and (c) increased legal, professional and contractor fees of $0.6 million.

The net loss on derivatives of $0.4 million in the first nine months of 2008 was comprised of $14.3 million of realized loss on net cash settled derivatives and $13.9 million of net unrealized mark-to-market gain on derivatives primarily as a result of the increase in oil and natural gas prices during 2008. The net gain on derivatives of $0.3 million in the first nine months of 2007 was comprised of $5.6 million of realized gain on net cash settled derivatives and $5.3 million of net unrealized mark-to-market loss on derivatives.

In May 2008, we repaid our outstanding borrowings under the Second Lien Facility and terminated the facility. As a result, we recorded a $5.7 million loss associated with the early extinguishment of debt consisting of $4.6 million non-cash write-off of deferred loan costs and $1.1 million in penalties paid for early retirement. In connection with the termination, we settled the interest rate swaps and realized a $3.3 million loss, included in our net loss on derivatives.

Interest expense and capitalized interest for the nine months ended September 30, 2008 were $16.7 million and $(11.2) million, respectively, as compared to $19.7 million and $(8.3) million for the same period in 2007. The decline in net interest expense is primarily attributable to lower interest rates and higher capitalized costs as a result of increased unproved leasehold costs in 2008. These decreases were partially offset by a higher outstanding debt balances in 2008.

Liquidity and Capital Resources

Sources and Uses of Cash. During the nine months ended September 30, 2008, capital expenditures, net of proceeds from property sales, exceeded our net cash provided by operations. During 2008, we funded our capital expenditures with cash generated from operations, proceeds from the issuance of our common stock and Senior Convertible Notes, and net additional borrowings under our Senior Revolving Credit Facility. Potential primary sources of future liquidity include the following:

·	Cash on hand and cash generated by operations. Cash flows from operations are highly dependent on commodity prices and market conditions for oil and gas field services. We hedge a portion of our production to reduce the downside risk of declining natural gas and oil prices.

Available borrowings under the Senior Credit Facility. In October 2008, the borrowing base under the Senior Credit Facility increased by $57.5 million to $222.5 million. At October 31, 2008, $102.5 million was available for borrowing under the Senior Credit Facility. The next borrowing base redetermination is currently scheduled for the first quarter of 2009.

Other debt and equity offerings. In February 2008, we received $135.1 million of net proceeds from an underwritten public offering of 2,587,500 shares of our common stock priced at $54.50 per share. In May 2008, we received $365.3 million of net proceeds from the issuance of the Senior Convertible Notes. As situations or conditions arise, we may need to issue debt, equity or other instruments to supplement our cash flows.

·	Asset sales. In order to fund our drilling program, we may consider the sale of certain properties or assets no longer deemed core to our future growth.

·	Project financing in certain limited circumstances.

·	Lease option agreements and land banking arrangements, such as those we have entered into regarding the Marcellus Shale, the Barnett Shale and other plays.

·	Joint ventures with third parties through which such third parties fund a portion of our exploration activities to earn an interest in our exploration acreage, such as our recent joint venture in the Marcellus Shale play.

-19-

Index

Our primary use of cash is capital expenditures related to land acquisition and our drilling program. For 2008, we budgeted approximately $295 million for our 2008 drilling program and $242 million for lease and seismic acquisitions. For the nine months ended September 30, 2008, we have incurred approximately $456.7 million in capital expenditures.

A description of the Marcellus lease option agreement and the Marcellus joint venture are included in Notes 9 and 10, respectively, to the unaudited financial statements included elsewhere in this report.

2009 Capital Budget and Funding Strategy. For 2009, we have an estimated capital expenditures budget of approximately $288 million, comprised of (1) $265 million for our drilling program (including $240 million for the Barnett Shale development), (2) $17 million for lease acquisitions, primarily in the Barnett Shale and (3) $6 million for seismic data acquisition. We are targeting to fund approximately 75%-85% of the 2009 budget from our cash flow from operations, and expect that the remainder will be funded from the borrowings available under our Senior Credit Facility, which was $102.5 million as of October 31, 2008. We may not be able to borrow sufficient amounts under our Senior Credit Facility to cover the remainder of the 2009 capital expenditures budget. While the average annual increase in the available borrowing base over the past eight calendar quarters has been about $85 million, there can be no assurance that we will continue to successfully grow the available borrowing base in 2009 due to a number of potential risk factors which could adversely affect future borrowing base availability including, among other factors a continued decline in commodity prices, and/or credit availability from commercial banks. In that event, we may be required to reduce or defer part of our 2009 capital expenditures program.

Overview of Cash Flow Activities. Cash flows provided by operating activities were $126.4 million and $49.5 million for the nine months ended September 30, 2008 and 2007, respectively. The increase was primarily due to increased production and higher oil and natural gas commodity prices.

Cash flows used in investing activities were $459.3 million and $152.2 million for the nine months ended September 30, 2008 and 2007, respectively, and related primarily to oil and gas property expenditures. During the first nine months of 2008, we invested approximately $457 million in oil and gas properties, including $247 million related to leasehold acquisitions primarily in the Barnett and Marcellus shales and $190 million related to drilling activities.

Net cash provided by financing activities for the nine months ended September 30, 2008 was $333.9 million and related primarily to net proceeds of $135.1 million from the issuance of common stock in February 2008, net proceeds of $365.3 million from the issuance of Senior Convertible Notes and $214.0 million in additional borrowings under the Senior Credit Facility. These cash proceeds were partially offset by the payoff and termination of the Second Lien Credit Facility and partial paydown of the Senior Credit Facility. Net cash provided by financing activities for the nine months ended September 30, 2007 was $101.9 million and related primarily to the additional borrowings of $75.0 million under the Second Lien Credit Facility in January 2007 and net proceeds of $72.0 million from the issuance of common stock in September 2007. These cash proceeds were partially offset by the paydown of the Senior Credit Facility.

Liquidity/Cash Flow Outlook. We currently believe that cash generated from operations along with cash on hand and the cash available under the Senior Revolving Credit Facility is sufficient to fund our immediate needs, but we may need to seek other financing alternatives to fully fund our currently planned 2008 capital expenditures budget.

We may not be able to obtain financing needed in the future on terms that would be acceptable to us. If we cannot obtain adequate financing, 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. The recent worldwide financial and credit crisis has adversely affected the ability of many companies, including us, to access the debt and equity markets. This decreased ability to obtain financing could materially adversely affect our ability to continue our previously expected business plan.

Contractual Obligations

During the first quarter of 2008, we entered into a firm drilling agreement for one rig over a three-year term. The estimated obligation is approximately $8.4 million per year through 2010.

During the second quarter 2008, we entered into two additional drilling rig agreements, (a) a three-year contract with an estimated obligation of $8.5 million per year and (b) a one-year contract with an estimated obligation of $7 million.

-20-

Index

Financing Arrangements

Convertible Senior Notes

In May 2008, the Company issued $373.8 million aggregate principal amount of 4.375% convertible senior notes due 2028 (“Convertible Senior Notes”). Interest is payable on June 1 and December 1 each year, commencing December 1, 2008. The notes will be convertible, using a net share settlement process, into a combination of cash and Carrizo common stock that entitles holders of the Convertible Senior Notes to receive cash up to the principal amount ($1,000 per note) and common stock in respect of the remainder, if any, of Carrizo’s conversion obligation in excess of such principal amount. The notes are convertible into Carrizo’s common stock at a ratio of 9.9936 shares per $1,000 principal amount of notes, equivalent to a conversion price of approximately $100.06. This conversion rate is subject to adjustment upon certain corporate events. In addition, if certain fundamental changes occur on or before June 1, 2013, the Company will in some cases increase the conversion rate for a holder electing to convert notes in connection with such fundamental change; provided, that in no event will the total number of shares issuable upon conversion of a note exceed 14.7406 per $1,000 principal amount of notes (subject to adjustment in the same manner as the conversion rate). The maximum number of shares that could be issued upon exercise of all of the outstanding Convertible Senior Notes, assuming the issuance of the maximum number of shares issuable pursuant to the provision in the preceding sentence, but subject to adjustment for other corporate events, is 5,509,299. Holders may convert the notes only under the following conditions: (a) during any calendar quarter if the last reported sale price of Carrizo common stock exceeds 130 percent of the conversion price for at least 20 trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter, (b) during the five business days after any five consecutive trading day period in which the trading price per $1,000 principal amount of the notes is equal to or less than 97% of the conversion value of such notes, (c) during specified periods if specified distributions to holders of Carrizo common stock are made or specified corporate transactions occur, (d) prior to the close of business on the business day preceding the redemption date if the notes are called for redemption or (e) on or after March 31, 2028 and prior to the close of business on the business day prior to the maturity date of June 1, 2028. The holders of the Convertible Senior Notes may require the Company to repurchase the notes on June 1, 2013, 2018 and 2023, or upon a fundamental corporate change at a repurchase price in cash equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. The Company may redeem notes at any time on or after June 1, 2013 at a redemption price equal to 100 percent of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any.

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 revenues. In addition, we are affected by increases in the costs of services and equipment that we employ to explore for and produce oil and natural gas due to high activity and a relative scarcity of equipment. We generally expect these costs and expenses to continue to increase if oil and natural gas prices remain strong and drilling activity remains high. In the recent historical past, inflation has had a minimal effect on us.

Recently Adopted Accounting Pronouncements

We adopted the Financial Accounting Standards Statement No. 157, “Fair Value Measurement” (“SFAS No. 157”), effective January 1, 2008. SFAS No. 157 provides a framework for measuring fair value and enhances related disclosures. The implementation of SFAS No. 157 did not change our current valuation method and did not have a material effect on our consolidated financial position or results in operations. We included additional disclosures in the Notes to Consolidated Financial Statements with respect to the measurement of our assets and liabilities at fair value on the balance sheet date.

Recently Issued Accounting Pronouncements

In March 2008, the Financial Accounting Standards Board (FASB) issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities (“SFAS No. 161”). This standard is intended to improve financial reporting by requiring transparency about the location and amounts of derivative instruments in an entity’s financial statements, how derivative instruments and related hedged items are accounted for under SFAS No. 133, and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. The provisions of SFAS No. 161 are effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We do not believe the adoption of SFAS No. 161 will have a significant effect on our consolidated financial position, results of operations or cash flows.

-21-

Index

In May 2008, the FASB issued FASB Staff Position (FSP) Accounting Principles Board (APB) 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement).” This FSP clarifies that convertible debt instruments that may be settled in cash upon conversion, including partial cash settlement, are not addressed by paragraph 12 of APB Opinion No. 14, “Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants.” Additionally, this FSP specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. This FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008. We currently expect a significant impact to our financial disclosures upon adoption of this FSP but the full impact has not yet been determined.

In June 2008, the FASB issued FSP Emerging Issues Task Force (EITF) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities.” This FSP provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share. We do not currently expect a material impact to our consolidated financial statements and disclosures upon adoption.

Critical Accounting Policies

The following summarizes our critical accounting policies:

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 employee-related costs for employees working directly on exploration activities of $5.2 million and $3.3 million for the nine months ended September 30, 2008 and 2007, 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 three months ended September 30, 2008 and 2007 was $2.24 and $2.26, 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.

Net capitalized costs of proved oil and natural gas properties are limited to a “ceiling test” based on the estimated future net revenues, discounted at 10% per annum, from proved oil and natural gas reserves based on current economic and operating conditions (“Full Cost Ceiling”). If net capitalized costs exceed this limit, the excess is charged to earnings.

In connection with our September 30, 2008 Full Cost Ceiling test computation, a price sensitivity study also indicated that a 10% increase or decrease in commodity prices at September 30, 2008 would have increased or decreased the Full Cost Ceiling test cushion by approximately $78 million and $95 million, respectively. The aforementioned price sensitivity is as of September 30, 2008 and, accordingly, does not include any potential changes in reserve values due to subsequent performance or events, such as commodity prices, reserve revisions and drilling results. Since September 30, 2008, there has been a significant decrease in oil prices, and to a lesser extent gas prices, thereby increasing the possibility of a ceiling test write-down in the future.

The Full Cost Ceiling cushion at the end of September 30, 2008 of approximately $125 million was based upon average realized oil, natural gas liquids and natural gas prices of $96.29 per Bbl, $55.44 per Bbl and $4.58 per Mcf, respectively, or a volume weighted average price of $40.12 per BOE. This cushion, however, would have been zero on such date at an estimated volume weighted average price of $34.82 per BOE. A BOE means one barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to

-22-

Index

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 of our oil and natural gas properties, excluding unevaluated costs, plus estimated future development costs and salvage value, to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income.

We have a significant amount of proved undeveloped reserves. We had 185.8 Bcfe of proved undeveloped reserves at December 31, 2007, representing 53% of our total proved reserves. As of December 31, 2007, a portion of these proved undeveloped reserves, or approximately 38.1 Bcfe, 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 (the estimated time that it will take to produce all recoverable reserves) of our Camp Hill properties is considerably longer, or approximately 15 years, when compared to the depletable life of our remaining oil and natural gas properties of approximately 10 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, causing the build-up of nondepleted capitalized costs associated with properties that have been completely depleted. This combination of factors, in turn, has had a favorable impact on our earnings, which have been higher than they would have been had the Camp Hill properties not resulted in a relatively low overall depletion rate and DD&A expense and longer depletion period. As a hypothetical illustration of this impact, the removal of our Camp Hill proved undeveloped reserves starting January 1, 2002 would have reduced our earnings by (a) an estimated $11.2 million in 2002 (comprised of after-tax charges for a $7.1 million full cost ceiling impairment and a $4.1 million depletion expense increase), (b) an estimated $5.9 million in 2003 (due to higher depletion expense), (c) an estimated $3.4 million in 2004 (due to higher depletion expense), (d) an estimated $6.9 million in 2005 (due to higher depletion expense), (e) an estimated $0.7 million in 2006 (due to higher depletion expense) and (f) an estimated $2.0 million in 2007 (due to higher depletion expense).

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 costs and current prices were all to remain constant, this continued build-up of capitalized cost increases the probability of a ceiling test write-down in the future.

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

For information regarding our other critical accounting policies, see the 2007 Form 10-K.

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 method of accounting rules. See “—Critical Accounting Policies—Oil and Natural Gas Properties.”

To mitigate some of our commodity price risk, we engage periodically in certain other limited derivative activities including price swaps, costless collars and, occasionally, put options, in order to establish some price floor protection.

The following table includes oil and natural gas positions settled during the three and nine-month periods ended September 30, 2008 and 2007, and the unrealized gain/(loss) associated with the outstanding oil and natural gas derivatives at September 30, 2008 and 2007.

-23-

Index

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2008			2007		2008			2007

Oil positions settled (Bbls)		18,400			18,300		45,700			18,300
Natural gas positions settled (MMBtu)		3,312,000			1,898,000		10,902,000			5,332,000
Realized gain/(loss) ($ millions) (1)	$	(4.1	)	$	2.8	$	(9.8	)	$	5.4
Unrealized gain/(loss) ($ millions) (1)	$	81.7		$	1.0	$	11.1		$	(3.5	)

__________

(1) Included in net gain (loss) on derivatives in the Consolidated Statements of Operations.

At September 30, 2008, the Company had the following outstanding derivative positions:

	Natural Gas				Natural Gas
	Swaps				Collars
			Average				Average		Average
Quarter	MMbtu		Fixed Price(1)		MMBtu		Floor Price(1)		Ceiling Price(1)
Fourth Quarter 2008		276,000	$	7.94		3,036,000	$	7.13	$	8.82
First Quarter 2009		-		-		2,520,000		7.37		9.10
Second Quarter 2009		-		-		2,548,000		7.12		8.85
Third Quarter 2009		-		-		2,576,000		7.16		8.88
Fourth Quarter 2009		-		-		2,576,000		7.17		8.90
First Quarter 2010		-		-		1,620,000		7.92		9.63
Second Quarter 2010		-		-		1,638,000		7.18		8.89
Third Quarter 2010		-		-		1,656,000		7.35		9.06
Fourth Quarter 2010		-		-		1,656,000		7.45		9.16
First Quarter 2011		-		-		450,000		9.70		11.70
Second Quarter 2011		-		-		455,000		8.25		10.25
Third Quarter 2011		-		-		460,000		8.65		10.65
Fourth Quarter 2011		-		-		460,000		8.85		10.85
First Quarter 2012		-		-		455,000		9.55		11.55
Second Quarter 2012		-		-		455,000		8.35		10.35

	Oil Collars
			Average		Average
Quarter	Bbls		Floor Price(2)		Ceiling Price (2)
Fourth Quarter 2008		18,400	$	100.85	$	114.23
First Quarter 2009		9,000		131.65		151.65
Second Quarter 2009		9,100		131.40		151.40
Third Quarter 2009		9,200		130.85		150.85
Fourth Quarter 2009		9,200		130.35		150.35

__________

(1) Based on Houston Ship Channel and Waha spot prices.

(2) Based on West Texas intermediate index prices.

At September 30, 2008, approximately 95% of our open natural gas hedges were with JPMorgan Chase Bank, N.A. New York (“JPMC”), and the remaining 5% were with Shell Energy North America (US), L.P. The open oil hedge positions were all arranged with JPMC. On October 29, 2008, the open derivative positions with JPMC were novated and substituted with Credit Suisse as the counterparty to each such arrangement.

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 derivatives 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

-24-

Index

the financial viability of counterparties. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity 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 additional 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 derivatives 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 Houston Ship Channel and Waha indices 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 West Texas Intermediate index for each trading day of a particular calendar month. For the third quarter of 2008, a 10% change in the price per Mcf of natural gas sold would have changed revenue by $5.0 million. A 10% change in the price per barrel of oil would have changed revenue by $0.5 million for the third quarter of 2008.

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 the Company’s business strategy, future exploration activity, production rates, 2008 and 2009 drilling programs, growth in production, development of new drilling programs, hedging of production and exploration and development expenditures, Camp Hill development and all and any other statements regarding future operations, financial results, business plans and cash needs, potential borrowing base increases 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 expressions are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to the Company’s dependence on its exploratory drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, the Company’s dependence on its key personnel, factors that affect the Company's ability to manage its growth and achieve its business strategy, risks relating to limited operating history, technological changes, significant capital requirements of the Company, the potential impact of government regulations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, availability of equipment, weather, availability of financing, actions by lenders, ability to obtain permits, the results of audits and assessments, and other factors detailed in the “Risk Factors” and other sections of the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 and in this and its 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.

-25-

Index

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, 2007. Except as discussed below, there have been no material changes to the disclosure regarding our exposure to certain market risks made in the Annual Report on Form 10-K. For additional information regarding our long-term debt, see Note 2 of the Notes to Consolidated Financial Statements (Unaudited) in Item 1 of Part I of this Quarterly Report on Form 10-Q.

Financial Instruments and Debt Maturities. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and bank borrowings, including borrowings under our Senior Credit Facility, and our Convertible Senior Notes. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature of our bank borrowings as short-term instruments. The fair values of the bank and vendor borrowings approximate the carrying amounts as of December 31, 2007 and 2006, and were determined based upon interest rates currently available to us for borrowings with similar terms. Maturities of long-term debt of $88.0 million are due in 2012 under the Senior Credit Facility and of $373.8 million in 2028 under the Convertible Senior Notes.

-26-

Index

ITEM 4 - CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures. Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures, which have been designed to provide reasonable assurance that the information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is accumulated and communicated to the Company's management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure. They concluded that the controls and procedures were effective as of September 30, 2008 to provide reasonable assurance that the information required to be disclosed by the Company in reports it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended September 30, 2008, that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

-27-

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 1A – Risk Factors

In addition to the risk factor set forth below and the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2007, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

The global financial and credit crisis may have impacts on our liquidity and financial condition that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system may have a material impact on our liquidity and our financial condition, and we may ultimately face major challenges if conditions in the financial markets do not improve. Our ability to access the capital markets or borrow money may be restricted at a time when we would like, or need, to raise capital, which could have an adverse impact on our flexibility to react to changing economic and business conditions and on our ability to fund our operations and capital expenditures in the future. The economic situation could have an impact on our lenders or customers, causing them to fail to meet their obligations to us, and on the liquidity of our operating partners, resulting in delays in operations or failure to make required payments. Also, market conditions could have an impact on our natural gas and oil derivatives transactions if our counterparties are unable to perform their obligations or seek bankruptcy protection. Additionally, the current economic situation could lead to reduced demand for natural gas and oil, or further reductions in the prices of natural gas and oil, or both, which could have a negative impact on our financial position, results of operations and cash flows. While the ultimate outcome and impact of the current financial crisis cannot be predicted, it may have a material adverse effect on our future liquidity, results of operations and financial condition.

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

The following table presents information regarding the Company’s purchases of its common stock on a monthly basis during the third quarter of 2008:

					(c) Total Number of		(d) Maximum Number
					Shares Purchased as		(or Appropriate Dollar
	(a) Total Number				Part of Publicly		Value) of Shares that May
	of Shares		(b) Average Price		Announced Plans or		Yet Be Purchased Under
Period	Purchased(1)		Paid Per Share		Programs		the Plan or Programs
July 2008		221	$	60.33		-		-
August 2008		-		-		-		-
September 2008		-		-		-		-

Total		221	$	60.33		-		-

__________

(1) The 221 shares related to the surrender of shares of common stock to satisfy tax withholding obligations in connection with the vesting of restricted stock issued to employees under our long-term incentive plan.

Item 3 - Defaults Upon Senior Securities

None.

-28-

Index

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
†3.1	—	Articles of Amendment to the Amended and Restated Articles of Incorporation of the Company (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed on June 25, 2008).
†10.1	—	Sixth Amendment dated July 7, 2008 to Credit Agreement dated as of May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, JPMorgan Chase Bank, N.A., as Administrative Agent and the Lenders party thereto (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on July 11, 2008).
†10.2	—	Seventh Amendment dated October 29, 2008 to Credit Agreement dated May 25, 2006 among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, the Lenders party thereto, JPMorgan Chase Bank, N.A., as resigning administrative agent and as resigning issuing bank, and Guaranty Bank, as successor administrative agent and as successor issuing bank (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 4, 2008).
†10.3	—	Participation Agreement among Carrizo (Marcellus) LLC, Carrizo Oil & Gas, Inc., Avista Capital Partners II, L.P. and ACP II Marcellus LLC, dated November 3, 2008 and effective as of August 1, 2008 (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on November 4, 2008).
31.1	—	CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	—	CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	—	CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	—	CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

†	Incorporated herein by reference as indicated.

-29-

Index

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 6, 2008	By: /s/S. P. Johnson, IV
	President and Chief Executive Officer
	(Principal Executive Officer)



Date: November 6, 2008	By: /s/Paul F. Boling
	Chief Financial Officer
	(Principal Financial and Accounting Officer)

-30-