Edgar Filing: CARRIZO OIL & GAS INC

q10_093010.htm

UNITED STATES

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, 2010

[ ] 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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

YES [ ] NO [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (Check one):

Large accelerated filer [ ] Accelerated filer [X]

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, 2010 was 34,915,988.

CARRIZO OIL & GAS, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2010

INDEX

PART I. FINANCIAL INFORMATION			PAGE

	Item 1.	Consolidated Financial Statements

		Consolidated Balance Sheets
		As of September 30, 2010 (Unaudited) and December 31, 2009	2

		Consolidated Statements of Operations (Unaudited)
		For the three and nine months ended September 30, 2010 and 2009	3

		Consolidated Statements of Cash Flows (Unaudited)
		For the nine months ended September 30, 2010 and 2009	4

		Notes to Consolidated Financial Statements (Unaudited)	5

	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	19

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31

	Item 4.	Controls and Procedures	31


PART II. OTHER INFORMATION

	Items 1-6.		31

SIGNATURES			37

Index

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

	September 30,			December 31,
ASSETS	2010			2009
	(Unaudited)
	(In thousands, except per share amount)
CURRENT ASSETS:
Cash and cash equivalents	$	2,748		$	3,837
Accounts receivable, net
Oil and gas sales		13,988			13,202
Joint interest billing		9,445			4,901
Related party		521			445
Other		879			2,793
Advances to operators		63			540
Fair value of derivative instruments		25,105			8,404
Other current assets		2,544			1,278
Total current assets		55,293			35,400

PROPERTY AND EQUIPMENT, NET
Oil and gas properties using the full-cost method of accounting:
Proved oil and gas properties, net		502,506			399,182
Costs not subject to amortization		442,902			330,607
Land, building and other equipment, net		4,160			3,911
TOTAL PROPERTY AND EQUIPMENT, NET		949,568			733,700
DEFERRED FINANCING COSTS, NET		7,849			9,738
INVESTMENTS		3,341			3,358
FAIR VALUE OF DERIVATIVE INSTRUMENTS		10,662			6,477
DEFERRED INCOME TAX		49,441			70,217
INVENTORY		3,292			3,292
OTHER ASSETS		1,049			925
TOTAL ASSETS	$	1,080,495		$	863,107

LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
Accounts payable, trade	$	30,567		$	19,907
Revenue and royalties payable		27,397			27,390
Current state tax payable		1,989			107
Accrued drilling costs		24,277			17,251
Accrued interest		6,111			1,922
Other accrued liabilities		9,045			11,013
Advances for joint operations		1,344			1,739
Current maturities of long-term debt		160			148
Deferred income tax		6,405			1,474
Other current liabilities		5,033			1,777
Total current liabilities		112,328			82,728

LONG-TERM DEBT, NET OF CURRENT MATURITIES AND DEBT DISCOUNT		584,069			520,188
ASSET RETIREMENT OBLIGATION		4,415			5,410
FAIR VALUE OF DERIVATIVE INSTRUMENTS		-			2,818
OTHER LIABILITIES		4,327			4,354

COMMITMENTS AND CONTINGENCIES

SHAREHOLDERS' EQUITY:
Common stock, par value $0.01 per share (90,000 shares authorized; 34,885 and
31,100 issued and outstanding at September 30, 2010 and
December 31, 2009, respectively)		349			311
Additional paid-in capital		513,606			431,757
Accumulated deficit		(138,672	)		(184,548	)
Accumulated other comprehensive income, net of taxes		73			89
Total shareholders' equity		375,356			247,609
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	1,080,495		$	863,107

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

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Index

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended						For the Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009
	(In thousands, except per share amounts)
REVENUES:
Oil and gas revenues	$	30,502		$	23,584		$	102,380		$	80,186
Other revenues		310			263			1,047			1,035
TOTAL REVENUES		30,812			23,847			103,427			81,221

COSTS AND EXPENSES:
Lease operating		7,117			3,339			18,365			19,598
Production tax		692			640			2,482			(382	)
Ad valorem tax		749			1,234			2,421			3,621
Gas purchases		311			272			1,043			1,139
Depreciation, depletion and amortization		10,369			12,524			31,289			40,049
Impairment of oil and gas properties		-			-			2,731			216,391
General and administrative (inclusive of stock-based compensation expense of
$4,396 and $2,780 for the three months ended September 30, 2010 and 2009, respectively,
and $9,716 and $8,514 for the nine months ended September 30, 2010 and 2009, respectively)		9,879			7,633			24,565			21,894
Accretion expense related to asset retirement obligation		56			79			160			225
TOTAL COSTS AND EXPENSES		29,173			25,721			83,056			302,535
OPERATING INCOME (LOSS)		1,639			(1,874	)		20,371			(221,314	)

OTHER INCOME AND EXPENSES:
Gain (loss) on derivative instruments, net		21,520			(1,986	)		47,536			25,802
Interest expense		(10,403	)		(9,903	)		(30,058	)		(28,617	)
Capitalized interest		5,601			4,996			15,062			15,065
Impairment of investment in Pinnacle Gas Resources, Inc.		-			-			-			(2,091	)
Distribution income - related party		20,793			-			20,793			-
Other income (expense), net		6			(22	)		(15	)		29
INCOME (LOSS) BEFORE INCOME TAXES		39,156			(8,789	)		73,689			(211,126	)
INCOME TAX (EXPENSE) BENEFIT		(14,801	)		3,994			(27,813	)		74,769

NET INCOME (LOSS)	$	24,355		$	(4,795	)	$	45,876		$	(136,357	)

OTHER COMPREHENSIVE INCOME (LOSS), NET OF TAXES:
Increase (decrease) in market value of investment in Pinnacle Gas Resources, Inc., net of taxes		(16	)		64			(16	)		179
Reclassification of cumulative decrease in market value of investment in
Pinnacle Gas Resources, Inc., net of taxes		-			-			-			1,359
COMPREHENSIVE INCOME (LOSS)	$	24,339		$	(4,731	)	$	45,860		$	(134,819	)

BASIC INCOME (LOSS) PER COMMON SHARE	$	0.70		$	(0.15	)	$	1.38		$	(4.40	)

DILUTED INCOME (LOSS) PER COMMON SHARE	$	0.69		$	(0.15	)	$	1.36		$	(4.40	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC		34,730			31,053			33,301			30,980
DILUTED		35,101			31,053			33,724			30,980

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Nine
	Months Ended
	September 30,
	2010			2009
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	45,876		$	(136,357	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities-
Depreciation, depletion and amortization		31,289			40,049
Impairment of oil and gas properties		2,731			216,391
Unrealized (gain) loss on derivative instruments		(24,677	)		36,262
Accretion of discount on asset retirement obligation		160			225
Stock-based compensation		9,716			8,514
Allowance for doutbful accounts		368			288
Deferred income taxes		25,716			(74,834	)
Amortization of deferred financing costs and equity premium associated with
Convertible Senior Notes		7,144			6,162
Impairment of investment in Pinnacle Gas Resources, Inc.		-			2,091
Other		1,789			5,248
Changes in operating assets and liabilities-
Accounts receivable		(3,860	)		3,158
Accounts payable		1,322			(2,053	)
Accrued liabilities		2,328			4,242
Other, net		(270	)		(1,548	)
Net cash provided by operating activities		99,632			107,838

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(261,341	)		(143,036	)
Change in capital expenditure accruals		17,404			(21,309	)
Proceeds from the sale of oil and gas properties		15,042			6
Advances to operators		477			12
Advances for joint operations		(395	)		1,859
Other		(445	)		(69	)
Net cash used in investing activities		(229,258	)		(162,537	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		245,600			100,037
Debt repayments		(191,000	)		(43,886	)
Proceeds from common stock offering, net of offering costs		73,814			-
Proceeds from stock options exercised		667			9
Payments of financing costs and other		(544	)		(3,069	)
Net cash provided by financing activities		128,537			53,091

DECREASE IN CASH AND CASH EQUIVALENTS		(1,089	)		(1,608	)

CASH AND CASH EQUIVALENTS, beginning of period		3,837			5,184
CASH AND CASH EQUIVALENTS, end of period	$	2,748		$	3,576

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

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CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.	NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Carrizo Oil & Gas, Inc. is an independent energy company which, together with its subsidiaries (collectively referred to herein as the “Company”), is engaged in the exploration, development, production and transportation of natural gas and oil, principally in the United States. The Company’s current operations are principally focused in proven, producing natural gas plays known as “shale plays” or “resource plays.” The Company’s primary core area is the Barnett Shale area, with a focus in Southeast Tarrant County, Texas. The Company has also established a significant position in the Marcellus Shale area in Pennsylvania, New York and West Virginia. In addition to the Barnett and the Marcellus plays, the Company’s current focus areas include the Eagle Ford Shale in South Texas, the Niobrara formation in Colorado and the Huntington Field located in the U.K. North Sea.

Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles. The consolidated 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 (the “SEC”). The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading. The consolidated financial statements included herein should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2009.

Unconsolidated Investments

The Company accounts for its investment in Pinnacle Gas Resources, Inc. as available-for-sale and adjusts the book value to fair value through other comprehensive income (loss), net of taxes. This fair value is assessed quarterly for other than temporary impairment based on publicly available information. If the impairment is deemed other than temporary, it is recognized in earnings. Subsequent recoveries in fair value are reflected as increases to investments and other comprehensive income (loss), net of taxes.

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.

Reclassifications

Certain reclassifications have been made to prior period amounts to conform to the current period presentation. These reclassifications had no effect on total assets, total liabilities, shareholders’ equity, net income (loss), comprehensive income (loss) or net cash provided by/used in operating, investing or financing activities.

Use of Estimates

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

Significant estimates include volumes of oil and gas reserves used in calculating depletion of proved oil and gas properties, future net revenues and abandonment obligations, impairment of unproved properties, future taxable income and related income tax assets and liabilities, the collectability of outstanding accounts receivable, fair values of derivative instruments, stock-based compensation, contingencies and the results of current and future litigation. Oil and gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality and quantity of available data and the application of engineering and geological interpretation and judgment to available data. Subsequent drilling results, testing and production may justify revisions of such estimates. Accordingly, reserve estimates are often

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different from the quantities of oil and gas that are ultimately recovered. In addition, reserve estimates are vulnerable to changes in prices of oil and 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 gas, the credit worthiness of counterparties, interest rates, the market value and volatility of the Company’s common stock and the Company’s ability to generate future taxable income. Future changes in these assumptions may affect these significant estimates materially in the near term. The Company has evaluated subsequent events for recording and disclosures, including assumptions used in its estimates.

Oil and Gas Properties

Investments in oil and 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 gas properties are capitalized. Such costs include lease acquisitions, seismic surveys, and drilling and completion equipment. The Company proportionately consolidates its interests in unincorporated joint ventures and oil and gas properties. The Company capitalized employee-related costs for employees working directly on acquisition, exploration and development activities of $1.4 million and $1.1 million for the three months ended September 30, 2010 and 2009, respectively, and $4.2 million and $4.1 million for the nine months ended September 30, 2010 and 2009, respectively. Maintenance and repairs are expensed as incurred.

Depreciation, depletion and amortization (“DD&A”) of proved oil and gas properties is based on the unit-of-production method using estimates of proved reserve quantities. The depletable base includes estimated future development costs and dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per Mcfe for the three months ended September 30, 2010 and 2009 was $1.17 and $1.50, respectively, and for the nine months ended September 30, 2010 and 2009 was $1.16 and $1.62, respectively. Under the full-cost method of accounting, the depletion rate is the current period production as a percentage of the total proved oil and gas reserves. Total proved reserves include both proved developed and proved undeveloped reserves. The depletion rate is applied to the net book value of the oil and gas properties (excluding unproved properties, capitalized interest and exploratory wells in progress) and estimated future development costs less salvage value to calculate the depletion expense.

Costs not subject to amortization include costs of unproved properties (which consists of unevaluated leaseholds and seismic costs associated with specific unevaluated properties), capitalized interest and exploratory wells in progress. These costs 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 added to the proved oil and gas property costs subject to DD&A and the full-cost ceiling test. Factors considered by management in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production, production response to secondary activities, drilling plans and available funds for exploration and development. The Company expects it will complete its evaluation of the properties representing the majority of its unproved property costs within the next two to five years. The Company capitalized interest costs associated with its unproved properties of $5.6 million and $5.0 million for the three months ended September 30, 2010 and 2009, respectively, and $15.1 million for the nine months ended September 30, 2010 and 2009.

Dispositions of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments significantly alter the relationship between capitalized costs and proved reserves. The Company has not had any transactions that significantly alter that relationship.

Capitalized costs, less accumulated amortization and related deferred income taxes, are limited to a “ceiling-test” based on the estimated future net revenues based on average market prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period, discounted at 10% per annum, from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. If net capitalized costs exceed this limit, the excess is charged to earnings. Prices used in the ceiling test computation do not include the impact of derivative instruments as the Company does not designate its derivative instruments as a cash flow hedge.

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

Investment in ACP II and Distribution Income-Related Party

The Company owns a profit interest (“B Units”) in ACP II Marcellus, LLC (“ACP II”), the Company’s existing joint venture partner in the Marcellus Shale and an affiliate of Avista Capital Partners, LP, a private equity fund (together with its affiliates, “Avista”). The B Units, which were issued to the Company in connection with the formation of the joint venture with Avista in 2008, entitle the

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Company to receive increasing percentages of the cash distributions to Avista that exceed certain internal rates-of-return and return–on-investment thresholds. The B Units provide consent rights only in limited, specified circumstances and generally do not entitle the Company to vote or participate in the management of ACP II, which is controlled by Avista. Steven A. Webster, Chairman of the Company’s Board of Directors, also serves as Co-Managing Partner and President of Avista. Cash distributions received on the Company’s B Units are treated as distributions on the Company’s investment in ACP II and are recognized as Distribution Income-Related Party when ACP II declares and pays cash distributions to Avista.

Stock-Based Compensation

The Company grants stock options, stock appreciation rights (“SARs”) and restricted stock to directors, employees and independent contractors.

For stock options, including SARs that the Company expects to settle in common stock (“Stock SARs”), compensation expense is based on the grant-date fair value and expensed over the vesting period (generally three years) using the straight-line method, except for awards with performance conditions, in which case the Company uses the graded vesting method. Stock options typically expire ten years after the date of grant. SARs expire seven years after the date of grant. Stock SARs allow the Company to elect whether to settle the Stock SARs in cash or common stock. For SARs that settle in cash (“Cash SARs”) and Stock SARs that the Company expects to settle in cash, the liability is adjusted to fair value at each reporting period date and amortized to expense over the vesting period and is classified as other accrued liabilities for the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder classified as other long-term liabilities.

For restricted stock, the Company measures deferred compensation based on the average of the high and low price of the Company’s stock on the grant date. The deferred compensation is amortized to expense over the vesting period of the restricted stock (generally one to three years), using the straight-line method, except for awards with performance conditions, in which case the Company uses the graded vesting method. Restricted stock issued to independent contractors is adjusted to fair value at each reporting period date and amortized to expense over the vesting period.

The Company recognized the following stock-based compensation expense for the periods indicated, which are reflected as general and administrative expense in the accompanying consolidated statements of operations:

	Three Months				Nine Months
	Ended September 30,				Ended September 30,
	2010		2009		2010		2009
	(In thousands)
Stock Options and SARs	$	1,675	$	286	$	2,196	$	357
Restricted Stock		2,721		2,494		7,520		8,157
Total Stock-Based Compensation	$	4,396	$	2,780	$	9,716	$	8,514

Prior to July 2010, the Company expected the Stock SARs granted in June 2009 to settle in common stock. In July 2010, the Company elected to settle those Stock SARs in cash upon exercise. As a result, the Company recognized a fair value liability for those awards at September 30, 2010, along with related compensation expense.

Derivative Instruments

The Company uses derivative instruments, typically fixed-rate swaps, costless collars, puts, calls and basis swaps, to manage price risk underlying its oil and gas production. All derivative instruments are recorded in the consolidated balance sheets at fair value. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty. Although the Company does not designate any of its derivative instruments as a cash flow hedge, such derivative instruments provide an economic hedge of our exposure to commodity price risk associated with forecasted oil and gas production. These contracts are accounted for using the mark-to-market accounting method and accordingly, the Company recognizes all unrealized and realized gains and losses related to these contracts currently in earnings and are classified as gain (loss) on derivative instruments. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty.

The Company’s Board of Directors sets all risk management policies and reviews the status and results of derivative activities, including volumes, types of instruments and counterparties on a quarterly basis. These policies require that derivative instruments be executed only by the President or Chief Financial Officer after consultation 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

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the only Company representatives authorized to execute trades. See Note 9., “Derivative Instruments” for further discussion of the Company’s derivative instruments.

Accounts Receivable and Allowance for Doubtful Accounts

At September 30, 2010 and December 31, 2009, the Company had related party receivables of $0.5 million and $0.4 million, respectively, with ACP II.

The Company establishes provisions for losses on accounts receivable when it determines that it will not collect all or a part of the outstanding balance. The Company reviews collectability quarterly and adjusts the allowance as necessary using the specific identification method. At September 30, 2010 and December 31, 2009, the Company’s allowance for doubtful accounts was $2.4 million and $2.0 million, respectively.

Earnings Per Share

Supplemental earnings per share information is provided below:

	Three Months					Nine Months
	Ended September 30,					Ended September 30,
	2010		2009			2010		2009
	(In thousands, except
	per share amounts)
Net income (loss)	$	24,355	$	(4,795	)	$	45,876	$	(136,357	)

Average common shares outstanding
Weighted average common shares outstanding		34,730		31,053			33,301		30,980
Restricted stock, stock options and SARs		371		-			423		-
Diluted weighted average common shares outstanding		35,101		31,053			33,724		30,980

Net income (loss) per common share
Basic	$	0.70	$	(0.15	)	$	1.38	$	(4.40	)
Diluted	$	0.69	$	(0.15	)	$	1.36	$	(4.40	)

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 outstanding and all dilutive potential common shares outstanding during the periods. The Company excluded 67,562 and 74,738 shares related to restricted stock, stock options and SARs from the calculation of dilutive shares for the three months and nine months ended September 30, 2010, respectively, because the grant prices were greater than the average market prices of the common shares for the periods and would be antidilutive to the computations. The Company excluded 893,837 shares related to stock options and SARs from the calculation of dilutive shares for the three months and nine months ended September 30, 2009 due to the net loss reported in the periods. Shares of common stock subject to issuance pursuant to the conversion features of the 4.375% convertible senior notes due 2028 did not have an effect on the calculation of dilutive shares for the three months and nine months ended September 30, 2010 and 2009.

Income Taxes

Deferred income taxes are recognized at each reporting period for the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts based on tax laws and statutory tax rates applicable to the periods in which the differences are expected to affect taxable income. The Company routinely assesses the realizability of its deferred tax assets and considers future taxable income based upon the Company’s estimated production of proved reserves at estimated future pricing in making such assessments. If the Company concludes that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the deferred tax assets are reduced by a valuation allowance.

Recently Adopted Accounting Pronouncements

A standard to improve disclosures about fair value measurements was issued by the Financial Accounting Standards Board (the “FASB”) in January 2010. The additional disclosures required include: (1) the different classes of assets and liabilities measured at fair value, (2) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (3) the gross presentation of purchases, sales, issuances and settlements for the rollforward of

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Level 3 activity and (4) the transfers in and out of Levels 1 and 2. The Company adopted the new disclosures in the first quarter of 2010.

2.	INVESTMENTS

Investments consisted of the following at September 30, 2010 and December 31, 2009:

	September 30,		December 31,
	2010		2009
	(In thousands)
Pinnacle Gas Resources, Inc.	$	818	$	835
Oxane Materials, Inc.		2,523		2,523
	$	3,341	$	3,358

Pinnacle Gas Resources, Inc.

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

At March 31, 2009, the market value of the Company’s investment in Pinnacle had consistently remained below its original book basis since October 2008. The Company determined that the impairment was other than temporary and, accordingly, recorded an impairment of $2.1 million at March 31, 2009. At September 30, 2010, the Company owned 2,555,825 shares of Pinnacle common stock and reported the fair value of the stock at $0.8 million (based on $0.33 per share, the closing price of Pinnacle’s common stock on September 30, 2010).

On February 23, 2010, Pinnacle entered into an Agreement and Plan of Merger (the “Merger Agreement”) with affiliates of Scotia Waterous (USA), Inc. At the closing of the transactions contemplated by the Merger Agreement, Pinnacle is expected to be owned by an investor group led by Scotia Waterous (USA), Inc., which includes DLJ Merchant Banking Partners III, L.P. and affiliated investment funds and certain members of Pinnacle’s management team. Subject to the terms and conditions of the Merger Agreement, at the effective time and as a result of the Merger, each outstanding share of Pinnacle common stock, (other than dissenting shares and those owned by the buyers and affiliates) will be converted into the right to receive a cash amount of $0.34 per share. The merger is expected to be completed during the fourth quarter of 2010.

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 accrued interest at a rate of 6% per annum. During the fourth quarter of 2008, the Company converted the promissory note into 630,371 shares of Oxane preferred stock.

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Index

3.	PROPERTY AND EQUIPMENT, NET

At September 30, 2010 and December 31, 2009, property and equipment, net consisted of the following:

	September 30,			December 31,
	2010			2009
	(In thousands)
Proved oil and gas properties	$	801,685		$	667,907
Costs not subject to amortization:
Unevaluated leaseholds and seismic costs		325,086			258,300
Capitalized interest		43,166			34,563
Exploratory wells in progress		74,650			37,744
Land, building and other equipment		7,332			6,475
Total property and equipment		1,251,919			1,004,989
Accumulated depreciation, depletion and amortization		(302,351	)		(271,289	)
Total property and equipment, net	$	949,568		$	733,700

In June 2010, the Company concluded that it was uneconomical to pursue development on the license covering the Monterey field in the U.K. North Sea and terminated further development efforts resulting in a full-cost ceiling test impairment of $2.7 million ($1.8 million after-tax) for the nine months ended September 30, 2010 with respect to the U.K. cost center. For the nine months ended September 30, 2009, the Company incurred a full cost-ceiling test impairment of $216.4 million ($140.6 million net of tax) with respect to the U.S. cost center. To measure the full-cost ceiling test impairment for the first quarter of 2009, the Company elected to use a pricing date subsequent to the balance sheet date, as allowed by SEC guidelines in effect at the time. Using prices as of May 6, 2009, the Company incurred a full-cost ceiling test impairment of $216.4 million ($140.6 million net of tax). Had the Company used prices in effect as of March 31, 2009, a full cost ceiling test impairment of $323.2 million ($210.1 million net of tax) would have been recorded for the first quarter of 2009. The option to use a pricing date subsequent to the balance sheet date is no longer available to the Company due to the adoption of the new oil and gas reporting requirements effective December 31, 2009.

4.	INCOME TAXES

The Company computes quarterly income taxes under the effective tax rate method based on applying an anticipated annual effective income tax rate to the year-to-date income (loss), except for discrete items. Income taxes for discrete items are computed and recorded in the period that the specific transaction occurs. Actual income tax (expense) benefit differs from income tax (expense) benefit computed by applying the U.S. federal statutory corporate rate of 35% to pretax income (loss) as follows:

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2010			2009		2010			2009
	(In thousands)
(Expense) benefit at the statutory rate	$	(13,704	)	$	3,076	$	(25,791	)	$	73,894
State and local income tax expense,
net of federal benefit		(1,115	)		109		(2,463	)		2,618
Other		18			809		441			(1,743	)
Total income tax (expense) benefit	$	(14,801	)	$	3,994	$	(27,813	)	$	74,769

At September 30, 2010, the Company had a net deferred tax asset of $43.0 million. The Company has determined it is more likely than not that its deferred tax assets are fully realizable based on projections of future taxable income which included estimated production of proved reserves at estimated future pricing. No valuation allowance for the net deferred tax asset is currently needed.

The Company classifies interest and penalties associated with income taxes as interest expense. At September 30, 2010, the Company had no material uncertain tax positions and the tax years since 1999 remain open to review by federal and various state tax jurisdictions.

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Index

DEBT

Debt consisted of the following at September 30, 2010 and December 31, 2009:

	September 30,			December 31,
	2010			2009
	(In thousands)
Convertible Senior Notes	$	373,750		$	373,750
Unamortized discount for Convertible Senior Notes		(35,681	)		(45,122	)
Senior Secured Revolving Credit Facility		246,000			191,400
Other		160			308
		584,229			520,336
Less: Current maturities		(160	)		(148	)
	$	584,069		$	520,188

Convertible Senior Notes

In May 2008, the Company issued $373.8 million aggregate principal amount of 4.375% convertible senior notes due 2028 (the “Convertible Senior Notes”). Interest is payable on June 1 and December 1 each year. The notes are convertible, using a net share settlement process, into a combination of cash and Company common stock that entitles holders of the Convertible Senior Notes to receive cash up to the principal amount ($1,000 per note) and common stock in respect of the remainder, if any, of the Company’s conversion obligation in excess of such principal amount.

The notes are convertible into the Company’s common stock at a ratio of 9.9936 shares per $1,000 principal amount of notes, equivalent to a conversion price of approximately $100.06. This conversion rate is subject to adjustment upon certain corporate events. In addition, if certain fundamental changes occur on or before June 1, 2013, the Company will in some cases increase the conversion rate for a holder electing to convert notes in connection with such fundamental change; provided, that in no event will the total number of shares issuable upon conversion of a note exceed 14.7406 per $1,000 principal amount of notes (subject to adjustment in the same manner as the conversion rate).

Holders may convert the notes only under the following conditions: (a) during any calendar quarter if the last reported sale price of the Company’s common stock exceeds 130 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 the Company’s common stock are made or specified corporate transactions occur, (d) prior to the close of business on the business day preceding the redemption date if the notes are called for redemption or (e) on or after March 31, 2028 and prior to the close of business on the business day prior to the maturity date of June 1, 2028.

The holders of the Convertible Senior Notes may require the Company to repurchase the notes on June 1, 2013, 2018 and 2023, or upon a fundamental corporate change at a repurchase price in cash equal to 100 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 subject to customary non-financial covenants and events of default, including a cross default under the Senior Credit Facility (defined below), the occurrence and continuation of which could result in the acceleration of amounts due under the Convertible Senior Notes.

The Convertible Senior Notes are unsecured obligations of the Company and rank equal to all future senior unsecured debt but rank second in priority to the Senior Credit Facility.

The Company valued the Convertible Senior Notes at May 21, 2008, as $309.6 million of debt and $64.2 million of equity representing the fair value of the conversion premium. The resulting debt discount is being amortized to interest expense through June 1, 2013, the first date on which the holders may require the Company to repurchase the Convertible Senior Notes, resulting in an effective interest rate of approximately 8% for the Convertible Senior Notes. Amortization of the debt discount amounted to $3.2 million and $3.1 million for the three months ended September 30, 2010 and 2009, respectively, and $9.4 million and $9.1 million for the nine months ended September 30, 2010 and 2009, respectively.

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Index

Subsequent to September 30, 2010, the Company commenced a tender offer for up to $300 million of the Convertible Senior Notes, as discussed in Note 13., “Subsequent Events.”

Senior Secured Revolving Credit Facility

The Company has a senior secured revolving credit facility (the “Senior Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent. The Senior Credit Facility provides for a revolving credit facility up to the lesser of the borrowing base or $375.0 million. It is secured by substantially all of the Company’s proved oil and gas assets and is currently guaranteed by certain of the Company’s subsidiaries: CCBM, Inc.; CLLR, Inc.; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC, Carrizo Marcellus Holding, Inc.; Hondo Pipeline, Inc.; Bandelier Pipeline Holding, LLC, Chama Pipeline Holding LLC, and Mescalero Pipeline, LLC. The Senior Credit Facility matures on October 29, 2012, and is subject to semi-annual borrowing base redeterminations as of March 31 and September 30.

In April 2009, the Company amended the Senior Credit Facility to, among other things, (1) adjust the maximum ratio of total net debt to Consolidated EBITDA (as defined in the Senior Credit Facility); (2) modify the calculation of total net debt for purposes of determining the ratio of total net debt to Consolidated EBITDA to exclude the following amounts, which represent a portion of the Convertible Senior Notes deemed to be an equity component that may be settled in cash (including partial cash settlement) upon conversion: $51.3 million during 2009, $38.9 million during 2010, $26.0 million during 2011 and $12.7 million during 2012 until the maturity date; (3) add a new senior leverage ratio; (4) modify the interest rate margins applicable to Eurodollar loans; (5) modify the interest rate margins applicable to base rate loans; and (6) establish new procedures governing the modification of swap agreements.

In May 2009, the Company amended the Senior Credit Facility to, among other things, (1) provide that the aggregate notional volume of oil and gas subject to swap agreements may not exceed 80% of “forecasted production from proved producing reserves,” (as that term is defined in the Senior Credit Facility), for any month, (2) remove a provision that limited the maximum duration of swap agreements permitted under the Senior Credit Facility to five years, and (3) provide that the aggregate notional amount under interest rate swap agreements may not exceed the amount of borrowings then outstanding under the Senior Credit Facility.

In May 2010, the Company amended the Senior Credit Facility to increase the borrowing base to $375 million from $350 million.

If the outstanding principal balance of the revolving loans under the Senior Credit Facility exceeds the borrowing base at any time, the Company has the option within 30 days to take any of the following actions, either individually or in combination: make a lump sum payment curing the deficiency, pledge additional collateral sufficient in the lenders’ opinion to increase the borrowing base and cure the deficiency or begin making equal monthly principal payments that will cure the deficiency within the ensuing six-month period. Those payments would be in addition to any payments that may come due as a result of the quarterly borrowing base reductions. Otherwise, any unpaid principal or interest will be due at maturity.

The annual interest rate on each base rate borrowing is (a) the greatest of the agent’s Prime Rate, the Base CD Rate plus 1.0% and the Federal Funds Effective Rate plus 0.5%, plus (b) a margin between 1.00% and 2.00% (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 2.25% to 3.25% (depending on the current level of borrowing base usage). The interest rate on each Eurodollar loan will be the adjusted daily LIBO rate plus a margin between 2.25% to 3.25% (depending on the then-current level of borrowing base usage). At September 30, 2010, the average interest rate for amounts outstanding under the Senior Credit Facility was 3.1%.

Subsequent to September 30, 2010, the Company amended its Senior Credit Facility, as discussed in Note 13., “Subsequent Events” and the following description does not reflect such amendment. The Company is subject to certain covenants under the amended terms of the Senior Credit Facility which include, but are not limited to, the maintenance of the following financial ratios: (1) a minimum current ratio of 1.00 to 1.00 (as defined in the Senior Credit Facility); and (2) a maximum total net debt (which excludes certain amounts attributable to the Convertible Senior Notes) to Consolidated EBITDA (as defined in the Senior Credit Facility) of (a) 4.75 to 1.00 for each quarter ending on or after December 31, 2009 and on or before September 30, 2010, (b) 4.25 to 1.00 for the quarter ending December 31, 2010, and (c) 4.00 to 1.00 for each quarter ending on or after March 31, 2011; and (3) a maximum ratio of senior debt (which excludes certain amounts attributable to the Convertible Senior Notes) to Consolidated EBITDA of 2.25 to 1.00. As defined in the Senior Credit Facility, the current ratio was 1.56 to 1, the total net debt to Consolidated EBITDA ratio was 4.01 to 1 and the ratio of senior debt to Consolidated EBITDA ratio was 1.71 to 1 as of September 30, 2010. Because the calculation of the financial ratios are made as of a certain date, the financial ratios can fluctuate significantly period to period as the amounts outstanding under the Senior Credit Facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings.

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Index

The Senior Credit Facility also places restrictions on indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of our common stock, swap agreements, transactions with affiliates and other matters.

The Senior Credit Facility is subject to customary events of default, the occurrence and continuation of which could result in the acceleration of amounts due under the facility by the agent or the lenders.

At September 30, 2010, the Company had $246.0 million of borrowings outstanding under the Senior Credit Facility. We have also issued $4.1 million of letters of credit which reduce the amounts available under the Senior Credit Facility. Future availability under our $375.0 million borrowing base is subject to the terms and covenants of the Senior Credit Facility. The Senior Credit Facility is used to fund ongoing working capital needs and the remainder of the Company’s capital expenditure plan only to the extent such amounts exceed the cash flow from operations, proceeds from the sale of oil and gas properties and securities offerings.

6.	ASSET RETIREMENT OBLIGATION

The following is a rollforward of the asset retirement obligation:

	Nine Months Ended			Year Ended
	September 30,			December 31,
	2010			2009
	(In thousands)
Asset retirement obligation at beginning of period	$	5,410		$	6,503
Liabilities incurred		125			444
Liabilities settled		(80	)		(36	)
Accretion expense		160			308
Revisions of previous estimates		(1,200	)		(1,809	)
Asset retirement obligation at end of period	$	4,415		$	5,410

The revisions of previous estimates relate primarily to increases in the estimated life of wells in the Barnett Shale and the reduction of estimated obligations in the U.K. North Sea.

7.	COMMITMENTS AND CONTINGENCIES

From time to time, the Company is party to certain legal actions and claims arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not currently expect these matters to have a material adverse effect on the financial position or results of operations of the Company.

The financial position and results of operations 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 gas production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable.

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Index

8.	SHAREHOLDERS’ EQUITY

The following is a rollforward of the Company’s shares outstanding:

	Nine Months
	Ended September 30,
	2010		2009
	(In thousands)
Shares outstanding at January 1		31,100		30,860
Common stock offering		3,220		-
Restricted stock awards, net of forfeitures		303		179
Stock options exercised for cash		262		5
Other		-		10
Shares outstanding at September 30		34,885		31,054

In April 2010, the Company sold 3.22 million shares of its common stock in an underwritten public offering at a price of $23.00 per share. The Company received proceeds of approximately $73.8 million, which were used to repay a portion of the outstanding borrowings under the Senior Credit Facility.

On November 24, 2009, the Company entered into a Land Agreement, as amended (the “Land Agreement”), with an unrelated third party and its affiliate. Under this arrangement, the Company may until May 31, 2011 acquire up to $20 million of oil, gas and mineral interests/leases in certain specified areas in the Barnett Shale from the third party. In consideration of the Company’s receipt of an option to purchase the leases acquired by the third party, each time the third party purchases a lease group under the Land Agreement, if any, the Company will issue to the third party’s affiliate warrants to purchase a number of shares of the Company’s common stock equal to the quotient of (rounded up to the nearest whole number) (1) 20% of the purchase price of such lease group divided by (2) $13.00, with an exercise price of $22.09 and an expiration date of August 21, 2017. In addition, under certain circumstances where the Company reaches surface casing point on an initial well in one of the areas covered by the Land Agreement but has not achieved a specified lease up threshold for acreage in such area, the Company will issue additional warrants, on the same terms, to purchase a number of shares of the Company’s stock equal to the quotient (rounded up to the nearest whole number) of (1) 20% of the product of (A) the number of acres below the specified lease up threshold multiplied by (B) $5,000, divided by (2) $13.00. The warrants are subject to antidilution adjustments and may be exercised on a “cashless” basis.

On September 13, 2010, the Company issued warrants to purchase 48,385 shares of the Company’s common stock to the third party’s affiliate in connection with purchases of leases by the third party under the Land Agreement.

9.	DERIVATIVE INSTRUMENTS

The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in its forward cash flows supporting its capital investment program. The commodity derivative instruments typically used are fixed-rate swaps, costless collars, puts, calls and basis swaps. The Company’s current long-term strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to 36 months. The derivative instruments are carried at fair value in the consolidated balance sheets, with the changes in fair value included in the consolidated statements of operations for the period in which the changes occur.

Under these derivative instruments, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at termination, expiration or exchanged for physical delivery contracts. The Company enters into the majority of its derivative transactions with three counterparties and netting agreements are in place with those counterparties. The Company does not obtain collateral to support the agreements but monitors the financial viability of counterparties and believes its credit risk is minimal on these transactions. In the event of nonperformance, the Company would be exposed to price and credit risk. The Company had not required its counterparties to post collateral at September 30, 2010 and December 31, 2009.

The following sets forth a summary of our natural gas derivative positions at average delivery location (Waha and Houston Ship Channel) prices as of September 30, 2010. Our crude oil derivative positions at September 30, 2010, were not significant.

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Index

			Weighted		Weighted
			Average		Average
	Volume		Floor Price		Ceiling Price
Period	(in MMbtu)		($/MMbtu)		($/MMbtu)
2010		6,716,000	$	5.76	$	6.32
2011		21,340,000	$	6.12	$	6.49
2012		7,963,000	$	6.53	$	7.03

In connection with the derivative instruments above, the Company has entered into protective put spreads. When the market price declines below the short put price as reflected below, the Company will effectively receive the market price plus a put spread. For example, for the remainder of 2010, if market prices fall below the short put price of $4.11, the floor price becomes the market price plus the put spread of $1.65 on 5,209,000 of the 6,716,000 MMBtus and the remaining 1,507,000 MMBtus have a floor price of $5.76.

			Weighted		Weighted
			Average		Average
	Volume		Short Put Price		Put Spread
Period	(in MMbtu)		($/MMbtu)		($/MMbtu)
2010		5,209,000	$	4.11	$	1.65
2011		16,799,000	$	4.29	$	1.83
2012		6,404,000	$	4.47	$	2.06

For the three months and nine months ended September 30, 2010 and 2009, the Company recorded the following related to its derivative instruments:

	Three Months					Nine Months
	Ended September 30,					Ended September 30,
	2010		2009			2010		2009
	(In thousands)
Realized gain	$	9,111	$	16,038		$	22,859	$	62,064
Unrealized gain (loss)		12,409		(18,024	)		24,677		(36,262	)
Gain (loss) on derivative instruments, net	$	21,520	$	(1,986	)	$	47,536	$	25,802

The Company deferred the payment of premiums associated with certain of its derivative instruments totaling $5.4 million and $4.8 million at September 30, 2010 and December 31, 2009, respectively. The Company classified $4.3 million and $1.8 million as other current liabilities at September 30, 2010 and December 31, 2009, respectively, and $1.1 million and $3.0 million as other non-current liabilities at September 30, 2010 and December 31, 2009, respectively. These deferred premiums will be paid to the counterparty with each monthly settlement (October 2010 – December 2011) and recognized as a reduction of realized gain on derivative instruments.

The fair value of derivative instruments at September 30, 2010 and December 31, 2009 was a net asset of $35.8 million and $12.1 million, respectively. At September 30, 2010, approximately 81% of the fair value of the Company’s derivative instruments were with Credit Suisse, 15% were with Shell Energy North America (US) LP, and the remaining 4% were with Credit Agricole.

10.	FAIR VALUE MEASUREMENTS

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

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

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

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Index

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.

The following presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of September 30, 2010 and December 31, 2009, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

	September 30, 2010								December 31, 2009
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
	(in thousands)
Assets:
Investment in Pinnacle
Gas Resources, Inc.	$	818	$	-	$	-	$	818	$	835	$	-	$	-	$	835
Derivative instruments		-		65,213		-		65,213		-		48,192		-		48,192
Liabilities:
Derivative instruments		-		29,446		-		29,446		-		36,129		-		36,129

Total	$	818	$	35,767	$	-	$	36,585	$	835	$	12,063	$	-	$	12,898

The derivative assets and liabilities above are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in our consolidated balance sheets.

Derivatives instruments are valued by industry-standard valuation 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. We had no transfers in or out of Levels 1 or 2 for the nine months ended September 30, 2010.

Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and debt. The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate fair value due to the highly liquid nature or short-term nature of these instruments. The fair values of the borrowings under the Senior Credit Facility approximate the carrying amounts as of September 30, 2010 and December 31, 2009, and were determined based upon interest rates currently available to the Company for borrowings with similar terms. The fair value of the Convertible Senior Notes at September 30, 2010 and December 31, 2009 was estimated at approximately $345.7 million and $321.7 million, respectively, based on a quote provided by an investment bank.

11.	MARCELLUS SHALE JOINT VENTURE

On September 10, 2010, the Company completed the sale of 20% of its interests in oil and gas properties in parts of Pennsylvania in the Marcellus Shale to Reliance Marcellus II, LLC (“Reliance”), a wholly-owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited for $13.1 million in cash and a commitment to pay 75% of certain of our future development costs of up to approximately $52 million. The Company received $11.9 million during the third quarter and expects to receive the remaining $1.2 million pending completion of land and title matters. The proceeds were recognized as a reduction to proved oil and gas properties, net and 20% of the unevaluated leaseholds and seismic costs associated with these properties (approximately $13.3 million) were transferred to proved oil and gas properties, net. A portion of the proceeds received by the Company in this transaction was used to repay borrowings under the Senior Credit Facility.

Simultaneous with this transaction, the Company and Reliance also entered into agreements to form a new joint venture with respect to the interests being purchased by Reliance from the Company and Avista as described below. The new Carrizo/Reliance joint venture agreement covers approximately 104,400 net acres in northern and central Pennsylvania. Under the terms of the agreement, the Company generally retained a 40% working interest in the acreage and Reliance generally acquired a 60% working interest. In addition to funding its own share of future development obligations, Reliance agreed to fund 75% of the Company’s portion of these costs until September 2012 or until the earlier full utilization of the up to $52 million development carry, subject to certain conditions and extensions.

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Index

12.	RELATED PARTY TRANSACTIONS

Simultaneous with the closing of the Marcellus shale joint venture transactions discussed above, the Company’s existing joint venture partner in the Marcellus Shale, ACP II closed the sale of its entire interest in the same oil and gas properties to Reliance for a purchase price of approximately $327 million. The Company and Avista amended the participation agreement that governs the joint venture to provide that the proceeds from the sales of the Company’s and Avista’s properties to Reliance would be allocated separately from other properties subject to the joint venture. The parties also agreed that profit interest distributions to the Company with respect to Avista’s sale of properties to Reliance would be principally based upon the return on investment and internal rates of return associated with such properties. In connection with the closing of the transactions with Reliance, on September 10, 2010, the Company and Avista further amended the participation agreement and other joint venture agreements with Avista to provide that the properties that the Company and Avista sold to Reliance, as well as the properties the Company commits to the new joint venture with Reliance, are not subject to the terms of the Avista joint venture, and that the Avista joint venture’s area of mutual interest will generally not include Pennsylvania, in which those properties are located. Our Marcellus joint venture with Avista continues and now covers approximately 147,000 net acres, primarily in West Virginia and New York.

During the third quarter, the Company received cash distributions of $20.8 million on its B Unit investment in ACP II as a result of ACP II’s distribution of Reliance sale proceeds to Avista. These cash distributions were recognized as Distribution Income-Related Party in the accompanying consolidated statements of operations. A portion of the proceeds received by the Company in this transaction was used to repay borrowings under our Senior Credit Facility.

Steven A. Webster, Chairman of the Company’s Board of Directors, also serves as Co-Managing Partner and President of 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.

13.	SUBSEQUENT EVENTS

On October 13, 2010, the Company received an additional $0.3 million from Reliance pursuant to the purchase and sale agreement and an additional $1.4 million in cash distributions from ACP II.

On October 21, 2010, the Company amended the Senior Credit Facility to permit the offering and issuance of the senior notes described below and the tender offer of the Convertible Senior Notes described below. The amendment also added restrictions on the Company’s ability to repurchase any senior notes issued in the senior notes offering and to make certain amendments to the terms of any senior notes issued in the senior notes offering, and added further restrictions on the Company’s ability to purchase the Convertible Senior Notes (other than pursuant to the tender offer described below).

In addition, the amendment to the Senior Credit Facility amended certain financial covenants in the credit agreement for the Senior Credit Facility. Specifically, from and after the date on which the senior notes offering closed, the Company is required to maintain: (1) a minimum current ratio of 1.00 to 1.00 (as defined in the Senior Credit Facility); and (2) a maximum total net debt (which excludes certain amounts attributable to the Convertible Senior Notes) to Consolidated EBITDA (as defined in the Senior Credit Facility) of (a) 4.75 to 1.00 for the fiscal quarter ending on September 30, 2010, (b) 4.25 to 1.00 for the fiscal quarters ending on or after December 31, 2010 and on or before June 30, 2011, (c) 4.50 to 1.00 for the fiscal quarters ending on or after September 30, 2011 and on or before December 31, 2011, and (d) 4.00 to 1.00 for each fiscal quarter ending on or after March 31, 2012; and (3) a maximum ratio of senior debt (which excludes the aggregate principal amount of the senior notes and the Convertible Senior Notes) to Consolidated EBITDA of (a) 2.25 to 1.00 for the fiscal quarters ending on or after September 30, 2010 and on or before June 30, 2011, (b) 2.50 to 1.00 for the fiscal quarters ending on or after September 30, 2011 and on or before December 31, 2011 and (c) 2.25 to 1.00 for each fiscal quarter ending on or after March 31, 2012. Because the calculation of the financial ratios are made as of a certain date, the financial ratios can fluctuate significantly period to period as the amounts outstanding under the Senior Credit Facility are dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings.

The amendment also provided that, upon the issuance of senior notes pursuant to the senior notes offering, the Company must repay all outstanding amounts under the Senior Credit Facility. Furthermore, the amendment provided that, on the date that the Company purchases any Convertible Senior Notes pursuant to the tender offer, the borrowing base under the Senior Credit Facility will be reduced by an amount equal to 25% of the difference between the aggregate principal amount of the senior notes issued in the senior notes offering and the aggregate principal amount of Convertible Senior Notes purchased pursuant to the tender offer.

On November 2, 2010, the Company completed its private placement of 8.625% $400 million aggregate principal amount of its senior notes due 2018 at an offering price equal to 99.302% (the “Senior Notes”). The Senior Notes are guaranteed by certain of the

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Company’s subsidiaries: CCBM, Inc.; CLLR, Inc.; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC; Carrizo Marcellus Holding, Inc.; Hondo Pipeline, Inc.; Bandelier Pipeline Holding, LLC; Chama Pipeline Holding, LLC; and Mescalero Pipeline, LLC. The net proceeds of $387.7 million (after deducting initial purchasers’ discounts and the Company’s estimated expenses) were used to repay in full borrowings outstanding under the Senior Credit Facility with the remaining net proceeds initially being held in short-term investments. Upon closing of the tender offer for up to $300 million of its Convertible Senior Notes discussed below, the Company intends to use the net proceeds that are being held in short-term investments, together with borrowings under the Senior Credit Facility, to fund the tender offer. If the tender offer is not consummated, the Company intends to use the net proceeds from the Senior Notes offering that were held in short-term investments to fund in part its recently expanded capital expenditure program, including exploration in the Eagle Ford Shale and Niobrara formation, and for general corporate purposes.

On November 2, 2010, the Company and the guarantors of the Senior Notes entered into a supplement to the indenture pursuant to which such guarantors also guaranteed the Convertible Senior Notes. The guarantee of the Convertible Senior Notes by the guarantors was required under the indenture for the Convertible Senior Notes as a result of the issuance of their guarantees of the Senior Notes.

On October 25, 2010, the Company commenced a tender offer for up to $300 million aggregate principal amount outstanding of the Convertible Senior Notes. Each holder will receive $1,000 for each $1,000 principal amount of Convertible Senior Notes purchased in the tender offer, plus accrued and unpaid interest. The tender offer is subject to conditions, including that at least $200 million aggregate principal amount are tendered and not withdrawn. The Company may amend, extend or waive conditions to, or terminate, the tender offer. The tender offer will expire on November 23, 2010 unless extended by the Company. The Company expects to recognize a non-cash, pre-tax loss on extinguishment of debt as a result of the purchase of the Convertible Senior Notes in the tender offer currently estimated to be approximately $30 million, assuming the purchase of the full $300 million principal amount sought in the tender offer.

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management’s discussion and analysis of the significant factors that affected the Company’s financial position and results of operations during the periods included in the accompanying unaudited consolidated 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 consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009 and the unaudited consolidated financial statements included in this quarterly report.

General Overview

Our third quarter 2010 included oil and gas revenues of $30.5 million and production of 8.6 Bcfe. The key drivers to our results for the three months ended September 30, 2010 included the following:

Drilling program. Our success is largely dependent on the results of our drilling program. During the three months ended September 30, 2010, we drilled (a) nine gross wells (6.2 net) in the Barnett Shale area with a success rate of 100%, (b) three gross (3.0 net) wells in the Eagle Ford Shale area, two of which are in the process of being fractured, (c) five gross (1.2 net) wells in the Marcellus Shale area which are awaiting further testing and (d) one gross (1.0 net) unsuccessful well in north Texas. At September 30, 2010 we had an inventory of 47 gross wells (21.0 net) in the Barnett Shale that have been drilled and are waiting on fracturing, completion or pipeline connection.

Production. Our third quarter 2010 production of 8.6 Bcfe, or 93.4 MMcfe/d, increased 5% from the third quarter 2009 production of 8.2 Bcfe, or 89.2 MMcfe/d, and decreased 8% from the second quarter 2010 production of 9.3 Bcfe, or 102.1 MMcfe/d. The increase from the third quarter of 2009 to the third quarter of 2010 was primarily a result of production from new wells in the Barnett Shale, partially offset by normal production decline and a high volume gas well in the Gulf Coast area that was shut in for a workover and sidetrack. The decrease from the second quarter of 2010 to the third quarter of 2010 was due primarily to the curtailment of our production as a result of our midstream partners expansion of natural gas transport pipeline capacity (serving our core Barnett Shale properties in Southeast Tarrant County, Texas), which was completed in late September, and the shut-in of a well in the Gulf Coast for a workover and sidetrack, which we expect to be completed in the fourth quarter of 2010.

Commodity prices. Our average natural gas price during the third quarter of 2010 was $3.37 per Mcf (excluding the impact of our derivative instruments), $0.77 per Mcf, or 30% higher than the price during the third quarter of 2009 and $0.06 per Mcf, or two percent, lower than the price during the second quarter of 2010. Excluded from these prices are realized gains on derivative instruments of $9.1 million ($1.06 per Mcf) for the third quarter of 2010, $16.0 million ($2.02 per Mcf) for the third quarter of 2009 and $8.8 million ($0.97 per Mcf) for the second quarter of 2010.

Financial flexibility. Our Board of Directors recently approved an increase in the capital expenditure plan for 2010 from $225 million to approximately $280 million as a result of the September 2010 closing of the transactions related to the Marcellus Shale joint venture with Reliance described below. In May 2010, the borrowing base under the Senior Credit Facility was increased from $350 million to $375 million. Our next borrowing base redetermination is expected in November 2010 and may be reduced at the closing of our tender offer for our Senior Convertible Notes as described below.

Recent Developments

Marcellus Shale Joint Ventures. On September 10, 2010, we completed the sale of 20% of our interests in oil and gas properties in parts of Pennsylvania in the Marcellus Shale to Reliance Marcellus II, LLC, a wholly-owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited for $13.1 million and a commitment to pay 75% of certain of our future development costs up to approximately $52 million, as further described below. We received $11.9 million during the third quarter and expect to receive the remaining $1.2 million pending completion of land and title matters. Simultaneous with the closing of this transaction, ACP II Marcellus, LLC, our existing joint venture partner in the Marcellus Shale, an affiliate of Avista Capital Partners, LP, closed the sale of its entire interest in the same properties to Reliance for a purchase price of approximately $327 million. During the third quarter, the Company received cash distributions of $20.8 million on its B Unit investment in ACP II as a result of ACP II’s distribution of Reliance sale proceeds to Avista. We have agreed to indemnify Reliance for breaches of the purchase agreement relating to the transaction and specified retained liabilities. A portion of the proceeds received by us in these transactions was used to repay borrowings under the Senior Credit Facility.

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Simultaneous with these transactions, we and Reliance also entered into agreements to form a new joint venture with respect to the interests being purchased by Reliance from us and Avista. The new Carrizo/Reliance joint venture agreement covers approximately 104,400 net acres in northern and central Pennsylvania. Under the terms of the agreement, we generally retained a 40% working interest in the acreage and Reliance generally acquired a 60% working interest. In addition to funding its own share of future development obligations, Reliance agreed to fund 75% of our portion of these costs until September 2012 or until the earlier full utilization of the up to $52 million development carry, subject to certain conditions and extensions.

We have agreed to various restrictions on our ability to transfer our properties covered by the Reliance joint venture. Additionally, following the expiration of the carry commitment, we are subject to a mutual right of first offer on direct and indirect property transfers for the remainder of a ten-year development period (through September 2020), subject to specified exceptions. We have granted an option in favor of Reliance to purchase a 60% (as adjusted over time) share of acreage purchased directly or indirectly by us after the closing. This option, which covers substantially all of Pennsylvania, is exercisable at our cost plus, in the case of direct property sales, a specified premium and is subject to specified exceptions. Reliance has the right to assume operatorship of 60% of undeveloped acreage in portions of central Pennsylvania beginning in September 2011 and for a three-year period to purchase all of our 40% interest in such acreage at a specified price. Operations under the joint venture will generally be required to conform to a budget approved by an operating committee that includes representatives of both parties, subject to exceptions, including those for sole risk operations and in the event of defaults by the parties. The parties have also generally agreed until 2013 to forego the ability conduct sole risk operations and have agreed to certain other limits to such operations thereafter. Reliance has also agreed to certain limitations with respect to specified actions taken with respect to us.

Our Marcellus joint venture with Avista will continue and currently includes approximately 147,000 net acres, primarily in West Virginia and New York.

Increased Capital Expenditure Plan. Our Board of Directors recently approved a capital expenditure plan for 2010 of $280 million as a result of the closing of the transactions related to the Marcellus Shale joint venture with Reliance described above. This amount represents an increase over our prior capital expenditure plan of $225 million. Our planned capital expenditures for 2010 are currently allocated as follows:

•	$166 million for drilling, an increase from $147 million under the previous $225 million plan;

•	$102 million for land and seismic acquisitions, an increase from $76 million under the previous $225 million plan; and

•	$12 million for development of our Huntington Field in the U.K. North Sea, an increase from $2 million under the previous $225 million plan.

Amendment to Senior Credit Facility. On October 21, 2010, we amended our Senior Credit Facility to permit the offering and issuance of the Senior Notes described below and the tender offer of the Convertible Senior Notes described below. This amendment also added restrictions on the our ability to repurchase any Senior Notes issued in the Senior Notes offering and to make certain amendments to the terms of any Senior Notes issued in the Senior Notes offering, and added further restrictions on our ability to purchase the Convertible Senior Notes (other than pursuant to the tender offer described below).

In addition, the amendment to the Senior Credit Facility amended certain financial covenants in the credit agreement for the Senior Credit Facility. Specifically, from and after the date on which the Senior Notes offering closed, we are required to maintain (1) a maximum ratio of total net debt (which excludes certain amounts attributable to the Convertible Senior Notes) to Consolidated EBITDA (as defined in the Senior Credit Facility) of (a) 4.75 to 1.00 for the fiscal quarter ending on September 30, 2010, (b) 4.25 to 1.00 for the fiscal quarters ending on or after December 31, 2010 and on or before June 30, 2011, (c) 4.50 to 1.00 for the fiscal quarters ending on or after September 30, 2011 and on or before December 31, 2011 and (d) 4.00 to 1.00 for each fiscal quarter ending on or after March 31, 2012; and (2) a maximum ratio of senior debt (which excludes the aggregate principal amount of the Senior Notes and the Convertible Senior Notes) to Consolidated EBITDA of (a) 2.25 to 1.00 for the fiscal quarters ending on or after September 30, 2010 and on or before June 30, 2011, (b) 2.50 to 1.00 for the fiscal quarters ending on or after September 30, 2011 and on or before December 31, 2011 and (c) 2.25 to 1.00 for each fiscal quarter ending on or after March 31, 2012.

The amendment also provided that, upon the issuance of Senior Notes pursuant to the Senior Notes offering, we must repay all outstanding amounts under the Senior Credit Facility. Furthermore, the amendment provided that, on the date that we purchase any Convertible Senior Notes pursuant to the tender offer, the borrowing base under the Senior Credit Facility will be reduced by an amount equal to 25% of the difference between the aggregate principal amount of the Senior Notes issued in the Senior Notes offering and the aggregate principal amount of Convertible Senior Notes purchased pursuant to the tender offer.

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Private Offering of Senior Notes and Tender Offer for Convertible Senior Notes. On November 2, 2010, we completed our private placement of $400 million aggregate principal amount of our 8.625% Senior Notes due 2018 at an offering price equal to 99.302%. The Senior Notes are guaranteed by certain of our subsidiaries: CCBM, Inc.; CLLR, Inc.; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC, Carrizo Marcellus Holding, Inc.; Hondo Pipeline, Inc.; Bandelier Pipeline Holding, LLC, Chama Pipeline Holding LLC, and Mescalero Pipeline, LLC. The net proceeds of approximately $387.7 million (after deducting initial purchasers’ discounts and our estimated expenses) were used to repay amounts outstanding under the Senior Credit Facility with the remaining net proceeds initially being held in short-term investments. Upon closing of the tender offer for up to $300 million of our Convertible Senior Notes described below, we intend to use the net proceeds that are being held in short-term investments, together with borrowings under the Senior Credit Facility, to fund the tender offer. For more information about the terms of the Senior Notes, please read “─Liquidity and Capital Resources─Financing Arrangements─Private Offering of Senior Notes.” In connection with the issuance of the Senior Notes, we agreed to use our commercially reasonable best efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the Senior Notes in exchange for outstanding Senior Notes. In certain circumstances, we may be required to use commercially reasonable efforts to file a shelf registration statement to cover resales of the Senior Notes. We may be required to pay additional interest to holders of the Senior Notes under certain circumstances if fail to meet these obligations by certain dates.

On November 2, 2010, we and the guarantors of the Senior Notes entered into a supplement to the indenture governing the Convertible Senior Notes. Pursuant to this supplemental indenture, the guarantors of the Senior Notes also became guarantors of the Convertible Senior Notes. The guarantee of the Convertible Senior Notes was required under the indenture for the Convertible Senior Notes as a result of the issuance of their guarantees of the Senior Notes.

On October 25, 2010, we commenced a tender offer for up to $300 million aggregate principal amount outstanding of the Convertible Senior Notes. Each holder will receive $1,000 for each $1,000 principal amount of Convertible Senior Notes purchased in the tender offer, plus accrued and unpaid interest. The tender offer is subject to conditions, including that at least $200 million aggregate principal amount are tendered and not withdrawn. We may amend, extend or waive conditions to, or terminate, the tender offer. The tender offer will expire on November 23, 2010, unless extended by us. We expect to recognize a non-cash pre-tax loss on extinguishment of debt as a result of the purchase of the Convertible Senior Notes in the tender offer currently estimated to be approximately $30 million, assuming the purchase of the full $300 million principal amount sought in the tender offer. As a result of the expected purchase of Convertible Senior Notes in our pending tender offer and the recent issuance of our Senior Notes, we expect that our debt service expenses will increase as the Senior Notes bear a higher interest rate than the stated interest rate on the Convertible Senior Notes. The maturities on the Senior Notes, however, extend beyond June 1, 2013, the date on which the holders of the Convertible Senior Notes will first be able to require us to purchase the Convertible Senior Notes.

Fourth Quarter Production. In the Barnett Shale area, we have several wells that have been drilled and fractured and are awaiting connection to gas gathering systems. Our midstream partner in this area has reported scheduling delays in connecting these wells, which delayed our adding` additional production. As a result, we currently estimate our fourth quarter production will average approximately 120 MMcfe/d. Actual fourth quarter production may vary materially from this estimate.

Outlook

Our outlook for 2010 remains challenging, primarily as a result of the low spot and futures prices for natural gas, but our outlook for the long-term future remains positive. Production growth and commodity prices that permit us to drill, develop and produce at a profit are key to our future success, and we believe the following measures will continue to have a positive impact on our results in 2010:

In April 2010, we announced a new growth strategy in crude oil and liquids-rich plays to take advantage of the attractive economics associated with those commodities in light of market conditions. We moved quickly to implement this strategy and currently own approximately 20,000 net acres in an unconventional play that is rich in condensate and natural gas liquids located in the Eagle Ford Shale, principally in LaSalle County, Texas and over 59,000 net acres in an unconventional oil play located in the Niobrara formation in the Denver-Julesberg basin in Weld County, Colorado. Since our announcement, we have drilled four horizontal gross wells (4.0 net) and we are drilling our fifth well in the Eagle Ford Shale. Prior to year-end, we expect to drill four gross wells (4.0 net) in the Niobrara formation. We currently expect initial production results from the Eagle Ford Shale in November 2010 and from the Niobrara formation by the end of 2010.

As a result of the joint venture with Reliance, we plan to accelerate our exploration activities in the Marcellus Shale. We have drilled seven gross wells (1.7 net) in the Marcellus Shale in 2010, including three gross wells (0.6 net) in Pennsylvania. In the third quarter of 2010, we entered into two long-term contracts for drilling rigs in the Marcellus Shale, one of which is expected to begin work in the fourth quarter of 2010 and the other of which is expected to begin work in the second quarter

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of 2011. Additionally, we expect to continue our Marcellus joint venture activities in West Virginia with Avista, including the completion and testing of 1.0 gross well (0.5 net) in 2010.

As a result of the closing of the transactions related to the Marcellus Shale joint venture with Reliance described above, our Board of Directors approved a revised capital expenditure plan for 2010 of approximately $280 million (a $55 million increase over our prior capital expenditure plan of $225 million), which includes $166 million for drilling, $102 million for land and seismic acquisitions and $12 million for the development of our Huntington Field in the U.K. North Sea.

At September 30, 2010, we had hedged approximately 6,716,000 MMBtus of natural gas production (or 73,000 MMBtu per day for the fourth quarter of 2010), representing approximately 60% of our forecasted natural gas production for the fourth quarter of 2010, at a weighted average floor or swap price of $5.76 per MMBtu relative to WAHA and Houston Ship Channel prices.

Results of Operations

Three Months Ended September 30, 2010, Compared to the Three Months Ended September 30, 2009

Revenues from oil and gas production for the three months ended September 30, 2010 increased 29% to $30.5 million from $23.6 million for the same period in 2009 primarily due to increased production and higher gas prices. Production volumes were 8.6 Bcfe and 8.2 Bcfe for the three months ended September 30, 2010 and 2009, respectively. The increase in production was primarily attributable to new production from wells in the Barnett Shale partially offset by normal production decline and a high volume gas well in the Gulf Coast area that was shut in for a workover and sidetrack during the third quarter of 2010. Average natural gas prices, excluding the impact attributable to a $9.0 million and a $16.0 million realized gain on derivative instruments for the quarters ended September 30, 2010 and 2009, respectively, increased to $3.37 per Mcf in the third quarter of 2010 from $2.60 per Mcf in the same period in 2009. Average oil prices, excluding the impact attributable to a $0.1 million realized gain on derivative instruments for the quarter ended September 30, 2010, increased 10% to $72.92 per barrel from $66.25 per barrel in the same period in 2009.

The following summarizes production volumes, average sales prices (excluding the impact of derivative instruments) and oil and gas revenues for the three months ended September 30, 2010 and 2009:

	Three Months Ended				2010 Period
	September 30,				Compared to 2009 Period
					Increase			% Increase
	2010		2009		(Decrease)			(Decrease)
Production volumes
Oil and condensate (MBbls)		29		44		(15	)		(34	)%
Natural gas and NGLs (MMcf)		8,417		7,947		470			6	%
Average sales prices
Oil and condensate (per Bbl)	$	72.92	$	66.25	$	6.67			10	%
Natural gas and NGLs (per Mcf)		3.37		2.60		0.77			30	%
Oil and gas revenues (In thousands)
Oil and condensate	$	2,096	$	2,886	$	(790	)		(27	)%
Natural gas and and NGLs		28,406		20,698		7,708			37	%
Total oil and gas revenues	$	30,502	$	23,584	$	6,918			29	%

Lease operating expenses were $7.1 million (or $0.83 per Mcfe) during the three months ended September 30, 2010 as compared to $3.3 million (or $0.41 per Mcfe) for the third quarter of 2009. Increased operating expenses were due to increased production and the workover of a high volume gas well in the Gulf Coast area.

Production taxes increased 8% from $0.6 million in the third quarter of 2009 to $0.7 million for the same period in 2010 primarily due to higher gas prices and increased production in 2010.

Ad valorem taxes decreased 39% to $0.7 million for the three months ended September 30, 2010 from $1.2 million for the same period in 2009 primarily due to lower estimated property valuations in 2010.

DD&A expense for the three months ended September 30, 2010 decreased to $10.4 million ($1.21 per Mcfe) from $12.5 million ($1.53 per Mcfe) for the same period in 2009. This decrease in DD&A was primarily due to a lower depletion rate resulting from an

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impairment charge that reduced the depletable full-cost pool in the fourth quarter of 2009 and lower overall finding costs of new reserves added primarily in the fourth quarter of 2009, partially offset by increased production.

General and administrative expense increased to $9.9 million for the three months ended September 30, 2010 from $7.6 million for the corresponding period in 2009. The increase was primarily due to (a) increased stock-based compensation largely attributable to SARs that increased in fair value at September 30, 2010 and the 2009 annual bonuses to senior management which were approved during the third quarter of 2010 and (b) increased compensation costs attributable to the 2009 annual bonuses to senior management which were approved during the third quarter of 2010 while the 2008 annual bonuses to senior management were approved during the second quarter of 2009 and an increase in the number of employees in 2010, partially offset by (c) expense associated with a pledge of $1.0 million made to the University of Texas at Arlington (“UTA”) in the third quarter of 2009 for which there was no corresponding expense in the 2010 period.

The net gain on derivative instruments of $21.5 million in the third quarter of 2010 consisted of a $12.4 million unrealized gain on derivatives and a $9.1 million realized gain on derivatives. The net loss on derivative instruments of $2.0 million in the third quarter of 2009 was comprised of an $18.0 million unrealized loss on derivatives and a $16.0 million realized gain on derivatives.

Interest expense and capitalized interest for the three months ended September 30, 2010 were $10.4 million and $5.6 million, respectively, as compared to $9.9 million and $5.0 million, respectively, for the same period in 2009. The net decrease was primarily due to higher capitalized interest due to higher levels of unproved properties and a higher weighted average interest rate partially offset by additional interest expense associated with higher levels of debt outstanding under the Senior Credit Facility, higher amortization of deferred financing costs and increased amortization of the discount related to the Senior Convertible Notes.

During the third quarter of 2010, we received cash distributions of $20.8 million on our B Unit investment in ACP II as a result of ACP II’s distribution to Avista of the proceeds from the sale of its interests in oil and gas properties in parts of Pennsylvania to Reliance.

Our overall effective tax rate was 37.8% for the third quarter of 2010 and 45.4% for the third quarter of 2009. The increase in the effective tax rate was primarily due state income taxes on the cash distributions we received during the third quarter of 2010.

Nine months Ended September 30, 2010, Compared to the Nine months Ended September 30, 2009

Revenues from oil and gas production for the nine months ended September 30, 2010 increased 28% to $102.4 million from $80.2 million for the same period in 2009 primarily due to increased production and higher gas prices. Production volumes for the nine months ended September 30, were 26.2 Bcfe and 24.4 Bcfe in 2010 and 2009, respectively. The increase in production was primarily due to new production from wells in the Barnett Shale, partially offset by normal production decline and a high volume gas well in the Gulf Coast area that was shut-in for a workover and sidetrack during the third quarter of 2010. Average natural gas prices, excluding the impact attributable to a $22.8 million and a $59.2 million realized gain on derivative instruments for the nine months ended September 30, 2010 and 2009, respectively, increased to $3.70 per Mcf for the first nine months of 2010 from $3.10 per Mcf in the same period in 2009. Average oil prices, excluding the impact of a realized gain on derivative instruments of $0.1 million and $2.8 million for the nine months ended September 30, 2010 and 2009, respectively, increased 39% to $75.10 per barrel from $54.08 per barrel in the same period in 2009.

The following summarizes production volumes, average sales prices (excluding the impact of derivative instruments) and oil and gas revenues for the nine months ended September 30, 2010 and 2009:

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	Nine Months Ended				2010 Period
	September 30,				Compared to 2009 Period
					Increase			% Increase
	2010		2009		(Decrease)			(Decrease)
Production volumes
Oil and condensate (MBbls)		105		129		(24	)		(19	)%
Natural gas and NGLs (MMcf)		25,524		23,589		1,935			8	%
Average sales prices
Oil and condensate (per Bbl)	$	75.10	$	54.08	$	21.02			39	%
Natural gas and NGLs (MMcf)		3.70		3.10		0.60			19	%
Oil and gas revenues (In thousands)
Oil and condensate	$	7,854	$	6,951	$	903			13	%
Natural gas and NGLs		94,526		73,235		21,291			29	%
Total oil and gas revenues	$	102,380	$	80,186	$	22,194			28	%

Lease operating expenses were $18.4 million (or $0.70 per Mcfe) during the nine months ended September 30, 2010 as compared to $19.6 million (or $0.80 per Mcfe) for the nine months ended 2009. A decrease in service costs and lower transportation costs were partially offset by increased operating expenses associated with increased production. The decrease in service costs was driven primarily by a decrease in operating expenses related to a pipeline and gathering system that was sold during the fourth quarter of 2009 and the increase in production from our Tarrant County Barnett Shale area, which has comparatively less associated salt water production that must be disposed of than production from other areas. The decrease in transportation costs was primarily due to a change in contractual pricing effective July 1, 2009, whereby natural gas production is now sold at the wellhead.

Production taxes increased from a credit of $0.4 million in the first nine months of 2009 to $2.5 million for the same period in 2010 as a result of a severance tax refund of $2.0 million in 2009 and higher prices and increased production in 2010.

Ad valorem taxes decreased 33% to $2.4 million for the nine months ended September 30, 2010 from $3.6 million for the same period in 2009 primarily due to lower estimated property valuations in 2010.

DD&A expense for the nine months ended September 30, 2010 decreased to $31.3 million ($1.20 per Mcfe) from $40.0 million ($1.64 per Mcfe) for the same period in 2009. This decrease in DD&A was primarily due to a lower depletion rate resulting from impairment charges that reduced the depletable full-cost pool in the first and fourth quarters of 2009 and lower overall finding costs of new reserves added primarily in the fourth quarter of 2009, partially offset by increased production.

In June 2010, we concluded that it was uneconomical to pursue development on the license covering the Monterey field in the U.K. North Sea and terminated further development efforts resulting in a full-cost ceiling test impairment of $2.7 million for the nine months ended September 30, 2010 with respect to the U.K. cost center. Due to low oil and gas prices during 2009, indicated by average prices of $3.17 per Mcf for natural gas and $51.76 per Bbl for crude oil on May 6, 2009, the discounted present value (discounted at ten percent) of future net cash flows from our proved oil and gas reserves fell below our net book basis in the proved oil and gas properties. This resulted in a full-cost ceiling test impairment at March 31, 2009 of $216.4 million with respect to the U.S. cost center.

General and administrative expense increased to $24.6 million for the nine months ended September 30, 2010 from $21.9 million for the corresponding period in 2009. The increase was due primarily to (a) increased stock-based compensation largely attributable to SARs that increased in fair value at September 30, 2010, and (b) increased compensation costs largely due to an increase in the number of employees in 2010 partially offset by (c) expense associated with a pledge of $1.0 million made to UTA in the third quarter of 2009 for which there is no corresponding expense in the 2010 period.

The net gain on derivative instruments of $47.5 million in the first nine months of 2010 consisted of a $24.6 million unrealized gain on derivatives and a $22.9 million realized gain on derivatives. The net gain on derivative instruments of $25.8 million in the first nine months of 2009 was comprised of a $62.0 million realized gain on derivatives and a $36.2 million unrealized loss on derivatives.

Interest expense and capitalized interest for the nine months ended September 30, 2010 were $30.1 million and $15.1 million, respectively, as compared to $28.6 million and $15.1 million, respectively, for the same period in 2009. The net increase was primarily due to increased interest expense associated with higher levels of debt outstanding under the Senior Credit Facility, higher amortization of deferred financing costs and increased amortization of the discount related to the Senior Convertible Notes.

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Our overall effective tax rate was 37.7% for the first nine months of 2010 and 35.4% for the first nine months of 2009. The increase in the effective tax rate was primarily due to a true up of prior year estimates of state income taxes during 2010 and state income taxes on the cash distributions we received during the third quarter of 2010.

Liquidity and Capital Resources

2010 Capital Expenditure Budget and Funding Strategy. In connection with the September 2010 closing of the transactions related to the Marcellus Shale joint venture with Reliance, our Board of Directors recently approved an increase in the capital expenditure plan for 2010 from $225 million to approximately $280 million which currently includes $166 million for drilling, $102 million for land and seismic acquisitions and $12 million for the development of the U.K. North Sea. If our development plan for the Huntington Field in the U.K. North Sea is approved by the U.K. Department of Energy and Climate Change during 2010, we will be required to invest up to an additional $10 million in facilities and drilling to develop this field in 2010. We currently intend to project finance a portion of the additional Huntington field development costs. We intend to finance our 2010 capital expenditure plan primarily from cash flows from operations, the possible selective sale or monetization of non-core assets and available borrowings under the Senior Credit Facility, including the increased capacity under the Senior Credit Facility that was made available following repayment of borrowings with proceeds from our April 2010 equity offering, the transactions relating to our Marcellus joint ventures with Reliance and Avista and our November 2010 Senior Notes offering . We may be required to reduce or defer part of our 2010 capital expenditure plan if we are unable to obtain sufficient financing from these sources or if natural gas prices decline.

Sources and Uses of Cash. During the nine months ended September 30, 2010, capital expenditures, net of proceeds from property sales, exceeded our net cash provided by operations. During 2010, we have funded our capital expenditures with cash generated from operations, net additional borrowings under the Senior Credit Facility, including borrowing capacity made available by the paydown of the facility with proceeds from our common stock offering and the transactions related to our Marcellus Shale joint ventures with Reliance and Avista. As discussed elsewhere, we expect to use cash in the fourth quarter of 2010 to fund our tender offer for Senior Convertible Notes. Potential 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 oil and gas prices.

Borrowings under the Senior Credit Facility. As of November 3, 2010, there was no outstanding balance under the Senior Credit Facility. We expect to fund the tender offer for our Convertible Senior Notes in late November 2010 primarily with borrowings under the Senior Credit Facility. We have also issued $4.1 million of letters of credit, which reduce the amounts available under the Senior Credit Facility. Future availability under our $375 million borrowing base is subject to the terms and covenants of the Senior Credit Facility. The Senior Credit Facility is used to fund ongoing working capital needs and the remainder of our capital expenditure plan only to the extent that such amounts exceed cash flow from operations, proceeds from the sale of oil and gas properties and securities offerings. The next borrowing base redetermination is expected in November 2010. In addition, the borrowing base will be reduced by 25% of the difference between the amount of Senior Notes issued and the Convertible Senior Notes tendered. We recently amended the terms and covenants under the Senior Credit Facility. Please read “-Recent Developments – Amendment to Senior Credit Facility.” As defined in the Senior Credit Facility, the current ratio was 1.56, the total net debt to Consolidated EBITDA ratio was 4.01 and the ratio of senior debt to Consolidated EBITDA ratio was 1.71 as of September 30, 2010. Because the calculation of the financial ratios are made as of a certain date, the financial ratios can fluctuate significantly period to period as the amounts outstanding under the Senior Credit Facility are dependent on, among other things, the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings.

Asset sales. In order to fund our capital expenditure plan, we may consider the sale of certain properties or assets that are not part of our core business, or are no longer deemed essential to our future growth, if we are able to sell such assets on terms that are acceptable to us. We may consider the sale of additional non-core assets, including the possible sale of our interest in the Huntington Field located in the U.K. North Sea, provided that we can obtain terms that are acceptable to us.

Securities offerings. In November 2010, we sold $400 million aggregate principal amount of Senior Notes, which were guaranteed by substantially all of our wholly owned subsidiaries. We used the net proceeds of approximately $387.7 million after deducting initial purchasers’ discounts and our estimated expenses, to repay in full borrowings outstanding under the

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Senior Credit Facility and initially held the remaining net proceeds in short-term investments. Upon closing of the concurrent tender offer for our Convertible Senior Notes, we intend to use the net proceeds that were initially held in short-term investments, together with borrowings under our Senior Credit Facility, to fund the tender offer. If the tender offer is not consummated, we intend to use the net proceeds from the offering that were held in short-term investments to fund in part our recently expanded capital expenditure program and for general corporate purposes. In April 2010, we sold 3.22 million shares of our common stock in an underwritten public offering at a price of $23.00 per share. We used the net proceeds of approximately $73.8 million to repay a portion of the outstanding borrowings under the Senior Credit Facility. For more information about the Senior Notes, please read “─Liquidity and Capital Resources─Financing Arrangements─Private Offering of Senior Notes.”

·	Project financing in certain limited circumstances, particularly to fund a portion of our future development costs for the Huntington Field in the U.K. North Sea.

·	Lease option agreements and land banking arrangements, such as those we have entered into in the past regarding the Marcellus Shale, the Barnett Shale and other plays. Please read Part II - Item 2, “Unregistered Sales of Equity Securities and Use of Proceeds,” of this Quarterly Report on Form 10-Q.

·	Joint ventures through which parties fund a portion of our land acquisition exploration activities to earn an interest in our exploration acreage, such as our joint ventures with Avista and Reliance in the Marcellus Shale play and our joint venture with Sumitomo in the Barnett Shale.

·	We may consider sale/leaseback transactions of certain capital assets, such as pipelines and compressors, which are not part of our core oil and gas exploration and production business.

In 2010 we currently plan to drill 57 gross (38.1 net) wells in the Barnett Shale area, eleven gross (3.8 net) wells in the Marcellus shale area, five gross (5.0 net) wells in the Eagle Ford Shale, four gross (4.0 net) wells in the Niobrara and three gross (1.5 net) wells in our other areas. The actual number of wells drilled and capital expended depends on our available financing, cash flow, availability and cost of drilling rigs, land and partner issues and other factors. In addition to our capital expenditure plan, we have contractual obligations as discussed below.

Overview of Cash Flow Activities. Net cash provided by operating activities were $99.6 million and $107.8 million for the nine months ended September 30, 2010 and 2009, respectively. The decrease was primarily due to a higher amount of realized gains on our derivative instruments in 2009 as compared to 2010 partially offset by higher gas prices and increased production in 2010.

Net cash used in investing activities were $229.3 million and $162.5 million for the nine months ended September 30, 2010 and 2009, respectively, and increased primarily due to increased capital expenditures during 2010 as compared to 2009 that was partially offset by higher proceeds from asset sales in 2010.

Net cash provided by financing activities for the nine months ended September 30, 2010 and 2009 was $128.5 million and $53.1 million, respectively. The increase related primarily to the $73.8 million proceeds from our equity offering in April 2010.

Liquidity/Cash Flow Outlook. We currently believe that cash generated from operations, borrowings under the Senior Credit Facility and proceeds from the transactions related to the Marcellus Shale joint venture with Reliance and Avista along with the proceeds from the November 2010 debt offering will be sufficient to fund our immediate cash flow needs.

Cash generated from operations is primarily driven by production and commodity prices. While we have steadily increased production over the last few years, natural gas prices have declined significantly since the third quarter of 2008. The Company’s current long-term strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to 36 months. At September 30, 2010, we had hedged approximately 36,019,000 MMbtus of natural gas production through 2012.

On May 5, 2010, we amended our Senior Credit Facility to increase the borrowing base to $375 million from $350 million, representing an increase of $25 million. As of November 3, 2010, we had no amounts outstanding under the Senior Credit Facility as the net proceeds from our private placement of our $400 million Senior Notes were used to repay in full amounts outstanding under the Senior Credit Facility with the remaining net proceeds initially being held in short-term investments. Upon closing of the tender offer for up to $300 million of the Convertible Senior Notes, we intend to use the net proceeds of the Senior Notes offering that are being held in short-term investments, together with borrowings under our Senior Credit Facility, to fund the tender offer. We have issued $4.1 million of letters of credit which reduce the amounts available under the Senior Credit Facility. Future availability under our $375 million borrowing base is subject to the terms and covenants of the Senior Credit Facility. The next borrowing base

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redetermination is expected in November 2010. In addition, the borrowing base under the Senior Credit Facility will be reduced by 25% of the difference between the amount of Senior Notes issued and the Convertible Senior Notes tendered. The Senior Credit Facility is used to fund ongoing working capital needs and the remainder of our capital expenditure plan only to the extent that such amounts exceed cash flow from operations, proceeds from the sale of oil and gas properties and securities offerings.

The amendment to the Senior Credit Facility, the Senior Notes Offering and the tender of the Convertible Senior Notes, each as discussed above, are intended to enhance our financial flexibility by reducing certain coverage ratios during 2011, increasing availability under the Senior Credit Facility and extending the average maturity life of our debt. We currently intend to seek to amend and restate the Senior Credit Facility to extend the maturity date to 2015, and effect other changes by the end of April 2011.

If cash from operations, funds available under the Senior Credit Facility and the other sources of cash described under “Sources and Uses of Cash” are insufficient to fund our 2010 capital expenditure plan, we may need to reduce our capital expenditure plan or seek other financing alternatives to fund it. We may not be able to obtain financing needed in the future on terms that would be acceptable to us, or at all. If we cannot obtain adequate financing, we may be required to limit or defer our planned 2010 oil and gas exploration and development program, thereby adversely affecting the recoverability and ultimate value of our oil and gas properties.

Contractual Obligations

For the nine months ended September 30, 2010, we entered into (a) long-term transportation agreements that require minimum volume commitments valued at $0.2 million for 2010, $1.2 million for 2011, $2.5 million for 2012, $4.1 million for 2013 and $9.8 million thereafter, (b) long-term drilling contracts that require payments of $1.8 million for 2010, $14.0 million for 2011, $16.0 million for 2012, $9.2 million for 2013 and $3.8 million thereafter and (c) a seismic contract that requires payments of $3.0 million in 2010 and $3.0 million in 2011.

Financing Arrangements

Amendment to Senior Credit Facility. On October 21, 2010, we amended our Senior Credit Facility to permit the issuance of the Senior Notes and the tender offer of the Convertible Senior Notes described below. This amendment also added restrictions on the our ability to repurchase any Senior Notes issued in the Senior Notes offering and to make certain amendments to the terms of any Senior Notes issued in the Senior Notes offering, and added further restrictions on our ability to purchase the Convertible Senior Notes (other than pursuant to the tender offer described below).

In addition, the amendment amended certain financial covenants in the credit agreement for the Senior Credit Facility. Specifically, from and after the date on which the Senior Notes offering closed, we are required to maintain (1) a maximum ratio of total net debt (which excludes certain amounts attributable to the Convertible Senior Notes) to Consolidated EBITDA (as defined in the Senior Credit Facility) of (a) 4.75 to 1.00 for the fiscal quarter ending on September 30, 2010, (b) 4.25 to 1.00 for the fiscal quarters ending on or after December 31, 2010 and on or before June 30, 2011, (c) 4.50 to 1.00 for the fiscal quarters ending on or after September 30, 2011 and on or before December 31, 2011 and (d) 4.00 to 1.00 for each fiscal quarter ending on or after March 31, 2012; and (2) a maximum ratio of senior debt (which excludes the aggregate principal amount of the Senior Notes and the Convertible Senior Notes) to Consolidated EBITDA of (a) 2.25 to 1.00 for the fiscal quarters ending on or after September 30, 2010 and on or before June 30, 2011, (b) 2.50 to 1.00 for the fiscal quarters ending on or after September 30, 2011 and on or before December 31, 2011 and (c) 2.25 to 1.00 for each fiscal quarter ending on or after March 31, 2012.

Private Offering of Senior Notes. On November 2, 2010, we closed on our private placement of $400 million aggregate principal amount of our 8.625% Senior Notes due 2018 at an offering price equal to 99.302%. The Senior Notes are guaranteed by certain of the Company’s subsidiaries: CCBM, Inc.; CLLR, Inc.; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC, Carrizo Marcellus Holding, Inc.; Hondo Pipeline, Inc.; Bandelier Pipeline Holding, LLC, Chama Pipeline Holding LLC, and Mescalero Pipeline, LLC. The net proceeds of $387.7 million (after deducting initial purchasers’ discount and our estimated expenses) were used to repay in full amounts outstanding under the Senior Credit Facility with the remaining net proceeds being held in short-term investments. Upon closing of the tender offer for up to $300 million of the Convertible Senior Notes, we intend to use the net proceeds that are being held in short-term investments, together with borrowings under our Senior Credit Facility, to fund the tender offer described below.

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The Senior Notes mature on October 15, 2018 with interest payable semi-annually. At any time prior to October 15, 2013, we may, subject to certain conditions, redeem up to 35% of the aggregate principal amount of Senior Notes at a redemption price of 108.625% of the principal amount, plus accrued and unpaid interest, using the net cash proceeds of one or more equity offerings by the Company. Prior to October 15, 2014, we may redeem all or part of the Senior Notes at 100% of the principal amount thereof, plus accrued and unpaid interest and a make whole premium. On and after October 15, 2014, we may redeem all or a part of the Senior Notes, at redemption prices decreasing from 104.313% to 100% on October 15, 2017, plus accrued and unpaid interest. If a Change of Control (as defined in the Indenture governing the Senior Notes) occurs, we may be required by holders to repurchase Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus any accrued but unpaid interest.

The Indenture contains covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: pay distributions on, purchase or redeem our common stock or other capital stock or redeem our subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of our assets; enter into agreements that restrict distributions or other payments from our restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries.

The notes and indenture are subject to customary events of default, including those relating to failures to comply with the terms of the notes and indenture, certain failures to file reports with the SEC and certain cross defaults of other indebtedness and mortgages and certain failures to pay final judgments.

In connection with the issuance of the Senior Notes, we agreed to use our commercially reasonable best efforts to file with the SEC and cause to become effective a registration statement relating to an offer to issue new notes having terms substantially identical to the Senior Notes in exchange for outstanding Senior Notes. In certain circumstances, we may be required to use commercially reasonable efforts to file a shelf registration statement to cover resales of the Senior Notes. We may be required to pay additional interest to holders of the Senior Notes under certain circumstances if fail to meet these obligations by certain dates.

Tender Offer for Convertible Senior Notes. On October 25, 2010, we commenced a tender offer for up to $300 million aggregate principal amount outstanding of the Convertible Senior Notes. Each holder will receive $1,000 for each $1,000 principal amount of Convertible Notes purchased in the tender offer, plus accrued and unpaid interest. The tender offer is subject to certain conditions, including that at least $200 million aggregate principal amount are tendered and not withdrawn. We may amend, extend or waive conditions to, or terminate, the tender offer. The tender offer will expire on November 23, 2010, unless extended by us. We expect to recognize a non-cash pre-tax loss on extinguishment of debt as a result of the purchase of the Convertible Senior Notes in the tender offer currently estimated to be approximately $30 million, assuming the purchase of the full $300 million principal amount sought in the tender offer.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing oil and gas prices. The significant decline in gas prices since the third quarter of 2008 has resulted in a significant decline in revenue per unit of production. Although operating costs have also declined, the rate of decline in gas prices has been substantially greater. Historically, inflation has had a minimal effect on us. However, with interest rates at historic lows and the government attempting to stimulate the economy through rapid expansion of the money supply in recent months, inflation could become a significant issue in the future.

Recently Adopted Accounting Pronouncements

A standard to improve disclosures about fair value measurements was issued by the FASB in January 2010. The additional disclosures required include: (1) the different classes of assets and liabilities measured at fair value, (2) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (3) the gross presentation of purchases, sales, issuances and settlements for the rollforward of Level 3 activity and (4) the transfers in and out of Levels 1 and 2. We adopted the new disclosures in the first quarter of 2010.

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Critical Accounting Policies

The preparation of financial statements in accordance with U.S. generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used. These policies and estimates are described in the 2009 Form 10-K. We have identified the following critical accounting policies and estimates used in the preparation of our financial statements: use of estimates, oil and gas properties, oil and gas reserve estimates, derivative instruments, income taxes and contingencies.

The full-cost ceiling test cushion for the U.S. cost center at September 30, 2010 was $202.0 million and was based upon average realized oil, natural gas liquids and natural gas prices of $72.21 per Bbl, $29.83 per Bbl and $4.17 per Mcf, respectively, or a volume weighted average price of $4.50 per Mcfe. In connection with our September 30, 2010 full-cost ceiling test computation for the U.S. cost center, a price sensitivity study indicated that a ten percent increase in the average commodity prices used in the ceiling test at September 30, 2010 would have increased the full-cost ceiling test cushion by approximately $80.9 million and a ten percent decrease in average commodity prices would have decreased the full-cost ceiling test cushion by approximately $110.1 million. The aforementioned price sensitivity is as of September 30, 2010 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.

Volatility of Oil and Gas Prices

Our revenues, future rate of growth, results of operations, financial position and ability to borrow funds or obtain additional capital, as well as the carrying value of our properties, are substantially dependent upon prevailing prices of oil and gas.

We review the carrying value of our oil and natural gas properties quarterly under the full-cost method of accounting rules. See “—Critical Accounting Policies—Oil and Natural Gas Properties,” in our 2009 Form 10-K.

We rely on various types of derivative instruments to manage our exposure to commodity price risk and to provide a level of certainty in our forward cash flows supporting our capital investment program. The commodity derivative instruments typically used are fixed-rate swaps, costless collars, puts, calls and basis swaps. Our current long-term strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to 36 months. Our derivative instruments are carried at fair value in the consolidated balance sheets, with the changes in fair value included in the consolidated statements of operations for the period in which the changes occur.

Under these derivative instruments, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at termination, expiration or exchanged for physical delivery contracts. We enter into the majority of our derivative transactions with three counterparties and netting agreements are in place with those counterparties. We do not obtain collateral to support the agreements but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. In the event of nonperformance, we would be exposed to price and credit risk.

			Weighted		Weighted
			Average		Average
	Volume		Floor Price		Ceiling Price
Period	(in MMbtu)		($/MMbtu)		($/MMbtu)
2010		6,716,000	$	5.76	$	6.32
2011		21,340,000	$	6.12	$	6.49
2012		7,963,000	$	6.53	$	7.03

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			Weighted		Weighted
			Average		Average
	Volume		Short Put Price		Put Spread
Period	(in MMbtu)		($/MMbtu)		($/MMbtu)
2010		5,209,000	$	4.11	$	1.65
2011		16,799,000	$	4.29	$	1.83
2012		6,404,000	$	4.47	$	2.06

For the three months and nine months ended September 30, 2010 and 2009, the Company recorded the following related to its derivative instruments:

	Three Months					Nine Months
	Ended September 30,					Ended September 30,
	2010		2009			2010		2009
	(In thousands)
Realized gain	$	9,111	$	16,038		$	22,859	$	62,064
Unrealized gain (loss)		12,409		(18,024	)		24,677		(36,262	)
Gain (loss) on derivative instruments, net	$	21,520	$	(1,986	)	$	47,536	$	25,802

We deferred the payment of premiums associated with certain derivative instruments totaling $5.4 million and $4.8 million at September 30, 2010 and December 31, 2009, respectively. We classified $4.3 million and $1.8 million as other current liabilities at September 30, 2010 and December 31, 2009, respectively, and $1.1 million and $3.0 million as other non-current liabilities at September 30, 2010 and December 31, 2009, respectively. The deferred premiums will be paid to the counterparty with each monthly settlement (October 2010 – December 2011) and recognized as a reduction of realized gain on derivative instruments.

The fair value of the derivative instruments at September 30, 2010 and December 31, 2009 was a net asset of $35.8 million and $12.1 million, respectively. At September 30, 2010, approximately 81% of the fair value of our derivative instruments were with Credit Suisse, 15% were with Shell Energy North America (US) LP, and the remaining 4% were with Credit Agricole.

Forward Looking Statements

The statements contained in all parts of this document, including, but not limited to, those relating to the Company’s or management’s intentions, beliefs, expectations, hopes, projections, assessment of risks, estimations, plans or predictions for the future, including 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 gas exploration, acquisition of 3-D seismic data (including number, timing and size of projects), spending plans, capital expenditure plans, planned evaluation of prospects, probability of prospects having oil and gas, expected production or reserves, pipeline connections, tender offer results, use of proceeds of the Senior Notes offering, receipt of distributions, increases in reserves, acreage, working capital requirements, hedging activities and the impact on our average prices, the ability of expected sources of liquidity to implement the Company’s business strategies, accessibility of borrowings under our credit facility, future exploration activity, drilling, completion and fracturing of wells, land acquisitions, production rates, forecasted production, project financing, growth in production, development of new drilling programs, participation of our industry partners, funding for our Marcellus Shale operations, hedging of production, exploration and development expenditures, the impact of our business strategies, the benefits, results, effects, closing and timing of our new and existing joint ventures and sales transactions and all and any other statements regarding future operations, financial results, business plans and cash needs and other statements regarding future operations, financial results, business plans and cash needs and other statements that are not historical facts are forward looking statements. When used in this document, the words “anticipate,” “estimate,” “expect,” “may,” “project,” “plan,” “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 worldwide economic downturn, availability of financing, our dependence on our exploratory drilling activities, the volatility of and changes in oil and gas prices, the need to replace reserves depleted by production, operating risks of oil and gas operations, our dependence on our key personnel, factors that affect our ability to manage our growth and achieve our business strategy, results, delays and uncertainties that may be encountered in drilling, development or production, interpretations and impact of new SEC rules regarding oil and gas reserves, activities and approvals of our partners and parties with whom we have alliances, technological changes, capital requirements, borrowing base determinations and availability under the Senior Credit Facility, evaluations of the Company by potential lenders under the Senior Credit Facility, the potential impact of government regulations, including proposed legislation and regulations related to hydraulic fracturing, air emissions and climate change, and adverse regulatory determinations, litigation, competition, the

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uncertainty of reserve information and future net revenue estimates, property acquisition risks, availability of equipment, weather, availability of financing, actions by lenders, joint venture partners and industry partners, ability to obtain permits, the results of audits and assessments, the failure to obtain certain bank and lease consents, the existence and resolution of title defects and land matters, delays, costs and difficulties relating to these transactions, actions by joint venture partners, results of exploration activities and other factors detailed in the “Risk Factors” and other sections of our Annual Report on Form 10-K for the year ended December 31, 2009 and in this and our other filings with the SEC. 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 we undertake no obligation to update or revise any forward-looking statement.

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, 2009. There have been no material changes to the disclosure regarding our exposure to certain market risks made in our Annual Report on Form 10-K for the year ended December 31, 2009.

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, 2010 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 by the SEC’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. 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, 2010 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 factors 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, 2009, and in Part II, Item 1A., “Risk Factors” in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2010 and June 30, 2010, which could materially affect our business, financial condition or future operating 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.

We may not complete the tender offer for our convertible senior notes on the terms described in this report or at all.

We have commenced a tender offer for up to $300 million aggregate principal amount of our Convertible Senior Notes. We may not complete the tender offer for our Convertible Senior Notes on the terms described in this report or at all. The tender offer is currently subject to a number of conditions, including that at least $200 million aggregate principal amount of Convertible Senior Notes is validly tendered and not withdrawn. We can provide no assurance that the minimum amount of Convertible Senior Notes will be

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tendered, and the amount tendered is subject to a number of factors beyond our control, such as market conditions and participation of holders of Convertible Senior Notes. Upon the failure of any condition to be satisfied, we may choose to terminate, withdraw or amend the tender offer. We may waive any of the conditions to the tender offer at any time, including those relating to the minimum amount that must be tendered or the deadline by which noteholders must tender their Convertible Senior Notes. We may also amend the tender offer at any time, including any amendment that increases or decreases the amount of Convertible Senior Notes we seek to purchase. As of September 30, 2010, we had $373.8 million of senior unsecured indebtedness outstanding. If we do not purchase any Convertible Senior Notes, as of September 30, 2010, pro forma for the issuance of the Senior Notes, we would have had $773.8 million of senior unsecured indebtedness outstanding. The risks associated with this increased level of debt may have a material adverse effect on our financial condition or results of operations. In addition, whether or not the tender offer is completed, we may purchase some or all of the outstanding Convertible Senior Notes in transactions other than through the tender offer. We may use available cash or borrowings under our Senior Credit Facility to fund the tender offer (which may be amended to increase the aggregate principal amount sought in such tender offer) and/or purchases of the Convertible Senior Notes in transactions other than through the tender offer. Use of these funds for these purchases may impair our ability to obtain additional financing in the future or reduce the amount of cash we would have otherwise used for capital expenditures.

We are subject to various risks and governmental regulations, including those relating to environmental matters such as benzene emissions and hydraulic fracturing, and future regulations may be more stringent.

Natural gas and oil operations are subject to various federal, state, local and foreign laws and government regulations that may change from time to time. Matters subject to regulation include discharge permits for drilling operations, plug and abandonment bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of natural gas and oil wells below actual production capacity in order to conserve supplies of natural gas and oil. Other federal, state, local and foreign laws and regulations relating primarily to the protection of human health and the environment apply to the development, production, handling, storage, transportation and disposal of natural gas and oil, by-products thereof and other substances and materials produced or used in connection with natural gas and oil operations, including drilling fluids and wastewater. In addition, we may incur costs arising out of property damage, including environmental damage caused by previous owners of property we purchase or lease or relating to third party sites, or injuries to employees and other persons. As a result, we may incur substantial liabilities to third parties or governmental entities and may be required to incur substantial remediation costs. We also are subject to changing and extensive tax laws, the effects of which cannot be predicted. Compliance with existing, new or modified laws and regulations could result in substantial costs, delay our operations or otherwise have a material adverse effect on our business, financial condition and results of operations.

Moreover, changes in environmental laws and regulations occur frequently and such laws and regulations tend to become more stringent over time. Stricter laws, regulations or enforcement policies could significantly increase our compliance costs and negatively impact our production and operations. For example, the Texas Commission on Environmental Quality (TCEQ) and the Railroad Commission of Texas have been evaluating possible additional regulation of air emissions in the Barnett Shale area, in response to concerns about allegedly high concentrations of benzene in the air near drilling sites and natural gas processing facilities. These initiatives, or other similar initiatives, could lead to more stringent air permitting, increased regulation and possible enforcement actions at the local, state, and federal levels. Additionally, the Environmental Protection Agency (the “EPA”) has recently entered into a court-ordered settlement with an environmental group that requires it to consider strengthening certain regulations under the Clean Air Act, including the New Source Performance Standards (NSPS), maximum achievable control technology standards (MACT) and residual risk standards, affecting a wide array of air emission sources in the oil and gas industry and propose standards by January 31, 2011, or determine that standards do not apply. If these or other initiatives result in an increase in regulation, it could increase our costs or reduce our production, which could have a material adverse effect on our results of operations and cash flows.

Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays like the Barnett Shale, the Marcellus Shale, the Eagle Ford Shale and the Niobrara formation. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas production. The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under that Act and to require the disclosure of chemicals used by us and others in the oil and gas industry in the hydraulic fracturing process. Sponsors of bills currently pending before the U.S. Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. Proposed legislation would require, among other things, the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings against producers and service providers. In addition, these bills, if adopted, could establish an additional level of regulation and permitting of hydraulic fracturing operations at the federal level, which could lead to operational delays, increased operating and compliance costs and additional regulatory burdens that could make it more difficult or commercially impracticable for us to perform hydraulic fracturing, delaying the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing. Additionally,

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the EPA has commenced a comprehensive research study to investigate the potential adverse environmental impacts of hydraulic fracturing, including on water quality and public health, and a committee of the U.S. House of Representatives is also conducting an investigation of hydraulic fracturing practices. The initial EPA study results are expected to be available in late 2012. Further, in light of the explosion and fire on the drilling rig Deepwater Horizon in the Gulf of Mexico, as well as recent incidents involving the release of natural gas and fluids as a result of drilling activities in the Marcellus Shale, there have been a variety of regulatory initiatives at both the federal and state levels to restrict oil and gas drilling operations in certain locations. For example, there is proposed legislation in both the Pennsylvania and New York legislatures calling for a moratorium on drilling. Additionally, the New York State Department of Environmental Conservation has ceased issuing exploration and production drilling permits, pending completion of an environmental impact statement regarding hydraulic fracturing, and the U.K. Parliament has discussed implementing a drilling moratorium in the U.K. North Sea. We use hydraulic fracturing extensively and any increased federal, state, local or foreign regulation of hydraulic fracturing or offshore drilling, including proposed legislation in the states of New York and Pennsylvania, could reduce the volumes of oil and natural gas that we can economically recover, which could materially and adversely affect our revenues and results of operations.

President Obama’s 2011 Fiscal Year Budget includes proposals that would, if enacted into law, make significant changes to United States tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could defer or eliminate certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Climate change and climate change legislation and regulatory initiatives could result in increased operating costs and decreased demand for the oil and gas that we produce.

There is increasing attention in the United States and worldwide being paid to the issue of climate change and the contributing effect of greenhouse gas (“GHG”) emissions. On September 22, 2009, the EPA issued a “Mandatory Reporting of Greenhouse Gases” final rule (“Reporting Rule”) which was subsequently amended on July 20, 2010. The Reporting Rule establishes a new comprehensive scheme, beginning in 2011, requiring operators of stationary sources emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions occurring in the prior calendar year on a facility-by-facility basis. On March 22, 2010, the EPA issued proposed rules applying these regulations to the oil and gas source category including oil and natural gas production facilities, natural gas processing, transmission, distribution and storage facilities. In addition, on December 15, 2009, the EPA published a Final Rule, also known as the EPA’s Endangerment Finding, finding that current and projected concentrations of six key GHGs in the atmosphere threaten the environment and public health and the welfare of current and future generations. Following issuance of the Endangerment Finding, the EPA promulgated final motor vehicle GHG emission standards under the Clean Air Act on April 1, 2010 that will require reduction in emissions of GHGs from motor vehicles beginning in 2011, the effect of which could reduce demand for motor fuels refined from crude oil. Also, on May 13, 2010, the EPA issued a prepublication version of a final rule to address permitting of GHG emissions from stationary sources under the Clean Air Act’s Prevention of Significant Deterioration (“PSD”) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply to certain stationary sources of GHG emissions, to be phased in through a multistep process, with the largest sources being the first subject to permitting. Most recently, on August 12, 2010, the EPA proposed two actions to govern the implementation of PSD permitting requirements for GHGs in states whose existing State Implementation Plans, or “SIPs,” do not accommodate the regulation of GHGs. First, the EPA has proposed to issue a “Finding of Substantial Inadequacy” and SIP Call to 13 of such states, requiring them to revise their SIPs to ensure that their SIP programs cover GHG emissions. Second, the EPA has proposed to establish a federal implementation plan in any state that does not revise its SIP to accommodate GHG permitting. In addition, the U.S. Congress is currently considering a number of legislative proposals to restrict GHG emissions and more than 20 states, either individually or as part of regional initiatives, have begun taking actions to control and/or reduce GHG emissions. Moreover, in 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding set of emission targets for GHGs, became binding on all those countries that had ratified it. International discussions are currently underway to develop a treaty to replace the Kyoto Protocol after its expiration in 2012. While it is not possible at this time to predict how regulation that may be enacted to address GHG emissions would impact our business, the modification of existing laws or regulations or the adoption of new laws or regulations curtailing oil and gas exploration in the areas of the United States or the North Sea in which we operate could materially and adversely affect our operations by limiting drilling opportunities or imposing materially increased costs. In addition, existing or new laws, regulations or treaties (including incentives to conserve energy or use alternative energy sources) could have a negative impact on our business if such incentives reduce demand for oil and gas.

Moreover, some experts believe climate change poses potential physical risks, including an increase in sea level and changes in weather conditions, such as an increase in changes in precipitation and extreme weather events. To the extent that such unfavorable weather conditions are exacerbated by global climate change or otherwise, our operations may be adversely affected to a greater degree than we have previously experienced, including increased delays and costs. However, the uncertain nature of changes in

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extreme weather events (such as increased frequency, duration, and severity) and the long period of time over which any changes would take place make estimating any future financial risk to our operations caused by these potential physical risks of climate change extremely challenging. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks.

We conduct a substantial portion of our operations through joint ventures, which subject us to additional risks that could have a material adverse effect on the success of these operations, our financial condition and our results of operations.

We conduct a substantial portion of our operations through joint ventures with third parties, including Reliance, an affiliate of Sumitomo Corporation and ACP II. We may also enter into other joint venture arrangements in the future. These third parties may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture and to pay their share of capital and other costs of the joint venture. The performance of these third party obligations, including the ability of the third parties to satisfy their obligations under these arrangements, is outside our control. If these parties do not satisfy their obligations under these arrangements, our business may be adversely affected.

Our joint venture arrangements may involve risks not otherwise present when exploring and developing properties directly, including, for example:

·	our joint venture partners may share certain approval rights over major decisions;

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

·	we may incur liabilities as a result of an action taken by our joint venture partners;

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

·	disputes between us and our joint venture partners may result in delays, litigation or operational impasses.

The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to transact the business that is the subject of such joint venture, which would in turn negatively affect our financial condition and results of operations.

Our joint venture with Reliance contemplates that we will make significant capital expenditures and subjects us to certain legal and financial terms that could adversely affect us.

On September 10, 2010, we completed the sale to Reliance of 20% of our interests in oil and gas properties in parts of Pennsylvania in the Marcellus Shale for approximately $13 million in cash and a commitment to pay 75% of certain of our future development costs up to approximately $52 million (the “Carry Commitment”). At that time, we entered into agreements with Reliance to form a new joint venture with respect to the interests being purchased by Reliance from us and ACP II such that we generally retained a 40% working interest in the acreage and Reliance generally owns a 60% working interest.

The agreements under which we formed this joint venture subject us to various risks, limit the actions we may take with respect to our properties and require us to grant rights to Reliance that could limit our ability to benefit fully from future positive developments. The joint venture requires us to make significant capital expenditures. If we do not timely meet our financial commitments or otherwise do not comply with our joint venture agreements, our rights to participate, exercise operator rights or otherwise influence or benefit from the joint venture will be adversely affected.

Reliance’s obligation to fund the Carry Commitment expires with respect to any portion of the Carry Commitment not utilized by September 10, 2012, subject to certain extensions. We have agreed to various restrictions on our ability to transfer our properties covered by the joint venture. Additionally, following the expiration of the Carry Commitment, we are subject to a mutual right of first offer on direct and indirect property transfers for the remainder of a ten-year development period (through September 2020), subject to specified exceptions. We have also granted an option in favor of Reliance to purchase a 60% (as adjusted over time) share of acreage purchased directly or indirectly by us after the closing. This option, which covers substantially all of Pennsylvania, is exercisable at our cost plus, in the case of direct property sales, a specified premium, and is subject to specified exceptions. Reliance has the right to assume operatorship of 60% of the undeveloped acreage in portions of central Pennsylvania and, for a three-year period (through September 2013), to purchase all of our 40% interest in such acreage at a specified price. Operations under the joint venture will

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generally be required to conform to a budget approved by an operating committee that includes representatives of both parties, subject to exceptions, including those for sole risk operations and in the event of defaults by the parties. The parties have also generally agreed until 2013 to forego the ability to conduct sole risk operations and have agreed to certain other limits to such operations thereafter. Reliance has substantially greater financial resources than we have and we may not be able to secure the funding necessary to participate in operations Reliance proposes, thereby reducing our ability to benefit from the joint venture.

Enactment of a Pennsylvania severance tax on natural gas could adversely impact our results of operations and the economic viability of exploiting natural gas drilling and production opportunities in Pennsylvania.

As a result of a funding gap in the state budget, the governor of the Commonwealth of Pennsylvania has proposed to its legislature the adoption of a severance tax on the production of natural gas in Pennsylvania. The amount of the proposed tax, as proposed by the governor, is 5% of the value of the natural gas at wellhead, plus 4.7 cents per 1,000 cubic feet of natural gas severed. In connection with the enactment of Pennsylvania’s 2010-2011 budget, the state’s legislature expressed its intention to pass a severance tax on natural gas to be effective no later than January 1, 2011, although the specific characteristics, including the scope and magnitude, of the tax have not been determined. A substantial portion of our Marcellus Shale acreage is located in the Commonwealth of Pennsylvania. If Pennsylvania adopts such a severance tax, it could adversely impact our results of operations and the economic viability of exploiting natural gas drilling and production opportunities in Pennsylvania.

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

On November 24, 2009, the Company entered into a Land Agreement (as amended, the “Land Agreement”) with an unrelated third party and its affiliate. Under this arrangement, the Company may until May 31, 2011 acquire up to $20 million of oil, gas and mineral interests/leases in certain specified areas in the Barnett Shale from the third party. In consideration of the Company’s receipt of an option to purchase the leases acquired by the third party, each time the third party purchases a lease group under the Land Agreement, if any, the Company will issue to the third party’s affiliate warrants to purchase a number of shares of the Company’s common stock equal to the quotient of (rounded up to the nearest whole number) (1) 20% of the purchase price of such lease group divided by (2) $13.00, with an exercise price of $22.09 and an expiration date of August 21, 2017. In addition, under certain circumstances where the Company reaches surface casing point on an initial well in one of the areas covered by the Land Agreement but has not achieved a specified lease up threshold for acreage in such area, the Company will issue additional warrants, on the same terms, to purchase a number of shares of the Company’s stock equal to the quotient (rounded up to the nearest whole number) of (1) 20% of the product of (A) the number of acres below the specified lease up threshold multiplied by (B) $5,000, divided by (2) $13.00. The warrants are subject to antidilution adjustments and may be exercised on a “cashless” basis.

For the issuance of these securities, the Company relied upon the exemption from registration provided by Section 4(2) of the Securities Act of 1933, as amended, for transactions not involving a public offering.

Item 3. Defaults Upon Senior Securities

None.

Item 5. Other Information

None.

Item 6. Exhibits

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

Exhibit Number		Description

10.1	—	Thirteenth Amendment to Credit Agreement, dated as of August 23, 2010 and effective as of September 10, 2010, among Carrizo Oil & Gas, Inc., as Borrower, certain Subsidiaries of the Borrower, as Guarantors, the Lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent and issuing bank (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on September 16, 2010).

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10.2	—	Amendment No. 1, dated as of August 4, 2010, to the Participation Agreement among Carrizo (Marcellus) LLC, Carrizo Oil & Gas, Inc., Avista Capital Partners II, L.P. and ACP II Marcellus LLC, 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 September 16, 2010).
10.3	—	Omnibus Amendment among Carrizo (Marcellus) LLC, Carrizo Oil & Gas, Inc., Avista Capital Partners II, L.P. and ACP II Marcellus LLC, dated as of September 10, 2010 (incorporated herein by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on September 16, 2010).
10.4	—	Fourteenth Amendment to Credit Agreement, dated as of October 21, 2010, among Carrizo Oil & Gas, Inc., as Borrower, certain Subsidiaries of the Borrower, as Guarantors, the Lenders party thereto, and Wells Fargo Bank, N.A., as administrative agent and issuing bank (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on October 25, 2010).
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.

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SIGNATURES

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

	Carrizo Oil & Gas, Inc.
	(Registrant)



Date: November 9, 2010	By: /s/ Paul F. Boling
	Vice President, Chief Financial Officer and Secretary
	(Principal Financial Officer)



Date: November 9, 2010	By: /s/ David L. Pitts
	Vice President and Chief Accounting Officer
	(Principal Accounting Officer)

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