Edgar Filing: CARRIZO OIL & GAS INC

form10q.htm

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2009

[ ] 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 [X] Accelerated filer []

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

YES [ ] NO [X]

The number of shares outstanding of the registrant's common stock, par value $0.01 per share, as of May 1, 2009, the latest practicable date, was 31,028,187.

CARRIZO OIL & GAS, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2009

INDEX

PART I. FINANCIAL INFORMATION			PAGE

	Item 1.	Consolidated Balance Sheets
		As of March 31, 2009 (Unaudited) and December 31, 2008	2

		Consolidated Statements of Operations (Unaudited)
		For the three-month periods ended March 31, 2009 and 2008	3

		Consolidated Statements of Cash Flows (Unaudited)
		For the three-month periods ended March 31, 2009 and 2008	4

		Notes to Consolidated Financial Statements (Unaudited)	5

	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	17

	Item 3.	Quantitative and Qualitative Disclosure About Market Risk	26

	Item 4.	Controls and Procedures	27


PART II. OTHER INFORMATION

	Items 1-6.		28

SIGNATURES			30

Index

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
ASSETS	2009			2008
	(Unaudited)			(Restated)
	(In thousands, except par value amount)
CURRENT ASSETS:
Cash and cash equivalents	$	3,111		$	5,184
Accounts receivable, trade (net of allowance for doubtful accounts of $1,486 and $1,264
at March 31, 2009 and December 31, 2008, respectively)		28,768			24,675
Advances to operators		844			336
Fair value of derivative financial instruments		45,467			22,791
Prepayments and deposits		2,097			3,335
Total current assets		80,287			56,321

PROPERTY AND EQUIPMENT, net full-cost method of accounting for oil
and natural gas properties (including unevaluated costs of properties of $267,312 and
$276,138 at March 31, 2009 and December 31, 2008, respectively)		816,176			1,026,508
DEFERRED FINANCING COSTS, NET		7,994			8,430
INVESTMENTS		3,182			3,274
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS		689			15,876
DEFERRED INCOME TAXES		38,006			-
OTHER ASSETS		1,135			1,172
TOTAL ASSETS	$	947,469		$	1,111,581

LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
Accounts payable, trade	$	62,239		$	46,683
Accrued liabilities		32,271			54,149
Advances for joint operations		7,415			3,815
Current maturities of long-term debt		173			173
Deferred tax liability		15,913			9,103
Total current liabilities		118,011			113,923

LONG-TERM DEBT, NET OF CURRENT MATURITIES AND DEBT DISCOUNT		499,787			475,788
ASSET RETIREMENT OBLIGATION		9,608			6,503
DEFERRED INCOME TAXES		-			48,736
DEFERRED CREDITS		580			625

COMMITMENTS AND CONTINGENCIES		-			-

SHAREHOLDERS' EQUITY:
Common stock, par value $0.01 (90,000 shares authorized; 30,889 and
30,860 issued and outstanding at March 31, 2009 and
December 31, 2008, respectively)		309			309
Additional paid-in capital		422,597			420,778
Retained earnings (deficit)		(102,064	)		46,218
Accumulated other comprehensive loss, net of tax		(1,359	)		(1,299	)
Total shareholders' equity		319,483			466,006
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	947,469		$	1,111,581

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
	March 31,
	2009			2008
				(Restated)
	(In thousands except
	per share amounts)
OIL AND NATURAL GAS REVENUES	$	31,203		$	53,560

COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of depreciation, depletion
and amortization shown separately below)		8,037			8,391
Third party gas purchases		550			-
Depreciation, depletion and amortization		16,543			14,087
Impairment of oil and natural gas properties		252,195			-
General and administrative (inclusive of stock-based compensation expense of
$3,426 and $1,480 for the three months ended March 31, 2009 and 2008,
respectively)		7,900			6,519
Accretion expense related to asset retirement obligations		71			58

TOTAL COSTS AND EXPENSES		285,296			29,055

OPERATING INCOME (LOSS)		(254,093	)		24,505

OTHER INCOME AND EXPENSES:
Gain (loss) on derivatives, net		30,090			(29,816	)
Interest income		6			148
Interest expense (inclusive of non-cash interest expense of $3.0 million associated
with the senior convertible notes for the three months ended March 31, 2009)		(9,060	)		(6,455	)
Capitalized interest		4,951			3,718
Other income and expenses, net		45			69

LOSS BEFORE INCOME TAXES		(228,061	)		(7,831	)
INCOME TAX BENEFIT		79,779			2,535

NET LOSS	$	(148,282	)	$	(5,296	)

OTHER COMPREHENSIVE LOSS:
Decrease in market value of investment in Pinnacle Gas Resources, Inc.,
net of taxes		(60	)		(3,197	)
COMPREHENSIVE LOSS	$	(148,342	)	$	(8,493	)

BASIC LOSS PER SHARE	$	(4.80	)	$	(0.18	)
DILUTED LOSS PER SHARE	$	(4.80	)	$	(0.18	)

WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC		30,883			29,152
DILUTED		30,883			29,152

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

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Index

CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Three
	Months Ended
	March 31,
	2009			2008
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(148,282	)	$	(5,296	)
Adjustments to reconcile net loss to net
cash provided by operating activities-
Depreciation, depletion and amortization		16,543			14,087
Impairment of oil and gas properties		252,195			-
Fair value (gain) loss of derivative financial instruments		(7,489	)		28,072
Provision for allowance for doubtful accounts		222			-
Accretion of discounts on asset retirement obligations		71			58
Stock-based compensation		3,426			1,480
Deferred income taxes		(79,844	)		(2,740	)
Other		4,259			145
Changes in operating assets and liabilities
Accounts receivable		(4,315	)		(5,124	)
Other assets		(245	)		922
Accounts payable		2,388			7,258
Accrued liabilities		4,443			2,335
Net cash provided by operating activities		43,372			41,197

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(54,507	)		(115,571	)
Change in capital expenditure accrual		(14,024	)		(9,289	)
Proceeds from the sale of properties		6			5
Advances to operators		(508	)		(55	)
Advances for joint operations		3,600			(220	)
Other		(57	)		(5	)
Net cash used in investing activities		(65,490	)		(125,135	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from debt issuance and borrowings		24,000			51,000
Debt repayments		(3,929	)		(85,563	)
Proceeds from common stock offering, net of offering costs		-			135,233
Proceeds from stock options exercised		-			76
Deferred loan costs and other		(26	)		(65	)
Net cash provided by financing activities		20,045			100,681

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(2,073	)		16,743

CASH AND CASH EQUIVALENTS, beginning of period		5,184			8,026

CASH AND CASH EQUIVALENTS, end of period	$	3,111		$	24,769

CASH PAID FOR INTEREST (NET OF AMOUNTS CAPITALIZED)	$	-		$	2,466

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

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Index

CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles. The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances. The financial statements reflect necessary adjustments, all of which were of a recurring nature and are in the opinion of management necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading. The financial statements included herein should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 (the “2008 Form 10-K”).

Unconsolidated Investments

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

The Company’s investment in Pinnacle Gas Resources, Inc. is classified as available-for-sale. The Company adjusts the book value to fair market value through other comprehensive income (loss), net of taxes.

Reclassifications

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

Use of Estimates

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

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of undeveloped properties, future income taxes and related assets/liabilities, the collectability of outstanding accounts receivable, fair values of derivatives, stock-based compensation expense, contingencies and the results of current and future litigation. Oil and natural gas reserve estimates, which are the basis for unit-of-production depletion and the ceiling test, have numerous inherent uncertainties. The accuracy of any reserve estimates is a function of the quality and quantity of available data and the application of engineering and geological interpretation and judgment to available data. Subsequent drilling, testing and production may justify revision of such estimates. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. In addition, reserve estimates may be affected by changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

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

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Index

Oil and Natural Gas Properties

Investments in oil and natural gas properties are accounted for using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of oil and natural gas properties are capitalized. Such costs include lease acquisitions, seismic surveys, and drilling and completion equipment. The Company proportionally consolidates its interests in oil and natural gas properties. The Company capitalized employee-related costs for employees working directly on exploration activities of $1.5 million and $2.1 million for the three months ended March 31, 2009 and 2008, respectively. Maintenance and repairs are expensed as incurred.

Depreciation, depletion and amortization (“DD&A”) of proved oil and natural gas properties is based on the unit-of-production method using estimates of proved reserve quantities. Investments in unproved properties are not subject to DD&A until proved reserves associated with the projects can be determined or until they are impaired. Unevaluated properties are evaluated periodically for impairment on a property-by-property basis. If the results of an assessment indicate that the properties have been impaired, the amount of such impairment is determined and added to the proved oil and natural gas property costs subject to DD&A. The depletable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per Mcfe for the quarters ended March 31, 2009 and 2008 was $1.99 and $2.19, respectively.

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

Net capitalized costs are limited to a “ceiling-test” based on the estimated future net revenues, discounted at 10% per annum, from proved oil and natural gas reserves, based on current economic and operating conditions. If net capitalized costs exceed this limit, the excess is charged to earnings. For the first quarter of 2009, the Company elected to use a pricing date subsequent to the balance sheet date, as allowed by current SEC guidelines, to calculate the full cost ceiling test. Using prices as of May 6, 2009, the Company incurred an impairment charge of $252.2 million ($163.9 million net of tax). Had the Company used prices in effect as of the balance sheet date, an impairment of $358.2 million ($232.9 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 will no longer be available to the Company starting December 31, 2009 due to the adoption of the new oil and natural gas reporting requirements as described below under “Recently Issued Accounting Pronouncements.”

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

Supplemental Cash Flow Information

The adjustment of the investment in Pinnacle of $0.1 million, net of tax and $3.2 million, net of tax is excluded from the Statement of Cash Flows for the three months ended March 31, 2009 and 2008, respectively. The Company paid no income taxes during the three months ended March 31, 2009 and 2008.

Stock-Based Compensation

The Company records stock-based compensation as prescribed by the Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004), “Share-Based Payment” (“SFAS No. 123(R)”). The compensation expense associated with stock options is based on the grant-date fair value of the options and recognized over the vesting period. Restricted stock is recorded as deferred compensation based on the closing price of the Company’s stock on the issuance date and is amortized to stock-based compensation expense ratably over the vesting period of the restricted shares (generally one to three years).

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Index

The Company recognized the following stock-based compensation expense for the three months ended March 31:

	Three Months
	Ended March 31,
	2009		2008
	(In millions)
Restricted Stock Expense	$	3.4	$	1.4
Stock Option Expense		-		0.1

Total Stock-Based Compensation Expense	$	3.4	$	1.5

Derivative Instruments

The Company uses derivatives to manage price risk underlying its oil and natural gas production. The Company also used derivatives to manage the variable interest rate on its borrowings under the second lien credit facility, which was terminated in May 2008.

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

The Company typically uses fixed-rate swaps, costless collars, puts and calls to hedge its exposure to material changes in the price of oil and natural gas.

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

Major Customers

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

	Three Months
	Ended March 31,
	2009			2008
Cokinos Natural Gas Company		11	%		-
Houston Pipeline Co.		-			13	%
Crosstex Energy Services, Ltd.		-			13	%
DTE Energy Trading, Inc.		57	%		34	%

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Index

Earnings Per Share

Supplemental earnings per share information is provided below:

	Three Months
	Ended March 31,
	2009			2008
	(In thousands, except
	per share amounts)

Net loss	$	(148,282	)	$	(5,296	)

Average common shares outstanding
Weighted average common shares outstanding (1)		30,883			29,152
Stock options		-			-
Diluted weighted average common shares outstanding		30,883			29,152

Loss per common share
Basic	$	(4.80	)	$	(0.18	)
Diluted	$	(4.80	)	$	(0.18	)

__________

(1)

In January 2009, the Company adopted and retroactively applied the Financial Accounting Standards Board's (“FASB”) Staff Position (“FSP”) Emerging Issues Task Force 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“EITF 03-6-1”). As prescribed in the accounting pronouncement, the Company has determined that all of its shares of restricted stock are participating securities and should be included in the basic earnings per share calculation (see Note 2 for additional details).

Basic earnings per common share is based on the weighted average number of shares of common stock (including restricted stock) outstanding during the periods. Diluted earnings per common share is based on the weighted average number of common shares and all dilutive potential common shares issuable during the periods. The Company did not include options to purchase 685,854 and 746,921 shares in the calculation of dilutive shares for the three months ended March 31, 2009 and 2008 due to the net loss for both quarters. Shares of common stock subject to issuance pursuant to the conversion features of the 4.375% Convertible Senior Notes due 2028 (the “Convertible Senior Notes”) did not have an effect on the calculation of dilutive shares for the three months ended March 31, 2009.

Income Taxes

Under SFAS No. 109 “Accounting for 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 assess the realizability of its deferred tax assets and considers future taxable income 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 under accounting standards, the assets are reduced by a valuation allowance. However, despite the Company’s attempt to make an accurate estimate, the ultimate utilization of the deferred tax assets is highly dependent upon actual production and the realization of taxable income in future periods.

Recently Issued Accounting Pronouncements

On December 31, 2008, the SEC adopted major revisions to its rules governing oil and gas company reporting requirements. These new rules will permit the use of new technologies to determine proved reserves and allow companies to disclose their probable and possible reserves to investors. The current rules limit disclosure to only proved reserves. The new rules require companies to report the independence and qualification of the person primarily responsible for the preparation or audit of its reserve estimates, and to file reports when a third party is relied upon to prepare or audit its reserves estimates. The new rules also require that the net present value of oil and gas reserves reported and used in the full cost ceiling test calculation be based upon an average price for the prior 12-month period. The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after

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Index

December 31, 2009, with early adoption not permitted. The Company is in the process of assessing the impact of these new requirements on its financial position, results of operations and financial disclosures.

In April 2009, the FASB issued FSP No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP FAS 157-4”), which provides additional guidance for estimating fair value in accordance with SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). FSP FAS 157-4 is effective for the quarter ending June 30, 2009. The Company is currently evaluating the requirements of this pronouncement and has not determined the impact, if any, that adoption will have on its consolidated financial statements.

In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (FSP FAS 115-2”), which provides new guidance on the recognition of other-than-temporary impairments of investments in debt securities and provides new presentation and disclosure requirements for other-than-temporary impairments of investments in debt and equity securities. FSP FAS 115-2 is effective for the quarter ending June 30, 2009. The Company is currently evaluating the requirements of this pronouncement and has not determined the impact, if any, that adoption will have on its consolidated financial statements.

In April 2009, the FASB issued FSP No. FAS 107-1 and ABP 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1”). FSP FAS 107-1 amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” (“SFAS 107”) to require disclosures about fair value of financial instruments in interim reporting periods. Such disclosures were previously required only in annual financial statements. FSP FAS 107-1 is effective for the quarter ending June 30, 2009. The Company is currently evaluating the requirements of this pronouncement and has not determined the impact, if any, that adoption will have on its consolidated financial statements.

2.	RESTATEMENT FOR IMPLEMENTATION OF NEW ACCOUNTING PRONOUNCEMENT

On January 1, 2009, the Company adopted FSP No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlements)” (“APB 14-1”), which clarifies the accounting for convertible debt instruments that may be settled in cash (including partial cash settlement) upon conversion. APB 14-1 requires that issuers of convertible debt separately account for the liability and equity components in a manner that reflects the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. Once adopted, APB 14-1 requires retrospective application to the terms of instruments as they existed for periods presented. The adoption of APB 14-1 affects the accounting for the Convertible Senior Notes. The retrospective application of this accounting pronouncement affects the Company’s balance sheet as of December 31, 2008 and results of operations for the year ended December 31, 2008.

On January 1, 2009, the Company adopted and retroactively applied EITF 03-6-1. This FSP provides that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share. This FSP requires retroactive application for all periods presented. The Company determined that its restricted shares of common stock are participating securities as defined in this FSP and applied this FSP retroactively to all periods presented.

The following table sets forth the effect of the retrospective application of EITF 03-6-1 and APB 14-1 on certain previously reported items.

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Index

Consolidated Statement of Income:

	March 31, 2008
	Originally			As
	Reported			Restated
	(In thousands, except per
	share amounts)

Basic Loss Per Share	$	(0.18	)	$	(0.18	)
Diluted Loss Per Share	$	(0.18	)	$	(0.18	)

Weighted Average Common Shares Outstanding
Basic		28,799			29,152
Diluted		28,799			29,152

Consolidated Balance Sheet:

	December 31, 2008
	Originally					As
	Reported		Adjustment			Restated
	(In thousands)
Property and Equipment	$	1,021,621	$	4,887		$	1,026,508
Deferred Financing Costs, net		9,750		(1,320	)		8,430
Long-Term Debt, net of current maturities		533,057		(57,269	)		475,788
and unamortized discount
Deferred Income Taxes		26,920		21,816			48,736
Additional Paid-In Capital		380,571		40,207			420,778
Retained Earnings		47,405		(1,187	)		46,218
Total Shareholders' Equity		426,986		39,020			466,006

3.	LONG-TERM DEBT

Long-term debt consisted of the following at March 31, 2009 and December 31, 2008:

	March 31,			December 31,
	2009			2008
				(Restated)(1)
	(In thousands)
Convertible Senior Notes	$	373,750		$	373,750
Unamortized discount for Convertible Senior Notes		(54,270	)		(57,269	)
Senior Secured Revolving Credit Facility		180,000			159,000
Other		480			480
		499,960			475,961
Current maturities		(173	)		(173	)

	$	499,787		$	475,788

__________

(1)	See Note 2 for a discussion of the restatement related to the implementation of APB 14-1.

Convertible Senior Notes

In May 2008, the Company issued $373.8 million aggregate principal amount of the Convertible Senior Notes. Interest is payable on June 1 and December 1 each year, commencing December 1, 2008. The notes will be convertible, using a net share settlement process,

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into a combination of cash and Carrizo common stock that entitles holders of the Convertible Senior Notes to receive cash up to the principal amount ($1,000 per note) and common stock in respect of the remainder, if any, of Carrizo’s conversion obligation in excess of such principal amount.

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

Holders may convert the notes only under the following conditions: (a) during any calendar quarter if the last reported sale price of Carrizo common stock exceeds 130 percent of the conversion price for at least 20 trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter, (b) during the five business days after any five consecutive trading day period in which the trading price per $1,000 principal amount of the notes is equal to or less than 97% of the conversion value of such notes, (c) during specified periods if specified distributions to holders of Carrizo common stock are made or specified corporate transactions occur, (d) prior to the close of business on the business day preceding the redemption date if the notes are called for redemption or (e) on or after March 31, 2028 and prior to the close of business on the business day prior to the maturity date of June 1, 2028.

The holders of the Convertible Senior Notes may require the Company to repurchase the notes on June 1, 2013, 2018 and 2023, or upon a fundamental corporate change at a repurchase price in cash equal to 100 percent of the principal amount of the notes to be repurchased plus accrued and unpaid interest, if any. The Company may redeem notes at any time on or after June 1, 2013 at a redemption price equal to 100 percent of the principal amount of the notes to be redeemed plus accrued and unpaid interest, if any.

The Convertible Senior Notes are subject to customary non-financial covenants and events of default, including a cross default under the Senior Credit Facility, 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 Secured Revolving Credit Facility.

In connection with the implementation of APB 14-1 (described in Note 2), as of May 21, 2008, the Company valued the Convertible Senior Notes as $309.6 million of debt and $64.2 million of equity representing the fair value of the conversion premium. The resulting debt discount will be 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 and will result in an effective interest rate of approximately 8% for the Convertible Senior Notes.

Senior Secured Revolving Credit Facility

On May 25, 2006, the Company entered into a Senior Secured Revolving Credit Facility (“Senior Credit Facility”) with JPMorgan Chase Bank, National Association, as administrative agent. The Senior Credit Facility provided for a revolving credit facility up to the lesser of the borrowing base and $200.0 million. It is secured by substantially all of the Company’s proved oil & gas assets and is guaranteed by the Company’s subsidiaries, CCBM, Inc., CLLR, Inc., Carrizo (Marcellus) LLC and Carrizo Marcellus Holdings, Inc.

In the fourth quarter of 2008, the Company amended the Senior Credit Facility to, among other things, (a) extend the maturity date to October 29, 2012; (b) change the semi-annual borrowing base redetermination dates to March 31 and September 30; and (c) replace JPMorgan Chase Bank with Guaranty Bank as the administrative agent bank.

In April 2009, the Company amended the Senior Credit Facility to, among other things, (a) adjust the maximum ratio of total net debt to Consolidated EBITDAX; (b) modify the calculation of total net debt for purposes of determining the ratio of total net debt to Consolidated EBITDAX to exclude the following amounts, which represent a portion of the Convertible Senior Notes deemed to be an equity component under APB 14-1: $51,252,980 during 2009, $38,874,756 during 2010, $26,021,425 during 2011 and $12,674,753 during 2012 until the maturity date; (c) add a new senior leverage ratio; (d) modify the interest rate margins applicable to Eurodollar loans; (e) modify the interest rate margins applicable to base rate loans; and (f) establish new procedures governing the modification of swap agreements.

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Index

Also in April 2009, the Company amended the Senior Credit Facility to increase the borrowing base to $290,000,000 and, on May 1, 2009, the total commitment of the lenders was increased to $259,400,000.

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 2.0% to 3.5% (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 March 31, 2009, the average interest rate for amounts outstanding under the Senior Credit Facility was 3.3%.

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; and (2) a maximum total net debt to Consolidated EBITDAX (as defined in the Senior Credit Facility) of (a) 4.25 to 1.00 for the quarter ending June 30, 2009, (b) 4.50 to 1.00 for the quarter ending September 30, 2009, (c) 4.75 to 1.00 for each quarter ending on or after December 31, 2009 and on or before September 30, 2010, (d) 4.25 to 1.00 for the quarter ending December 31, 2010, and (e) 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 debt attributable to the Convertible Senior Notes) to Consolidated EBITDAX of 2.25 to 1.00.

Although the Company currently believes that it can comply with all of the financial covenants with the business plan that it has put in place, the business plan is based on a number of assumptions, the most important of which is a relatively stable, natural gas price at economically sustainable levels. If the price that the Company receives for our natural gas production deteriorates significantly from current levels, it could lead to lower revenues, cash flow and earnings, which in turn could lead to a default under certain financial covenants in the Senior Credit Facility, including the financial covenants discussed above. In order to provide a further margin of comfort with regards to these financial covenants, the Company may seek to further reduce its capital and exploration budget, sell non-strategic assets, opportunistically modify or increase its natural gas hedges or approach the lenders under our Senior Credit Facility for modifications of either or both of the financial covenants discussed above. There can be no assurance that the Company will be able to successfully execute any of these strategies, or if executed, that they will be sufficient to avoid a default under our Senior Credit Facility if a precipitous decline in natural gas prices were to occur in the future. 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, speculative commodity transactions, 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 March 31, 2009, the Company had $180.0 million of borrowings outstanding under the Senior Credit Facility and the borrowing base availability was $70.0 million.

4.	INVESTMENTS

Investments consisted of the following at March 31, 2009 and December 31, 2008:

	March 31,		December 31,
	2009		2008
	(In thousands)
Pinnacle Gas Resources, Inc.	$	659	$	751
Oxane Materials, Inc.		2,523		2,523

	$	3,182	$	3,274

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Pinnacle Gas Resources, Inc.

In 2003, the Company and its wholly-owned subsidiary CCBM, Inc. (“CCBM”) contributed their interests in certain natural gas and oil leases in Wyoming and Montana in areas prospective for coalbed methane to a newly formed entity, Pinnacle Gas Resources, Inc. (“Pinnacle”). As of March 31, 2009, the Company owned 2,439,238 shares of Pinnacle common stock.

The Company classifies the Pinnacle investment as available-for-sale and adjusts the investment to fair value through other comprehensive income. At March 31, 2009, the Company reported the fair value of the stock at $0.7 million (based on the closing price of Pinnacle’s common stock on March 31, 2009), which is approximately $2.1 million below original cost. The last date on which the fair value of the Company’s investment in Pinnacle was in excess of, or equal to, the original cost of approximately $2.8 million was in October 2008. Management currently believes that this decrease in value below the original cost that commenced in October 2008 is temporary. If the impairment is other than temporary, the loss will be reclassified on the Statements of Operations from Other Comprehensive Loss to Other Income and Expenses.

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. The Company accounts for the investment using the cost method.

5.	INCOME TAXES

The Company provided deferred federal income taxes at the rate of 35% (which also approximates its statutory rate) that amounted to a federal tax benefit of $79.8 million and $2.7 million for the three months ended March 31, 2009 and 2008, respectively. At March 31, 2009, the Company had a net deferred tax asset of $22.1 million. The Company has determined that its deferred tax assets are fully realizable thus no valuation allowance for the net asset is currently needed.

On January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 prescribes a measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return. Additionally, FIN 48 provides guidance regarding uncertain tax positions relating to derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The Company classifies interest and penalties associated with income taxes as interest expense. At March 31, 2009, the Company had no material uncertain tax positions and the tax years 2003 through 2007 remained open to review by federal and various state tax jurisdictions.

6.	COMMITMENTS AND CONTINGENCIES

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

The operations and financial position of the Company continue to be affected from time to time in varying degrees by domestic and foreign political developments as well as legislation and regulations pertaining to restrictions on oil and natural gas production, imports and exports, natural gas regulation, tax increases, environmental regulations and cancellation of contract rights. Both the likelihood and overall effect of such occurrences on the Company vary greatly and are not predictable.

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7.	SHAREHOLDERS’ EQUITY

The following is a summary of changes in the Company’s common stock for the three months ended March 31:

	2009		2008
	(In thousands)
Shares outstanding at January 1		30,860		28,009
Equity offering		-		2,588
Restricted stock issued, net of forfeitures		19		9
Stock options exercised		-		15
Common stock issued for oil and gas properties		10		-
Common stock repurchased and retired for tax withholding obligation		-		(1	)
Shares outstanding at March 31		30,889		30,620

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

8.	DERIVATIVE INSTRUMENTS

The Company enters into swaps, options, collars and other derivative contracts to manage price risks associated with a portion of anticipated future oil and natural gas production. The Company also used interest rate swap agreements to manage the Company’s exposure to interest rate fluctuations on borrowings under the Company’s second lien credit facility, which was terminated in May 2008.

The Company accounts for its oil and natural gas derivatives and interest rate swap agreements as non-designated hedges. These derivatives are marked-to-market at each balance sheet date and the unrealized gains (losses) along with the realized gains (losses) associated with the settlements of derivative instruments are reported as net gain (loss) on derivatives, in other income and expenses in the Consolidated Statements of Operations. For the three months ended March 31, 2009 and 2008, the Company recorded the following related to its derivatives:

	Three Months
	Ended March 31,
	2009		2008
	(In millions)
Realized gains (losses):
Natural gas and oil derivatives	$	22.6	$	(1.5	)
Interest rate swaps - second lien debt outstanding		-		(0.2	)
		22.6		(1.7	)

Unrealized gains (losses):
Natural gas and oil derivatives		7.5		(25.9	)
Interest rate swaps		-		(2.2	)
		7.5		(28.1	)

Net gain (loss) on derivatives	$	30.1	$	(29.8	)

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At March 31, 2009, the Company had the following outstanding derivative positions:

	Natural Gas				Natural Gas						Basis Differential
	Swaps				Collars						Swaps(3)
			Average				Average		Average
Quarter	MMBtu(1)		Fixed Price(2)		MMBtu		Floor Price(2)		Ceiling Price(2)		MMbtu		Fixed Price
Second Quarter 2009		5,187,000	$	5.34		2,548,000	$	7.12	$	8.85		-	$	-
Third Quarter 2009		3,680,000		5.31		2,576,000		7.16		8.88		1,840,000		0.27
Fourth Quarter 2009		3,680,000		5.58		2,576,000		7.17		8.90		-		-
First Quarter 2010		1,800,000		5.57		1,620,000		7.92		9.63		-		-
Second Quarter 2010		1,820,000		5.57		182,000		7.35		9.15		-		-
Third Quarter 2010		1,840,000		5.57		184,000		7.35		9.15		-		-
Fourth Quarter 2010		1,840,000		5.57		184,000		7.35		9.15		-		-
First Quarter 2011		1,800,000		5.64		450,000		9.70		11.70		-		-
Second Quarter 2011		1,820,000		5.64		455,000		8.25		10.25		-		-
Third Quarter 2011		1,840,000		5.64		460,000		8.65		10.65		-		-
Fourth Quarter 2011		1,840,000		5.64		460,000		8.85		10.85		-		-
First Quarter 2012		910,000		5.88		455,000		9.55		11.55		-		-
Second Quarter 2012		910,000		5.88		455,000		8.35		10.35		-		-
Third Quarter 2012		920,000		5.88		-		-		-		-		-
Fourth Quarter 2012		920,000		5.88		-		-		-		-		-
		30,807,000				12,605,000						1,840,000

__________

(1)

In the first quarter of 2009, the Company entered into $3.00 puts on 910,000, 920,000 and 920,000 MMBtu in each of the second, third and fourth quarters of 2009, respectively, for a portion of our production hedged with swaps. Also in the first quarter of 2009, the Company entered into a $5.35 put, a $6.20 long-call and an $8.00 short-call with respect to a portion of the Company’s production hedged with swaps (10,000 MMBtu per day) in 2011 and 2012.

(2)	Based on Houston Ship Channel (“HSC”) and WAHA spot prices.

(3)	Basis differential swaps covering the price differential for natural gas between NYMEX and HSC.

At March 31, 2009, approximately 55% of the Company’s open natural gas hedges were with Credit Suisse First Boston (Credit Suisse), and the remaining 45% were with Shell Energy North America (US), L.P.

The fair value of the outstanding derivatives at March 31, 2009 and December 31, 2008 was a net asset of $46.2 million and $38.7 million, respectively.

9.	FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

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

	Level 1		Level 2		Level 3		Total
	(in thousands)
Assets:
Investment in Pinnacle Gas Resources, Inc.	$	659	$	-	$	-	$	659
Oil and natural gas derivatives		-		46,156		-		46,156

Total	$	659	$	46,156	$	-	$	46,815

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

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

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following is management’s discussion and analysis of certain significant factors that have affected certain aspects of the Company’s financial position and results of operations during the periods included in the accompanying unaudited financial statements. You should read this in conjunction with the discussion under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the audited financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2008 and the unaudited financial statements included elsewhere herein.

General Overview

Our first quarter 2009 included revenues of $31.2 million and record production of 8.3 Bcfe. The key drivers to our results for the three months ended March 31, 2009 included the following:

Drilling program. Our success is largely dependent on the results of our drilling program. During the three months ended March 31, 2009, we drilled 11 gross wells (10.2 net wells) in the Barnett Shale area with an apparent success rate of 100%. At March 31, 2009 we had an inventory of 40 gross wells (32.4 net) in the Barnett Shale that have been drilled and are waiting on hydraulic fracturing, completion and hook-up to sales.

Production. Our first quarter 2009 production of 8.3 Bcfe, or 91.8 MMcfe/d, was a record high. The first quarter 2009 production increased 14% from the fourth quarter 2008 production of 7.2 Bcfe and increased 30% from the first quarter 2008 production of 6.3 Bcfe. These increases were primarily attributable to the addition of new wells in the Barnett Shale area and were partially offset by the natural decline of other properties.

Commodity prices. Our average natural gas price during the first quarter of 2009 was $3.63 per Mcf (excluding the impact of our hedges), $4.43 per Mcf, or 55%, lower than the price in the first quarter of 2008 and $1.21 per Mcf, or 25%, lower than the price in the fourth quarter of 2008. Primarily as a result of these depressed commodity prices, we recorded a full cost ceiling test impairment of $252.2 million for the first quarter of 2009.

Financial flexibility. In April 2009, we improved our financial flexibility through an amendment to our senior secured revolving credit facility (the “Senior Credit Facility”) that (a) increased the maximum total debt leverage ratio under the Senior Credit Facility through 2010 to as high as 4.75 to 1, (b) refined the definition of Net Debt in the leverage ratio to exclude a portion of our 4.375% Senior Convertible Notes due 2028 (the “Senior Convertible Notes”) (starting at $51 million in 2009) and (c) added a senior debt leverage covenant with a maximum ratio of 2.25 to 1. In addition, the borrowing base under the Senior Credit Facility was increased to $290 million and, on May 1, 2009, the total commitments of the lenders were increased to $259.4 million. See “Senior Credit Facility” for more information.

Outlook

Our outlook for 2009 remains challenging as natural gas prices continue to decline but the outlook for our long-term future remains positive. Production growth and stable upward movement in commodity prices are key to our future success. We believe the following measures will continue to have a positive impact on our 2009 results:

We plan to continue efforts to control capital costs. During the first quarter of 2009, we spent approximately $40.0 million of capital expenditures on our drilling program and $8.8 million on leasehold and seismic costs. We currently have a 2009 capital and exploration budget of $105.0 million, which we currently expect to fund through cash generated from our operations or from cash available under the Senior Credit Facility. For a further discussion of our 2009 capital budget and funding strategy, see “Liquidity and Capital Resources—2009 Capital Budget and Funding Strategy” and “Liquidity and Capital Resources—Sources and Uses of Cash.”

·	We plan to continue the development of the Marcellus Shale in the Northeastern United States, primarily through joint ventures with ACP II Marcellus, LLC and with other industry partners.

We expect to continue to hedge production to decrease our exposure to reductions in natural gas prices. At March 31, 2009, we had hedged approximately 43,412,000 MMBtus of natural gas production through 2012. During the first quarter of 2009, we put additional calls and puts on our production designed to further decrease our exposure to declining natural gas prices.

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Results of Operations

Three Months Ended March 31, 2009,

Compared to the Three Months Ended March 31, 2008

Revenues from oil and natural gas production for the three months ended March 31, 2009 decreased 43% to $30.7 million from $53.6 million for the same period in 2008 due to declining oil and natural gas prices. Production volumes for natural gas for the three months ended March 31, 2009 increased 33% to 8.0 Bcf from 6.0 Bcf for the same period in 2008. Average natural gas prices, excluding the impact of our settled derivatives gain of $19.8 million and loss of $1.1 million for the quarters ended March 31, 2009 and 2008, respectively, decreased to $3.63 per Mcf in the first quarter of 2009 from $8.06 per Mcf in the same period in 2008. Average oil prices, excluding the impact of our settled derivative gain of $2.8 million and loss of $(0.4) million for the quarters ended March 31, 2009 and 2008, respectively, decreased 59% to $39.38 per barrel from $96.10 per barrel in the same period in 2008. The increase in natural gas production volume was due primarily to new production from wells in the Barnett Shale that commenced production since the first quarter of 2008. These increases were partially offset by the natural decline of other properties.

The following table summarizes production volumes, average sales prices (excluding the impact of derivatives) and operating revenues for the three months ended March 31, 2009 and 2008:

	For the Three				2009 Period
	Months Ended				Compared to 2008 Period
	March 31,				Increase			% Increase
	2009		2008		(Decrease)			(Decrease)
Production volumes
Oil and condensate (MBbls)		44		53		(9	)		(17	)%
Natural gas (MMcf)		7,994		6,014		1,980			33	%
Average sales prices
Oil and condensate (per Bbl)	$	39.38	$	96.10	$	(56.72	)		(59	)%
Natural gas (per Mcf)		3.63		8.06		(4.43	)		(55	)%
Operating revenues (In thousands)
Oil and condensate	$	1,734	$	5,095	$	(3,361	)		(66	)%
Natural gas		28,999		48,465		(19,466	)		(40)	%
Other		470		-		470			-

Total Operating Revenues	$	31,203	$	53,560	$	(22,357	)		(42)	%

Oil and natural gas operating expenses for the three months ended March 31, 2009 decreased four percent to $8.0 million from $8.4 million for the same period in 2008, primarily as a result of decreased severance tax expense of $2.5 million associated with decreased revenues, partially offset by higher lifting costs of $1.1 million primarily attributable to increased production and the increased number of producing wells and increased transportation and other product costs of $1.0 million mainly attributable to increased production in the Barnett Shale area.

Depreciation, depletion and amortization (DD&A) expense for the three months ended March 31, 2009 increased 17% to $16.5 million ($2.00 per Mcfe) from $14.1 million ($2.22 per Mcfe) for the same period in 2008. This increase in DD&A was primarily due to an increase in production volumes partially offset by a lower depletion rate primarily due to the fourth quarter 2008 ceiling test impairment.

The significant decline in oil and natural gas prices since December 31, 2008, indicated by average posted prices of $3.17 per Mcf for natural gas and $51.76 per Bbl for oil on May 6, 2009, caused the discounted present value (discounted at ten percent) of future net cash flows from our proved oil and gas reserves to fall below our net book basis in the proved oil and gas properties. This resulted in a non-cash, ceiling test write-down at the end of the first quarter of 2009 of $252.2 million ($163.9 million after tax).

General and administrative expense for the three months ended March 31, 2009 increased by $1.4 million to $7.9 million from $6.5 million for the corresponding period in 2008 primarily as a result of increased stock-based compensation of $1.9 million related to payment of 2008 discretionary bonuses to non-executive employees in Company stock, partially offset by a decrease of $1.0 million in compensation and other employee-related expenses.

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The net gain on derivatives of $30.1 million in the first quarter of 2009 was comprised of $22.6 million of realized gain on net settled oil and natural gas derivatives and $7.5 million of net unrealized mark-to-market gain on derivatives. The net loss on derivatives of $29.8 million in the first quarter of 2008 was comprised of $1.7 million of realized loss on net settled derivatives and $28.1 million of net unrealized mark-to-market loss on derivatives.

Interest expense and capitalized interest for the three months ended March 31, 2009 were $9.1 million and $5.0 million, respectively, as compared to $6.5 million and $3.7 million for the same period in 2008 primarily attributable to approximately $3.0 million in non-cash interest expense associated with the amortization of the debt discount on the Senior Convertible Notes as prescribed by APB 14-1.

Liquidity and Capital Resources

2009 Capital Budget and Funding Strategy. For 2009, our Board established a capital and exploration expenditures budget of $105 million, including $90 million for our drilling program, of which $85 million is designated for Barnett Shale development. We intend to finance our 2009 capital and exploration budget primarily from cash flows from operations, supplemented by available borrowings under the Senior Credit Facility and the possible selective sale of non-core assets. We may be required to reduce or defer part of our 2009 capital expenditures program if we are unable to obtain sufficient financing from these sources.

Sources and Uses of Cash. During the three months ended March 31, 2009, capital expenditures, net of proceeds from property sales, exceeded our net cash provided by operations. During 2009, we have funded our capital expenditures with cash generated from operations and net additional borrowings under the Senior Credit Facility. Potential primary sources of future liquidity include the following:

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

·	Available borrowings under the Senior Credit Facility. At May 1, 2009, $75.4 million was available for borrowing under the Senior Credit Facility. The next borrowing base redetermination is currently scheduled for the fourth quarter of 2009.

·	Debt and equity offerings. As situations or conditions arise, we may need to issue debt, equity or other instruments to supplement our cash flows. However, we may not be able to obtain such financing on terms that are acceptable to us, or at all.

·	Asset sales. In order to fund our capital and exploration budget, we may consider the sale of certain properties or assets that are not part of our core business, can be monetized at a price we find acceptable, or are no longer deemed essential to our future growth.

·	Project financing in certain limited circumstances.

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

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

·	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.

Our primary use of cash is capital expenditures to fund our drilling and development programs and, to a lesser extent, our lease and seismic acquisition programs. Our capital expenditures budget in 2009 provides for approximately $90 million for drilling, and approximately $15 million for leasing, land costs, seismic acquisitions and other capital expenses. We currently expect that substantially all of our 2009 drilling program in the Marcellus Shale will be funded by ACP II Marcellus, LLC under our joint venture agreement.

Overview of Cash Flow Activities. Cash flows provided by operating activities were $43.4 million and $41.2 million for the three months ended March 31, 2009 and 2008, respectively. The increase was primarily due to an increase in revenues largely attributable to

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a 30% increase in production. Natural gas prices have fallen since the third quarter of 2008 and have continued to decline in 2009, having a negative impact on our cash flow from operations and on our 2009 drilling plans. Despite our increase in natural gas production, further decreases in natural gas prices could have a further negative impact on our cash flow from operations and on our 2009 drilling plans.

Cash flows used in investing activities were $65.5 and $125.1 million for the three months ended March 31, 2009 and 2008 and related primarily to oil and gas property expenditures.

Net cash provided by financing activities for the three months ended March 31, 2009 was $20.0 million and related primarily to net borrowings under the Senior Credit Facility. Net cash provided by financing activities for the three months ended March 31, 2008 was $100.7 million and related primarily to net proceeds of $135.2 million from the issuance of common stock in February 2008. These cash proceeds were partially offset by the repayment of borrowings under the Senior Credit Facility.

Liquidity/Cash Flow Outlook.

We currently believe that cash generated from operations, supplemented by borrowings under the Senior Credit Facility, will be sufficient to fund our immediate needs. Cash generated from operations is primarily driven by production and commodity prices. While we have steadily increased production over the last few years, oil and natural gas prices have declined since the third quarter of 2008. In an effort to mitigate declining prices, we hedge a portion of our production and, as of March 31, 2009, we had hedged approximately 20,247,000 MMBtus (70 MMcf per day for the full year 2009, or 85% of our estimated production from April through December 2009) of our 2009 natural gas production at a weighted average floor or swap price of $6.07 per MMBtu relative to WAHA and HSC prices. We believe the funds available to us under the Senior Credit Facility, $75.4 million at May 1, 2009, will be accessible to us.

If cash from operations and funds available under the Senior Credit Facility are insufficient to fund our 2009 capital and exploration budget, we may need to reduce our capital and exploration budget 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 2009 natural gas and oil exploration and development program, thereby adversely affecting the recoverability and ultimate value of our natural gas and oil properties. The recent worldwide financial and credit crisis has adversely affected our ability to access the capital markets.

Senior Credit Facility

In April 2009, we amended the Senior Credit Facility to, among other things, (1) adjust the maximum ratio of total net debt to Consolidated EBITDAX to a maximum ratio of (a) 4.25 to 1.00 for the quarter ending June 30, 2009, (b) 4.50 to 1.00 for the quarter ending September 30, 2009, (c) 4.75 to 1.00 for each quarter ending on or after December 31, 2009 and on or before September 30, 2010, (d) 4.25 to 1.00 for the quarter ending December 31, 2010, and (e) 4.00 to 1.00 for each quarter ending on or after March 31, 2011; (2) modify the calculation of total net debt for purposes of determining the ratio of total net debt to Consolidated EBITDAX to exclude the following amounts, which represent a portion of the Convertible Senior Notes deemed to be an equity component under APB 14-1: $51,252,980 during 2009, $38,874,756 during 2010, $26,021,425 during 2011 and $12,674,753 during 2012 until the maturity date; (3) add a new senior leverage ratio, which requires that our ratio of senior debt (which excludes debt attributable to the Convertible Senior Notes) to Consolidated EBITDAX not exceed 2.25 to 1.00; (4) modify the interest rate margins applicable to Eurodollar loans to a range of between 2.25% and 3.25% (depending on the then-current level of borrowing base usage); (5) modify the interest rate margins applicable to base rate loans to a range of between 1.00% and 2.00% (depending on the then-current level of borrowing base usage); and (6) establish new procedures governing the modification of swap agreements.

Also in April 2009, we amended the Senior Credit Facility to increase the borrowing base to $290,000,000. In May 2009, the total commitments of the lenders under the Senor Credit Facility were increased to $259,400,000. The Company is currently seeking to add additional lenders to its Senior Credit Facility, in order to increase the lenders total commitments to $290,000,000.

As of May 1, 2009, we had $184.0 million of borrowings outstanding and a borrowing base availability of $75.4 million.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing natural gas and oil prices. The dramatic drop in natural gas and oil prices since the third quarter of 2008 has resulted in a significant drop in revenue per unit of production. Although operating costs have also declined, the rate of decline in natural gas and oil prices has been substantially greater. Historically, inflation has had a

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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

On January 1, 2009, we adopted the Financial Accounting Standards Board's (“FASB”) Staff Position No. APB 14-1, “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlements)” (“APB 14-1”), which clarifies the accounting for convertible debt instruments that may be settled in cash (including partial cash settlement) upon conversion. APB 14-1 requires that issuers of convertible debt separately account for the liability and equity components in a manner that reflects the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. Once adopted, ABP 14-1 requires retrospective application to the terms of instruments as they existed for periods presented. We applied this accounting pronouncement to the Convertible Senior Notes. We valued the conversion premium of the convertible debt at $64.2 million and accordingly restated our balance sheet as of December 31, 2008 for the carrying value of debt and equity and restated our results of operations for interest expense, capitalized interest, and income taxes for the year ended December 31, 2008. See Item 1, Notes to Consolidated Financial Statements, Note 2 for a discussion of the restatement related to the adoption of this accounting pronouncement.

On January 1, 2009, we adopted and retroactively applied FASB Staff Position (“FSP”) Emerging Issues Task Force 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“EITF 03-6-1”). This FSP provides that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents, whether paid or unpaid, are participating securities and shall be included in the computation of both basic and diluted earnings per share. This FSP requires retroactive application for all periods presented. We determined that our restricted shares of common stock are participating securities as defined in this FSP and applied this FSP retroactively to all periods presented. See Item 1, Notes to Consolidated Financial Statements, Note 2 for a discussion of the restatement related to the adoption of this accounting pronouncement.

Recently Issued Accounting Pronouncements

On December 31, 2008, the SEC adopted major revisions to its rules governing oil and gas company reporting requirements. These new rules permit the use of new technologies to determine proved reserves and that allow companies to disclose their probable and possible reserves to investors. The current rules limit disclosure to only proved reserves. The new rules require companies to report the independence and qualification of the person primarily responsible for the preparation or audit of its reserve estimates, and to file reports when a third party is relied upon to prepare or audit its reserves estimates. The new rules also require that the net present value of oil and gas reserves reported and used in the full cost ceiling test calculation be based upon an average price for the prior 12-month period. The new oil and gas reporting requirements are effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, with early adoption not permitted. We are in the process of assessing the impact of these new requirements on our financial position, results of operations and financial disclosures.

In April 2009, the FASB issued FSP No. 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly” (“FSP FAS 157-4”), which provides additional guidance for estimating fair value in accordance with SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). FSP FAS 157-4 is effective for the quarter ending June 30, 2009. We are currently evaluating the requirements of this pronouncement and have not determined the impact, if any, that adoption will have on our consolidated financial statements.

In April 2009, the FASB issued FSP No. FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments” (“FSP FAS 115-2”), which provides new guidance on the recognition of other-than-temporary impairments of investments in debt securities and provides new presentation and disclosure requirements for other-than-temporary impairments of investments in debt and equity securities. FSP FAS 115-2 is effective for the quarter ending June 30, 2009. We are currently evaluating the requirements of this pronouncement and have not determined the impact, if any, that adoption will have on our consolidated financial statements.

In April 2009, the FASB issued FSP No. FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (“FSP FAS 107-1”). FSP FAS 107-1 amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” to require disclosures about fair value of financial instruments in interim reporting periods. Such disclosures were previously required only in annual financial statements. FSP FAS 107-1 is effective for the quarter ending June 30, 2009. We are currently evaluating the requirements of this pronouncement and have not determined the impact, if any, that adoption will have on our consolidated financial statements.

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Critical Accounting Policies

The following summarizes our critical accounting policies:

Oil and Natural Gas Properties

We account for investments in natural gas and oil properties using the full-cost method of accounting. All costs directly associated with the acquisition, exploration and development of natural gas and oil properties are capitalized. These costs include lease acquisitions, seismic surveys, and drilling and completion equipment. We proportionally consolidate our interests in natural gas and oil properties. We capitalized compensation costs for employees working directly on exploration activities of $1.5 million and $2.1 million for the three months ended March 31, 2009 and 2008, respectively. We expense maintenance and repairs as they are incurred.

We amortize natural gas and oil properties based on the unit-of-production method using estimates of proved reserve quantities. We do not amortize investments in unproved properties until proved reserves associated with the projects can be determined or until these investments are impaired. We periodically evaluate, on a property-by-property basis, unevaluated properties for impairment. If the results of an assessment indicate that the properties are impaired, we add the amount of impairment to the proved natural gas and oil property costs to be amortized. The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values. The depletion rate per Mcfe for the three months ended March 31, 2009 and 2008 was $1.99 and $2.19, respectively.

We account for dispositions of natural gas and oil properties as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves. We have not had any transactions that significantly alter that relationship.

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

The Full Cost Ceiling impairment at March 31, 2009 of $252.2 million was based upon average May 6, 2009 realized oil, natural gas liquids and natural gas prices of $51.76 per Bbl, $24.51 per Bbl and $3.17 per Mcf, respectively, or a volume weighted average price of $23.32 per BOE. For the first quarter of 2009, we elected to use a pricing date subsequent to the balance sheet date, as allowed by current SEC guidelines, to calculate the full cost ceiling impairment. Had we used the March 31, 2009 average realized prices of oil, natural gas liquids and natural gas of $45.13 per Bbl, $18.92 per Bbl and $2.74 per Mcf, respectively, we would have incurred a ceiling test impairment of $358.2 million ($232.9 million after tax) during the first quarter of 2009. The option to use a pricing date subsequent to the balance sheet will no longer be available to us starting December 31, 2009 due to our mandatory adoption of the new oil and natural gas reporting requirements as described above under “Recently Issued Accounting Pronouncements”. These new rules will require the use of an average price over a twelve-month period. We would not have had a Full Cost Ceiling write-down at an estimated volume weighted average price of $36.35 per BOE. A BOE means one barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids, which approximates the relative energy content of oil, condensate and natural gas liquids as compared to natural gas. Prices have historically been higher or substantially higher, more often for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower. The Full Cost Ceiling impairment was primarily the result of the decline in commodity prices.

Under the full cost method of accounting, the depletion rate is the current period production as a percentage of the total proved reserves. Total proved reserves include both proved developed and proved undeveloped reserves. The depletion rate is applied to the net book value of our oil and natural gas properties, excluding unevaluated costs, plus estimated future development costs and salvage value, to calculate the depletion expense. Proved reserves materially impact depletion expense. If the proved reserves decline, then the depletion rate (the rate at which we record depletion expense) increases, reducing net income.

We have a significant amount of proved undeveloped reserves. We had 239.1 Bcfe of proved undeveloped reserves at December 31, 2008, representing 48% of our total proved reserves. As of December 31, 2008, a portion of these proved undeveloped reserves, or approximately 29.9 Bcfe, are attributable to our Camp Hill properties that we acquired in 1994. The estimated future development costs to develop our proved undeveloped reserves on our Camp Hill properties are relatively low, on a per Mcfe basis, when compared to the estimated future development costs to develop our proved undeveloped reserves on our other oil and natural gas properties. Furthermore, the average depletable life (the estimated time that it will take to produce all recoverable reserves) of our Camp Hill properties is considerably longer, or approximately 15 years, when compared to the depletable life of our remaining oil and natural gas

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properties of approximately 10 years. Accordingly, the combination of a relatively low ratio of future development costs and a relatively long depletable life on our Camp Hill properties has resulted in a relatively low overall historical depletion rate and DD&A expense. This has resulted in a capitalized cost basis associated with producing properties being depleted over a longer period than the associated production and revenue stream, causing the build-up of nondepleted capitalized costs associated with properties that have been completely depleted. This combination of factors, in turn, has had a favorable impact on our earnings, which have been higher than they would have been had the Camp Hill properties not resulted in a relatively low overall depletion rate and DD&A expense and longer depletion period. As a hypothetical illustration of this impact, the removal of our Camp Hill proved undeveloped reserves starting January 1, 2002 would have reduced our earnings by (a) an estimated $11.2 million in 2002 (comprised of after-tax charges for a $7.1 million full cost ceiling impairment and a $4.1 million depletion expense increase), (b) an estimated $5.9 million in 2003 (due to higher depletion expense), (c) an estimated $3.4 million in 2004 (due to higher depletion expense), (d) an estimated $6.9 million in 2005 (due to higher depletion expense), (e) an estimated $0.7 million in 2006 (due to higher depletion expense), (f) an estimated $2.0 million in 2007 (due to higher depletion expense), and (g) an estimated $11.7 million in 2008 (comprised of after tax charges for an $11.0 million full cost ceiling test impairment and a $0.7 million depletion expense increase).

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

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

For information regarding our other critical accounting policies, see the 2008 Form 10-K.

Volatility of Oil and Natural Gas Prices

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

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

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

The following table includes oil and natural gas positions settled during the three-month periods ended March 31, 2009 and 2008, and the unrealized gain/(loss) associated with the outstanding oil and natural gas derivatives at March 31, 2009 and 2008.

	Three months ended
	March 31,
	2009		2008

Oil positions settled (Bbls)		5,900		18,200
Natural gas positions settled (MMBtus)		6,385,000		4,280,000
Realized gain (loss) ($ millions) (1)	$	22.6	$	(1.5	)
Unrealized gain (loss) ($ millions) (1)	$	7.5	$	(25.9	)

__________

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

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At March 31, 2009, we had the following outstanding natural gas derivative positions:

	Natural Gas				Natural Gas						Basis Differential
	Swaps				Collars						Swaps(3)
			Average				Average		Average
Quarter	MMBtu(1)		Fixed Price(2)		MMBtu		Floor Price(2)		Ceiling Price(2)		MMbtu		Fixed Price
Second Quarter 2009		5,187,000	$	5.34		2,548,000	$	7.12	$	8.85		-	$	-
Third Quarter 2009		3,680,000		5.31		2,576,000		7.16		8.88		1,840,000		0.27
Fourth Quarter 2009		3,680,000		5.58		2,576,000		7.17		8.90		-		-
First Quarter 2010		1,800,000		5.57		1,620,000		7.92		9.63		-		-
Second Quarter 2010		1,820,000		5.57		182,000		7.35		9.15		-		-
Third Quarter 2010		1,840,000		5.57		184,000		7.35		9.15		-		-
Fourth Quarter 2010		1,840,000		5.57		184,000		7.35		9.15		-		-
First Quarter 2011		1,800,000		5.64		450,000		9.70		11.70		-		-
Second Quarter 2011		1,820,000		5.64		455,000		8.25		10.25		-		-
Third Quarter 2011		1,840,000		5.64		460,000		8.65		10.65		-		-
Fourth Quarter 2011		1,840,000		5.64		460,000		8.85		10.85		-		-
First Quarter 2012		910,000		5.88		455,000		9.55		11.55		-		-
Second Quarter 2012		910,000		5.88		455,000		8.35		10.35		-		-
Third Quarter 2012		920,000		5.88		-		-		-		-		-
Fourth Quarter 2012		920,000		5.88		-		-		-		-		-
		30,807,000				12,605,000						1,840,000

__________

(1)

In the first quarter of 2009, we entered into $3.00 puts on 910,000, 920,000 and 920,000 MMBtu in each of the second, third and fourth quarters of 2009, respectively, for a portion of our production hedged with swaps. Also in the first quarter of 2009, we entered into a $5.35 put, a $6.20 long-call and an $8.00 short-call with respect to a portion of the Company’s production hedged with swaps (10,000 MMBtus per day) in 2011 and 2012.

(2)	Based on Houston Ship Channel (“HSC”) and WAHA spot prices.

(3)	Basis differential swaps covering the price differential for natural gas between NYMEX and HSC.

As of March 31, 2009, approximately 55% of our open natural gas hedges were with Credit Suisse as the counterparty, and the remaining 45% were with Shell Energy North America (U.S.), L.P. as the counterparty.

While the use of hedging arrangements limits the downside risk of adverse price movements, it may also limit our ability to benefit from increases in the prices of natural gas and oil. We enter into the majority of our derivatives transactions with two counterparties and have a netting agreement in place with those counterparties. We do not obtain collateral to support the agreements but monitor the financial viability of counterparties and believe our credit risk is minimal on these transactions. Under these arrangements, payments are received or made based on the differential between a fixed and a variable commodity price. These agreements are settled in cash at expiration or exchanged for physical delivery contracts. In the event of nonperformance, we would be exposed again to price risk. We have additional risk of financial loss because the price received for the product at the actual physical delivery point may differ from the prevailing price at the delivery point required for settlement of the hedging transaction. Moreover, our derivatives arrangements generally do not apply to all of our production and thus provide only partial price protection against declines in commodity prices. We expect that the amount of our hedges will vary from time to time.

Our natural gas derivative transactions are generally settled based upon the average of the reporting settlement prices on the HSC or WAHA indices for the last three trading days of a particular contract month. Our oil derivative transactions are generally settled based on the average reporting settlement prices on the West Texas Intermediate index for each trading day of a particular calendar month. For the first quarter of 2009, a 10% change in the price per Mcf of natural gas sold would have changed revenue by $2.9 million, and a 10% change in the price per barrel of oil would have changed revenue by $0.2 million.

Forward Looking Statements

The statements contained in all parts of this document, including, but not limited to, those relating to our schedule, targets, estimates or results of future drilling, including the number, timing and results of wells, budgeted wells, increases in wells, the timing and risk

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involved in drilling follow-up wells, expected working or net revenue interests, planned expenditures, prospects budgeted and other future capital expenditures, efforts to control capital costs, risk profile of oil and natural gas exploration, acquisition of 3-D seismic data (including number, timing and size of projects), planned evaluation of prospects, probability of prospects having oil and natural gas, expected production or reserves, increases in reserves, acreage, working capital requirements, hedging activities, credit risk of hedging counterparties, the ability of expected sources of liquidity to implement the Company’s business strategy, future exploration activity, production rates, 2009 drilling program, growth in production, development of new drilling programs, hedging of production and exploration and development expenditures, Camp Hill development, addition of new lenders under the Senior Credit Facility, fair value of the Company’s investment in Pinnacle Gas Resources, Inc, (“Pinnacle”) and all and any other statements regarding future operations, financial results, business plans and cash needs, potential borrowing base increases and other statements that are not historical facts are forward looking statements. When used in this document, the words “anticipate,” “estimate,” “expect,” “may,” “project,” “believe” and similar expressions are intended to be among the statements that identify forward looking statements. Such statements involve risks and uncertainties, including, but not limited to, those relating to the Company's dependence on its exploratory drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, the Company’s dependence on its key personnel, factors that affect the Company's ability to manage its growth and achieve its business strategy, technological changes, significant capital requirements of the Company, borrowing base determinations and availability under the Senior Credit Facility, evaluations of the Company by potential lenders u under the Senior Credit Facility, results of operation of Pinnacle, the potential impact of government regulations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, availability of equipment, weather, availability of financing, actions by lenders, ability to obtain permits, the results of audits and assessments, and other factors detailed in the “Risk Factors” and other sections of the Company’s Annual Report on Form 10-K for the year ended December 31, 2008 and in this and its other filings with the Securities and Exchange Commission. Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual outcomes may vary materially from those indicated. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by reference to these risks and uncertainties. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement and the Company undertakes no obligation to update or revise any forward-looking statement.

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ITEM 3 - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

For information regarding our exposure to certain market risks, see “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2008. There have been no material changes to the disclosure regarding our exposure to certain market risks made in the Annual Report on Form 10-K. For additional information regarding our long-term debt, see Note 3 of the Notes to Consolidated Financial Statements (Unaudited) in Item 1 of Part I of this Quarterly Report on Form 10-Q.

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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 March 31, 2009 to provide reasonable assurance that the information required to be disclosed by the Company in reports it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the quarter ended March 31, 2009, that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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 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, 2008, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

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

In February 2009, the Company issued 9,500 shares of common stock to a corporation as payment for the settlement of leasehold costs valued at $138,035. In issuing the shares of common stock, the Company relied on the exemption from registration provide by Section 4 (2) of the Securities Act of 1933, as amended, for transactions not involving public offering.

Item 3 - Defaults Upon Senior Securities

None.

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

At the Annual Meeting of Carrizo Oil & Gas, Inc. held on April 30, 2009, there were represented by person or by proxy 29,195,924 shares out of 30,888,890 entitled to vote as of the record date, constituting a quorum.

The matters submitted to a vote of shareholders were:

(a) the reelection of Mr. S.P. Johnson, IV; Mr. Steven A. Webster; Mr. Thomas L. Carter, Jr.; Mr. Paul B. Loyd, Jr.; Mr. F. Gardner Parker; Mr. Roger A. Ramsey and Mr. Frank A. Wojtek as directors; and

(b) the approval of the Amended and Restated Incentive Plan.

With respect to the election of directors, the following number of votes were cast for the nominees: 28,230,764 for Mr. Johnson and 965,160 withheld; 23,439,154 for Mr. Webster and 5,756,770 withheld; 26,888,792 for Mr. Carter and 2,307,132 withheld; 24,982,983 for Mr. Loyd and 4,212,941 withheld; 23,793,222 for Mr. Parker and 5,402,702 withheld; 28,247,596 for Mr. Ramsey and 948,328 withheld; and 28,207,311 for Mr. Wojtek and 988,613 withheld. There were no abstentions in the election of directors.

With respect to the approval of the Amended and Restated Incentive Plan, there were 19,326,986 votes cast for the proposal, 4,645,381 votes cast against the proposal, 14,643 abstentions and 2,351,800 broker non-votes.

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	—	Eighth Amendment dated as of April 22, 2009 to Credit Agreement dated May 25, 2006 by and among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, the Lenders party thereto, and Guaranty Bank, as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on April 28, 2009).

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†10.2	—	Ninth Amendment dated as of April 30, 2009 to Credit Agreement dated May 25, 2006 by and among Carrizo Oil & Gas, Inc., as Borrower, Certain Subsidiaries of Borrower, as Guarantors, the Lenders party thereto, and Guaranty Bank, as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on May 6, 2009).
†10.3	—	Amended and Restated Incentive Plan of Carrizo Oil & Gas, Inc. (incorporated herein by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on May 6, 2009).
31.1	—	CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	—	CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	—	CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	—	CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

†	Incorporated herein by reference as indicated.

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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: May 11, 2009	By: /s/S. P. Johnson, IV
	President and Chief Executive Officer
	(Principal Executive Officer)



Date: May 11, 2009	By: /s/Paul F. Boling
	Chief Financial Officer
	(Principal Financial and Accounting Officer)

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