Carrizo Oil & Gas (CRZO) 10-Q 2008 Q1 Quarterly report

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

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

For the quarterly period ended March 31, 2008

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

For the transition period from ________ to _________

Commission File Number 000-29187-87

CARRIZO OIL & GAS, INC.

(Exact name of registrant as specified in its charter)

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

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

(713) 328-1000

(Registrant's telephone number)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

YES [X]          NO [ ]

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

Large accelerated filer [X]    Accelerated filer []

Non-accelerated filer [ ]    Smaller reporting company [ ]

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, 2008, the latest practicable date, was 30,628,724.

 CARRIZO OIL & GAS, INC.

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2008

INDEX

PART I.  FINANCIAL INFORMATION			PAGE
	Item 1.	Consolidated Balance Sheets
		As of March 31, 2008 (Unaudited) and December 31, 2007	2
		Consolidated Statements of Operations (Unaudited)
		For the three-month periods ended March 31, 2008 and 2007	3
		Consolidated Statements of Cash Flows (Unaudited)
		For the three-month periods ended March 31, 2008 and 2007	4
		Notes to Consolidated Financial Statements (Unaudited)	5
	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	13
	Item 3.	Quantitative and Qualitative Disclosure About Market Risk	20
	Item 4.	Controls and Procedures	21
PART II.  OTHER INFORMATION
	Items 1-6.		22
SIGNATURES			23

CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
ASSETS	2008			2007
	(Unaudited)
	(In thousands, except share amount)
CURRENT ASSETS:
Cash and cash equivalents	$	24,769		$	8,026
Accounts receivable, trade (net of allowance for doubtful accounts of $1,359 and $1,430
at March 31, 2008 and December 31, 2007, respectively)		32,601			26,411
Advances to operators		1,167			1,113
Fair value of derivative financial instruments		-			1,829
Prepayments and deposits		1,659			3,913
Deferred income taxes		8,246			324
Total current assets		68,442			41,616
PROPERTY AND EQUIPMENT, net full-cost method of accounting for oil
and natural gas properties (including unevaluated costs of properties of $170,216 and
$124,373 at March 31, 2008 and December 31, 2007, respectively)		750,240			646,810
DEFERRED FINANCING COSTS, NET		5,351			5,921
INVESTMENT IN PINNACLE GAS RESOURCES, INC.		6,173			11,071
OTHER ASSETS		3,181			3,245
TOTAL ASSETS	$	833,387		$	708,663
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable, trade		46,363		$	49,700
Accrued liabilities		39,409			36,091
Advances for joint operations		651			872
Current maturities of long-term debt		2,250			2,251
Fair value of derivative financial instruments		23,561			2,755
Total current liabilities		112,234			91,669
LONG-TERM DEBT, NET OF CURRENT MATURITIES		217,688			252,250
ASSET RETIREMENT OBLIGATION		6,478			5,869
FAIR VALUE OF DERIVATIVE FINANCIAL INSTRUMENTS		7,483			1,050
DEFERRED INCOME TAXES		49,781			46,321
DEFERRED CREDITS		762			783
COMMITMENTS AND CONTINGENCIES		-			-
SHAREHOLDERS' EQUITY:
Common stock, par value $0.01 (40,000 shares authorized; 30,620 and
28,009 issued and outstanding at March 31, 2008 and
December 31, 2007, respectively)		306			280
Additional paid-in capital		381,922			246,099
Retained earnings		60,048			65,344
Accumulated other comprehensive income, net of tax		2,229			5,425
Unearned compensation - restricted stock		(5,544	)		(6,427	)
Total shareholders' equity		438,961			310,721
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	833,387		$	708,663

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three
	Months Ended
	March 31,
	2008			2007
	(In thousands except
	per share amounts)
OIL AND NATURAL GAS REVENUES	$	53,560		$	22,612
COSTS AND EXPENSES:
Oil and natural gas operating expenses (exclusive of depreciation, depletion
and amortization shown separately below)		8,391			4,703
Depreciation, depletion and amortization		14,087			8,038
General and administrative (inclusive of stock-based compensation expense of
$1,480 and $979 for the three months ended March 31, 2008 and 2007,
respectively)		6,519			4,878
Accretion expense related to asset retirement obligations		58			88
TOTAL COSTS AND EXPENSES		29,055			17,707
OPERATING INCOME		24,505			4,905
OTHER INCOME AND EXPENSES:
Net loss on derivatives (Note 7)		(29,816	)		(5,711	)
Other income and expenses, net		69			116
Interest income		148			344
Interest expense		(6,455	)		(6,154	)
Capitalized interest		3,718			2,686
LOSS BEFORE INCOME TAXES		(7,831	)		(3,814	)
INCOME TAX BENEFIT (Note 4)		2,535			1,269
NET LOSS	$	(5,296	)	$	(2,545	)
BASIC LOSS PER SHARE	$	(0.18	)	$	(0.10	)
DILUTED LOSS PER SHARE	$	(0.18	)	$	(0.10	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC		28,799			25,658
DILUTED		28,799			25,658

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

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Three
	Months Ended
	March 31,
	2008			2007
	(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(5,296	)	$	(2,545	)
Adjustment to reconcile net loss to net
cash provided by operating activities-
Depreciation, depletion and amortization		14,087			8,038
Fair value loss of derivative financial instruments		29,069			8,062
Accretion of discounts on asset retirement obligations		58			88
Stock-based compensation		1,480			979
Deferred income taxes		(2,740	)		(1,370	)
Other		145			12
Changes in operating assets and liabilities
Accounts receivable		(6,121	)		3,384
Other assets		922			430
Accounts payable		7,258			1,539
Accrued liabilities		2,335			553
Net cash provided by operating activities		41,197			19,170
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures		(115,571	)		(47,815	)
Change in capital expenditure accrual		(9,289	)		1,709
Proceeds from the sale of properties		5			1,363
Advances to operators		(55	)		747
Advances for joint operations		(220	)		(80	)
Other		(5	)		(74	)
Net cash used in investing activities		(125,135	)		(44,150	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Net proceeds from debt issuance and borrowings		51,000			75,000
Debt repayments		(85,563	)		(41,564	)
Proceeds from common stock offering, net of offering costs		135,233			-
Proceeds from stock options exercised		76			65
Deferred loan costs and other		(65	)		(2,867	)
Net cash provided by financing activities		100,681			30,634
NET INCREASE IN CASH AND CASH EQUIVALENTS		16,743			5,654
CASH AND CASH EQUIVALENTS, beginning of period		8,026			5,408
CASH AND CASH EQUIVALENTS, end of period	$	24,769		$	11,062
CASH PAID FOR INTEREST (NET OF AMOUNTS CAPITALIZED)	$	2,466		$	3,251

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

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CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The consolidated financial statements are presented in accordance with U.S. generally accepted accounting principles.  The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances.  The financial statements reflect necessary adjustments, all of which were of a recurring nature and are in the opinion of management necessary for a fair presentation.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”).  The Company believes that the disclosures presented are adequate to allow the information presented not to be misleading.  The financial statements included herein should be read in conjunction with the audited financial statements and notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2007 (the “2007 Form 10-K”).

Investment in Unconsolidated Subsidiary

The Company accounts for its investment in Pinnacle Gas Resources, Inc. (“Pinnacle”) using the cost method of accounting and adjusts the carrying amount of its investment for contributions to and distributions from the subsidiary.

Pinnacle became a publicly traded entity on the Nasdaq Global Market in May 2007.  For accounting purposes, the Pinnacle common stock now has a readily determinable fair market value.  The Company classifies this investment as available-for-sale and adjusts the book value to fair market value through Other Comprehensive Income, net of taxes.

Reclassifications

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

Use of Estimates

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

Significant estimates include volumes of oil and natural gas reserves used in calculating depletion of proved oil and natural gas properties, future net revenues and abandonment obligations, impairment of undeveloped properties, future income taxes and related assets/liabilities, the collectibility 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 effected 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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Oil and Natural Gas Properties

Investments in oil and natural gas properties are accounted for using the full-cost method of accounting.  All costs directly associated with the acquisition, exploration and development of oil and natural gas properties are capitalized.  Such costs include lease acquisitions, seismic surveys, and drilling and completion equipment.  The Company proportionally consolidates its interests in oil and natural gas properties.  The Company capitalized compensation costs for employees working directly on exploration activities of $2.1 million and $1.4 million for the three months ended March 31, 2008 and 2007, respectively.  Maintenance and repairs are expensed as incurred.

Depreciation, depletion and amortization (“DD&A”) of proved oil and natural gas properties is based on the unit-of-production method using estimates of proved reserve quantities.  Investments in unproved properties are not subject to DD&A until proved reserves associated with the projects can be determined or until they are impaired.  Unevaluated properties are evaluated periodically for impairment on a property-by-property basis.  If the results of an assessment indicate that the properties have been impaired, the amount of such impairment is determined and added to the proved oil and natural gas property costs subject to DD&A.  The depletable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values.  The depletion rate per Mcfe for the quarters ended March 31, 2008 and 2007 was $2.19 and $2.47, respectively.

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

Net capitalized costs are limited to a “ceiling-test” based on the estimated future net revenues, discounted at 10% per annum, from proved oil and natural gas reserves, based on current economic and operating conditions (“Full Cost Ceiling”).  If net capitalized costs exceed this limit, the excess is charged to earnings.  For the three-month periods ended March 31, 2008 and 2007, the Company did not have any charges associated with its ceiling test.

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

Supplemental Cash Flow Information

The adjustment of the investment in Pinnacle of $3.2 million, net of tax is excluded from the Statement of Cash Flows for the three months ended March 31, 2008.  The Company paid no income taxes during the three months ended March 31, 2008 and 2007.

Stock-Based Compensation

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

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

	2008		2007
	(In millions)
Stock Option Expense	$	0.1	$	0.1
Restricted Stock Expense		1.4		0.9
Total Stock-Based Compensation Expense	$	1.5	$	1.0

Derivative Instruments

The Company uses derivatives to manage price risk underlying its oil and natural gas production.  The Company also uses derivatives to manage the variable interest rate on its Second Lien Credit Facility.

-6-

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 presented herein were treated as non-designated derivatives and the unrealized gain/(loss) related to the mark-to-market valuation was included in the Company’s earnings.

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

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 quarterly.

Major Customers

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

	For the Three Months
	Ended March 31,
	2008			2007
Cimarex Energy Co.		-			14	%
Houston Pipeline Co.		13	%		20	%
Crosstex Energy Services, Ltd.		13	%		-
DTE Energy Trading, Inc.		34	%		-

Loss Per Share

Supplemental loss per share information is provided below:

	Three Months
	Ended March 31,
	2008			2007
	(In thousands, except
	per share amounts)
Net loss	$	(5,296	)	$	(2,545	)
Average common shares outstanding
Weighted average common shares outstanding		28,799			25,658
Stock options		-			-
Diluted weighted average common shares outstanding		28,799			25,658
Loss per common share
Basic	$	(0.18	)	$	(0.10	)
Diluted	$	(0.18	)	$	(0.10	)

Basic loss per common share is based on the weighted average number of shares of common stock outstanding during the periods.  Diluted loss 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 had outstanding 453,962 stock options and 353,094 shares of restricted stock that were excluded in the calculation of dilutive shares for the three-month period ended March 31, 2008 due to the net loss reported for the quarter.  The Company had outstanding 885,069 stock options and 329,412 shares of restricted stock that were excluded in the calculation of dilutive shares for the three-month period ended March 31, 2007 due to the net loss for the quarter.

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2.  LONG-TERM DEBT

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

	March 31,			December 31,
	2008			2007
	(In thousands)
Second Lien Credit Facility	$	219,938		$	220,500
Senior Secured Revolving Credit Facility		-			34,000
Other		-			1
		219,938			254,501
Current maturities		(2,250	)		(2,251	)
	$	217,688		$	252,250

Second Lien Credit Facility

On July 21, 2005, the Company entered into a Second Lien Credit Agreement with Credit Suisse, as administrative agent and collateral agent and the lenders party thereto (the “Second Lien Credit Facility”) that matures on July 21, 2010.  The Second Lien Credit Facility, as amended, provides for a term loan facility in an aggregate principal amount of $225.0 million.  It is secured by substantially all of the Company’s assets and is guaranteed by the Company’s subsidiaries.  The liens securing the Second Lien Credit Facility are second in priority to the liens securing the Senior Secured Revolving Credit Facility (discussed below).

The interest rate on each base rate loan will be the greater of the agent’s prime rate and the federal funds effective rate plus 0.5%, plus a margin of 3.75%.  The interest rate on each Eurodollar loan will be the adjusted LIBOR rate plus a margin of 4.75%.  Interest on Eurodollar loans is payable on either the last day of each period or every three months, whichever is earlier.  Interest on the Company’s outstanding borrowings under the Second Lien Credit Facility is currently payable quarterly on the last day of each quarter.  On March 31, 2008, the interest rate was approximately 7.4%, excluding the effect of interest rate swaps.

Under this agreement, the Company is subject to certain covenants and restrictions on additional financing and other matters.  See the 2007 Form 10-K for further discussion.

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, that matures May 25, 2010.  The Senior Credit Facility provides for a revolving credit facility up to the lesser of the borrowing base and $200.0 million.    It is secured by substantially all of the Company’s assets and is guaranteed by the Company’s subsidiaries.  The liens securing the Senior Credit Facility are first in priority to the liens securing the Second Lien Credit Facility.

The borrowing base will be determined by the lenders at least semi-annually on each May 1 and November 1.  The Company may request one unscheduled borrowing base determination subsequent to each scheduled determination and the lenders may request unscheduled determinations at any time.  At March 31, 2008, the conforming and non-conforming base was $125.0 million and $20.0 million, respectively, as determined in December 2007.

As of March 31, 2008, the Company had no borrowings outstanding under the Senior Credit Facility.

The annual interest rate on each base rate borrowing will be (1) 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 (2) a margin between 0.25% and 1.75% (depending on the current level of borrowing base usage).  The interest rate on each Eurodollar loan will be the adjusted LIBOR Rate plus a margin between 1.5% to 3.0% (depending on the current level of borrowing base usage).

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

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3.  INVESTMENT IN 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”).  At March 31, 2008, the Company owned less than ten percent of Pinnacle’s outstanding equity and accounted for its investment in Pinnacle using the cost method.

During the second quarter of 2007, Pinnacle became a publicly traded entity on the Nasdaq Global Market.  For accounting purposes, the Pinnacle stock now has a readily determinable fair value.  As a result, the Company classifies the Pinnacle investment as available-for-sale and adjusts the investment to fair value through Other Comprehensive Income.  For the three months ended March 31, 2008, Carrizo decreased the book value of its Pinnacle investment by $4.9 million, $3.2 million net of tax, and reported the fair value of the stock at $6.2 million (based on the closing price of Pinnacle’s common stock on March 31, 2008).

In June 2007, the Company sold 41,894 shares of Pinnacle stock for net proceeds of $0.4 million and recognized a $0.3 million gain, which is included in Other income and expenses, net on the Consolidated Statements of Operations.  As of March 31, 2008, the Company owned 2,420,723 shares of Pinnacle common stock.

On October 15, 2007, Pinnacle, Quest Resource Corporation (“Quest”), and Quest Merger Sub, Inc., a wholly owned subsidiary of Quest (“Merger Sub”), entered into an agreement and plan of merger whereby Merger Sub will merge with and into Pinnacle. The merger agreement provides for Quest’s acquisition of all of the issued and outstanding shares of Pinnacle’s common stock for aggregate consideration of approximately 15.5 million shares of Quest’s common stock, or approximately $100 million based on the closing price of Quest’s common stock on March 31, 2008.  Upon completion of the merger, each share of Pinnacle’s common stock will be converted into the right to receive 0.5278 shares of Quest’s common stock.  Completion of the merger transaction is conditioned upon, among other things, adoption of the merger agreement by both Pinnacle’s and Quest’s stockholders.

4.  INCOME TAXES

The Company provided deferred federal income taxes at the rate of 35% (which also approximates its statutory rate) that amounted to a tax benefit of $2.7 million and $1.3 million for the three-month periods ended March 31, 2008 and 2007, respectively.

On January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”).  FIN 48 prescribes a measurement process for recording in the financial statements uncertain tax positions taken or expected to be taken in a tax return.  Additionally, FIN 48 provides guidance regarding uncertain tax positions relating to derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.  The Company classifies interest and penalties associated with income taxes as interest expense.  At March 31, 2008, the Company had no material uncertain tax positions and the tax years 2003 through 2007 remained open to review by federal and various state tax jurisdictions.

5.  COMMITMENTS AND CONTINGENCIES

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

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

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6.  SHAREHOLDERS’ EQUITY

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

	2008			2007
	(In thousands)
Shares outstanding at January 1		28,009			25,981
Equity offering		2,588			-
Restricted stock issued, net of forfeitures		9			5
Employee stock options exercised		15			6
Common stock repurchased and retired for tax withholding obligation		(1	)		(1	)
Shares outstanding at March 31		30,620			25,991

In February 2008, the Company completed an underwritten public offering of 2,587,500 shares of its common stock under an effective shelf registration statement 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 $135.2 million, net of expenses, and plans to use the proceeds to fund, in part, its capital expenditure program for 2008, including its Barnett Shale drilling and land acquisition programs, and for other corporate purposes.  Pending those uses, the Company used a portion of the net proceeds to repay $85.0 million outstanding under the Senior Credit Facility.

7.  DERIVATIVE INSTRUMENTS

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

The Company accounts for its oil and natural gas derivatives and interest rate swap agreements as non-designated hedges.  These derivatives are marked-to-market at each balance sheet date and the unrealized gains (losses) along with the realized gains (losses) associated with the cash settlements of derivative instruments are reported as gain (loss) on derivatives, net in Other Income and Expenses in the Consolidated Statements of Operations.  For the three month periods ended March 31, 2008 and 2007, the Company recorded the following related to its derivatives:

	Three Months
	Ended March 31,
	2008			2007
	(In millions)
Realized gains (losses):
Natural gas and oil derivatives	$	(0.5	)	$	2.3
Interest rate swaps		(0.2	)		0.1
		(0.7	)		2.4
Unrealized losses:
Natural gas and oil derivatives	$	(26.9	)	$	(8.0	)
Interest rate swaps		(2.2	)		(0.1	)
		(29.1	)		(8.1	)
Loss on derivatives, net	$	(29.8	)	$	(5.7	)

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At March 31, 2008, the Company had the following outstanding derivative positions:

	Natural Gas				Natural Gas
	Swaps				Collars
			Average				Average		Average
Quarter	MMbtu		Fixed Price(1)		MMBtu		Floor Price(1)		Ceiling Price(1)
Second Quarter 2008		273,000	$	7.94		3,185,000	$	7.14	$	8.83
Third Quarter 2008		276,000		7.94		3,036,000		7.13		8.82
Fourth Quarter 2008		276,000		7.94		3,036,000		7.13		8.82
First Quarter 2009		-		-		2,520,000		7.37		9.10
Second Quarter 2009		-		-		2,548,000		7.12		8.85
Third Quarter 2009		-		-		2,576,000		7.16		8.88
Fourth Quarter 2009		-		-		2,576,000		7.17		8.90
First Quarter 2010		-		-		1,170,000		7.55		9.27
Second Quarter 2010		-		-		1,183,000		7.07		8.79
Third Quarter 2010		-		-		1,196,000		7.19		8.90
Fourth Quarter 2010		-		-		1,196,000		7.25		8.96

	Oil Collars
			Average		Average
Quarter	Bbls		Floor Price(2)		Ceiling Price (2)
Second Quarter 2008		9,100	$	70.00	$	76.75
Third Quarter 2008		9,200		70.00		76.75
Fourth Quarter 2008		9,200		70.00		76.75

__________

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

(2)   Based on West Texas intermediate index prices.

During the first and second quarter of 2007, the Company entered into interest swap agreements covering amounts outstanding under the Second Lien Credit Facility.  These arrangements are designed to manage the Company’s exposure to interest rate fluctuations through December 31, 2008 by effectively exchanging existing obligations to pay interest based on floating rates with obligations to pay interest based on fixed LIBOR.  The Company’s outstanding positions under interest rate swap agreements at March 31, 2008 were as follows (dollars in thousands):

	Notional		Fixed
Quarter	Amount		LIBOR Rate
Second Quarter 2008		219,938		5.32	%
Third Quarter 2008		219,375		5.31	%
Fourth Quarter 2008		218,813		5.31	%

The fair value of the outstanding derivatives at March 31, 2008 and December 31, 2007 was a liability of $31.1 million and $2.0 million, respectively.

8.  FAIR VALUE MEASUREMENTS

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

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

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

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

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

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

The following table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis as of March 31, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

	Level 1		Level 2			Level 3		Total
	(in thousands)
Assets:
Investment in Pinnacle Gas Resources, Inc.	$	6,173	$	-		$	-	$	6,173
Liabilities:
Oil and natural gas derivatives		-		(26,125	)		-	$	(26,125	)
Interest rate swaps		-		(4,919	)		-	$	(4,919	)
Total	$	6,173	$	(31,044	)	$	-	$	(24,871	)

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.  Interest rate swaps are valued by a third-party consultant using modling techniques that include market inputs such as interest rate yield curves.

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

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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, 2007 and the unaudited financial statements included elsewhere herein.

General Overview

Our first quarter 2008 included record revenues of $53.6 million and record production of 6.3 Bcfe.  The key drivers to our success for the three months ended March 31, 2008 included the following:

Drilling program.  Our success is largely dependent on the results of our drilling program.  During the three months ended March 31, 2008, we drilled 19 gross wells (14.0 net wells) with an apparent success rate of 100% that was comprised of: (1) 15 gross wells (11.2 net wells) in the Barnett Shale area and (2) four gross wells (2.8 net wells) in the onshore Gulf Coast area.  We also drilled three gross service wells (3.0 net wells) in the Camp Hill area and one gross appraisal well (0.2 net wells) in the North Sea.

Production.  Our first quarter production of 6.3 Bcfe, or 69.6 MMcfe/d was a record high.  The first quarter 2008 production increased 12% from the fourth quarter 2007 production of 5.6 Bcfe and nearly doubled from the first quarter 2007 production of 3.2 Bcfe.  The increase between first quarter 2008 and fourth quarter 2007 was due primarily to production from eight new wells brought on line in the Barnett Shale during the first quarter 2008.  The increase in the first quarter 2008 production compared to the first quarter of 2007 was primarily attributable to 36 new company-operated wells in the Barnett Shale that have commenced production since the first quarter of 2007 and additional production from two new wells in the Gulf Coast area, which began production in late first quarter 2007 and in the mid-second quarter 2007, respectively.  These increases were partially offset by the natural decline of other properties.

Commodity prices.  Natural gas prices during the first quarter of 2008 were $8.06 per Mcf (excluding the impact of our hedges), $1.30 per Mcf, or 19% higher than the price in the first quarter of 2007.

Capital funding.  In order to fund our growth, we have taken steps to enhance our liquidity.  In February 2008, we received approximately $135.2 million in net proceeds from an underwritten public offering of 2.59 million shares of our common stock.  The net proceeds were used in part to pay down the outstanding debt of $85.0 million under the Senior Credit Facility.  As a result, we had borrowing capacity of $145.0 million under the Senior Credit Facility at March 31, 2008.

Outlook

Our outlook for the future remains positive.  Production growth and strong commodity prices are key to our future success and to continue our success:

·   In the last three quarters of 2008 we plan to drill 53 gross wells (50.9 net) in the Barnett Shale area, eleven gross wells (3.1 net) in the Gulf Coast area, 37 gross wells (37.0 net) in our Camp Hill field (which includes approximately 14 service wells), one gross (0.2 net) U.K. North Sea appraisal wells and 29 gross wells (14.5 net) in other areas.  The actual number of wells drilled will vary depending upon various factors, including the availability and cost of drilling rigs, land and industry partner issues, our cash flow, success of drilling programs, weather delays and other factors.  If we drill the number of wells we have budgeted for 2008, depreciation, depletion and amortization, oil and natural gas operating expenses and production are expected to increase over levels incurred in 2007.  Our ability to drill this number of wells is heavily dependent upon the timely access to oilfield services, particularly drilling rigs.

·   We plan to continue the development of the Barnett Shale.  We currently have 25 gross (21.8 net) wells awaiting completion or pipeline connections.  We expect to bring these wells online in the second and third quarter of 2008.

·   We plan to continue the development of other new drilling programs in the Floyd Shale in Mississippi, the Fayetteville Shale in Arkansas, the Marcellus Shale in New York and Pennsylvania and the North Sea.

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·   We expect to continue to hedge production to decrease our exposure to reductions in natural gas and oil prices.  At March 31, 2008, we had hedged approximately 25,047,000 MMBtus of natural gas production through 2010 and 27,500 Bbls of oil production through 2008.

Results of Operations

Three Months Ended March 31, 2008,

Compared to the Three Months Ended March 31, 2007

Oil and natural gas revenues for the three months ended March 31, 2008 increased 137% to $53.6 million from $22.6 million for the same period in 2007.  Production volumes for natural gas for the three months ended March 31, 2008 increased 111% to 6.0 Bcf from 2.8 Bcf for the same period in 2007.  Average natural gas prices, excluding the impact of the loss from our cash settled derivatives of $0.1 million and gain of $2.3 million for the quarters ended March 31, 2008 and 2007, respectively, increased to $8.06 per Mcf in the first quarter of 2008 from $6.76 per Mcf in the same period in 2007.  Average oil prices for the quarter ended March 31, 2008 increased 71% to $96.10 from $56.23 per barrel in the same period in 2007.  The increase in natural gas production volume was due primarily to new production from 36 company-operated wells in the Barnett Shale that commenced production since the first quarter of 2007 and additional production from two new wells in the Gulf Coast area which were brought online in late first quarter 2007 and second quarter 2007, respectively.  These increases were partially offset by the natural decline of the properties.

The following table summarizes production volumes, average sales prices and operating revenues (excluding the impact of derivatives) for the three months ended March 31, 2008 and 2007:

	For the Three				2008 Period
	Months Ended				Compared to 2007 Period
	March 31,				Increase			% Increase
	2008		2007		(Decrease)			(Decrease)
Production volumes
Oil and condensate (MBbls)		53		60		(7	)		(12	)%
Natural gas (MMcf)		6,014		2,845		3,169			111	%
Average sales prices
Oil and condensate (per Bbl)	$	96.10	$	56.23	$	39.87			71	%
Natural gas (per Mcf)		8.06		6.76		1.30			19	%
Operating revenues (In thousands)
Oil and condensate	$	5,095	$	3,383	$	1,712			51	%
Natural gas		48,465		19,229		29,236			152	%
Total Operating Revenues	$	53,560	$	22,612	$	30,948			137	%

Oil and natural gas operating expenses for the three months ended March 31, 2008 increased 78% to $8.4 million from $4.7 million for the same period in 2007 primarily as a result of (1) higher lifting costs of $1.5 million primarily attributable to increased production and the increased number of producing wells, (2) increased transportation and other product costs of $1.5 million mainly attributable to the Barnett Shale area and (3) increased severance tax expense of $0.5 million associated with increased production.

Depreciation, depletion and amortization (DD&A) expense for the three months ended March 31, 2008 increased 77% to $14.1 million ($2.22 per Mcfe) from $8.0 million ($2.51 per Mcfe) for the same period in 2007.  This increase was primarily due to an increase in production volumes partially offset by a decrease in the DD&A rate attributable to lower overall finding costs of new reserves.

General and administrative expense for the three months ended March 31, 2008 increased by $1.6 million to $6.5 million from $4.9 million for the corresponding period in 2007 primarily as a result of (1) an increase of $0.7 million for compensation and other employee-related expenses, (2) increased stock-based compensation of $0.5 million due to increased issuance of stock awards and higher stock prices and (3) increased legal and consulting fees of $0.3 million.

The net loss on derivatives of $29.8 million in the first quarter of 2008 was comprised of (1) $0.7 million of realized loss on net cash settled derivatives and (2) $29.1 million of net unrealized mark-to-market loss on derivatives.  The net loss on derivatives of $5.7

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million in the first quarter of 2007 was comprised of (1) $2.4 million of realized gain on net cash settled derivatives and (2) $8.1 million of net unrealized mark-to-market loss on derivatives.

Interest expense and capitalized interest for the three months ended March 31, 2008 were $6.5 million and ($3.7) million, respectively, as compared to $6.2 million and $(2.7) million for the same period in 2007.

Income tax benefit increased to $2.5 million for the three months ended March 31, 2008 from $1.3 million for the same period in 2007 due to the change in net loss.

Liquidity and Capital Resources

Sources and Uses of Cash.  During the three months ended March 31, 2008, capital expenditures, net of proceeds from property sales, exceeded our net cash provided by operations.  During the first quarter of 2008, we have funded our capital expenditures with cash generated from operations, additional borrowings under our Senior Credit Facility and proceeds from the issuance of our common stock.  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.  On December 20, 2007, the borrowing base availability under the Senior Credit Facility increased from $117.0 million to $145.0 million.  At April 30, 2008, cash available under the Senior Credit Facility was $106.0 million.  The next borrowing base redetermination is scheduled for May 2008 at which time we currently expect our borrowing base to increase by a yet undetermined amount.

·   Other debt and equity offerings.  In February 2008, we received $135.2 million from an underwritten public offering of 2,587,500 shares of our common stock priced at $54.50 per share.  As situations or conditions arise, we may issue debt, equity or other instruments to supplement our cash flows.

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

Our primary use of cash is capital expenditures related to our drilling program.  We have budgeted approximately $250 million on our 2008 drilling program and $50 million from lease and seismic acquisitions.  For the three months ended March 31, 2008, we have incurred approximately $115.6 million in capital expenditures.

Overview of Cash Flow Activities.  Cash flows provided by operating activities were $41.2 million and $19.2 million for the three months ended March 31, 2008 and 2007, respectively.  The increase was primarily due to increased production and higher oil and natural gas commodity prices.

Cash flows used in investing activities were $125.1 and $44.2 million for the three months ended March 31, 2008 and 2007, respectively, and related primarily to oil and gas property expenditures.  During the first quarter of 2008, we invested approximately $115 million in oil and gas properties, including $58 million related to drilling activities and $53 million related to leasehold acquisitions.

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 (see Note 6 of the Notes to Consolidated Financial Statements for further discussion of this transaction).  These cash proceeds were partially offset by the paydown of the Senior Credit Facility.  Net cash provided by financing activities for the three months ended March 31, 2007 was $30.6 million and related primarily to the additional borrowings of $75.0 million under the Second Lien Credit Facility in January 2007, partially offset by $41.6 million of debt repayments.

Liquidity/Cash Flow Outlook.  We currently believe that the proceeds from the February 2008 equity offering, cash generated from operations along with cash on hand and the cash available under the Senior Credit Facility is sufficient to fund our immediate needs but we may need to seek other financing alternatives, including additional debt or equity financings, to fully fund our current 2008 capital expenditures budget, especially if there are additional capital needs in connection with our Marcellus Shale or U.K. North Sea operations or new opportunities in our Other Shale areas.

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

Contractual Obligations

During the first quarter of 2008, we entered into a firm drilling agreement for one rig over a three-year term scheduled to begin in the second quarter of 2008.  The estimated obligation is approximately $25 million per year through 2010.

Effects of Inflation and Changes in Price

Our results of operations and cash flows are affected by changing oil and natural gas prices.  If the price of oil and natural gas increases (decreases), there could be a corresponding increase (decrease) in revenues.  In addition, we are affected by increases in the costs of services and equipment that we employ to explore for and produce oil and natural gas due to high activity and a relative scarcity of equipment.  We generally expect these costs and expenses to continue to increase if oil and natural gas prices remain strong and drilling activity remains high.  In the recent historical past, inflation has had a minimal effect on us.

Recently Adopted Accounting Pronouncements

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

Recently Issued Accounting Pronouncements

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

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 $2.1 million and $1.4 million for the three months ended March 31, 2008 and 2007, respectively.  We expense maintenance and repairs as they are incurred.

We amortize natural gas and oil properties based on the unit-of-production method using estimates of proved reserve quantities.  We do not amortize investments in unproved properties until proved reserves associated with the projects can be determined or until these investments are impaired.  We periodically evaluate, on a property-by-property basis, unevaluated properties for impairment.  If the results of an assessment indicate that the properties are impaired, we add the amount of impairment to the proved natural gas and oil property costs to be amortized.  The amortizable base includes estimated future development costs and, where significant, dismantlement, restoration and abandonment costs, net of estimated salvage values.  The depletion rate per Mcfe for the three months ended March 31, 2008 and 2007 was $2.19 and $2.47, respectively.

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

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

In connection with our March 31, 2008 Full Cost Ceiling test computation, a price sensitivity study also indicated that a 10% increase or decrease in commodity prices at March 31, 2008 would have increased or decreased the Full Cost Ceiling test cushion by approximately $97 million.  The aforementioned price sensitivity is as of March 31, 2008 and, accordingly, does not include any potential changes in reserve values due to subsequent performance or events, such as commodity prices, reserve revisions and drilling results.

The Full Cost Ceiling cushion at the end of March 31, 2008 of approximately $395 million was based upon average realized oil, natural gas liquids and natural gas prices of $97.28 per Bbl, $55.93 per Bbl and $8.15 per Mcf, respectively, or a volume weighted average price of $57.06 per BOE.  This cushion, however, would have been zero on such date at an estimated volume weighted average price of $33.85 per BOE.  A BOE means one barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids, which approximates the relative energy content of oil, condensate and natural gas liquids as compared to natural gas.  Prices have historically been higher or substantially higher, more often for oil than natural gas on an energy equivalent basis, although there have been periods in which they have been lower or substantially lower.

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

We have a significant amount of proved undeveloped reserves.  We had 185.8 Bcfe of proved undeveloped reserves at December 31, 2007, representing 53% of our total proved reserves.  As of December 31, 2007, a portion of these proved undeveloped reserves, or approximately 38.1 Bcfe, are attributable to our Camp Hill properties that we acquired in 1994.  The estimated future development costs to develop our proved undeveloped reserves on our Camp Hill properties are relatively low, on a per Mcfe basis, when compared to the estimated future development costs to develop our proved undeveloped reserves on our other oil and natural gas properties.  Furthermore, the average depletable life (the estimated time that it will take to produce all recoverable reserves) of our Camp Hill properties is considerably longer, or approximately 15 years, when compared to the depletable life of our remaining oil and natural gas properties of approximately 10 years.  Accordingly, the combination of a relatively low ratio of future development costs and a relatively long depletable life on our Camp Hill properties has resulted in a relatively low overall historical depletion rate and DD&A expense.  This has resulted in a capitalized cost basis associated with producing properties being depleted over a longer period than the associated production and revenue stream, causing the build-up of nondepleted capitalized costs associated with properties that have been completely depleted.  This combination of factors, in turn, has had a favorable impact on our earnings, which have been higher than they would have been had the Camp Hill properties not resulted in a relatively low overall depletion rate and DD&A expense and longer depletion period.  As a hypothetical illustration of this impact, the removal of our Camp Hill proved undeveloped reserves starting January 1, 2002 would have reduced our earnings by (1) 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), (2) an estimated $5.9 million in 2003 (due to higher depletion expense), (3) an estimated $3.4 million in 2004 (due to higher depletion expense), (4) an estimated $6.9 million in 2005 (due to higher depletion expense), (5) an estimated $0.7 million in 2006 (due to higher depletion expense) and (6) an estimated $2.0 million in 2007 (due to higher depletion expense).

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

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

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

Volatility of Oil and Natural Gas Prices

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

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

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

The following table includes oil and natural gas positions settled during the three-month periods ended March 31, 2008 and 2007, and the unrealized gain/(loss) associated with the outstanding oil and natural gas derivatives at March 31, 2008 and 2007.

	Three months ended
	March 31,
	2008			2007
Oil positions settled (Bbls)		18,200			-
Natural gas positions settled (MMBtu)		4,132,000			1,887,000
Realized gain/(loss) ($ millions) (1)	$	(0.5	)	$	2.3
Unrealized loss ($ millions) (1)	$	(26.9	)	$	(8.0	)

__________

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

At March 31, 2008, we had the following outstanding natural gas derivative positions:

	Natural Gas				Natural Gas
	Swaps				Collars
			Average					Average		Average
Quarter	MMbtu		Fixed Price(1)		MMBtu			Floor Price(1)		Ceiling Price(1)
Second Quarter 2008		273,000	$	7.94		3,185,000		$	7.14	$	8.83
Third Quarter 2008		276,000		7.94		3,036,000			7.13		8.82
Fourth Quarter 2008		276,000		7.94		3,036,000			7.13		8.82
First Quarter 2009		-		-		2,520,000			7.37		9.10
Second Quarter 2009		-		-		2,548,000	��		7.12		8.85
Third Quarter 2009		-		-		2,576,000			7.16		8.88
Fourth Quarter 2009		-		-		2,576,000			7.17		8.90
First Quarter 2010		-		-		1,170,000			7.55		9.27
Second Quarter 2010		-		-		1,183,000			7.07		8.79
Third Quarter 2010		-		-		1,196,000			7.19		8.90
Fourth Quarter 2010		-		-		1,196,000			7.25		8.96

	Oil Collars
			Average		Average
Quarter	Bbls		Floor Price(2)		Ceiling Price (2)
Second Quarter 2008		9,100	$	70.00	$	76.75
Third Quarter 2008		9,200		70.00		76.75
Fourth Quarter 2008		9,200		70.00		76.75

__________

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

(2)   Based on West Texas intermediate index prices.

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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 Houston Ship Channel and Waha indices for the last three trading days of a particular contract month.  Our oil derivative transactions are generally settled based on the average reporting settlement prices on the West Texas Intermediate index for each trading day of a particular calendar month.  For the first quarter of 2008, a 10% change in the price per Mcf of natural gas sold would have changed revenue by $4.8 million.  A 10% change in the price per barrel of oil would have changed revenue by $0.5 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 involved in drilling follow-up wells, expected working or net revenue interests, planned expenditures, prospects budgeted and other future capital expenditures, risk profile of oil and natural gas exploration, acquisition of 3-D seismic data (including number, timing and size of projects), planned evaluation of prospects, probability of prospects having oil and natural gas, expected production or reserves, increases in reserves, acreage, working capital requirements, hedging activities, the ability of expected sources of liquidity to implement the Company’s business strategy, future exploration activity, production rates, 2008 drilling program, growth in production, development of new drilling programs, hedging of production and exploration and development expenditures, Camp Hill development and all and any other statements regarding future operations, financial results, business plans and cash needs, potential borrowing base increases and other statements that are not historical facts are forward looking statements.  When used in this document, the words “anticipate,” “estimate,” “expect,” “may,” “project,” “believe” and similar expressions are intended to be among the statements that identify forward looking statements.  Such statements involve risks and uncertainties, including, but not limited to, those relating to the Company's dependence on its exploratory drilling activities, the volatility of oil and natural gas prices, the need to replace reserves depleted by production, operating risks of oil and natural gas operations, the Company's dependence on its key personnel, factors that affect the Company's ability to manage its growth and achieve its business strategy, risks relating to limited operating history, technological changes, significant capital requirements of the Company, the potential impact of government regulations, litigation, competition, the uncertainty of reserve information and future net revenue estimates, property acquisition risks, availability of equipment, weather, availability of financing, actions by lenders, ability to obtain permits, the results of audits and assessments, and other factors detailed in the “Risk Factors” and other sections of the Company's Annual Report on Form 10-K for the year ended December 31, 2007 and 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, 2007.  There have been no material changes to the disclosure regarding our exposure to certain market risks made in the Annual Report on Form 10-K.  For additional information regarding our long-term debt, see Note 2 of the Notes to Consolidated Financial Statements (Unaudited) in Item 1 of Part I of this Quarterly Report on Form 10-Q.

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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, 2008 to provide reasonable assurance that the information required to be disclosed by the Company in reports it files under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.  While our disclosure controls and procedures provide reasonable assurance that the appropriate information will be available on a timely basis, this assurance is subject to limitations inherent in any control system, no matter how well it may be designed or administered.

Changes in Internal Controls.  There was no change in our internal control over financial reporting during the quarter ended March 31, 2008, 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, 2007, which could materially affect our business, financial condition or future results.  Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.

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

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

					(c) Total Number of		(d) Maximum Number
					Shares Purchased as		(or Appropriate Dollar
	(a) Total Number				Part of Publicly		Value) of Shares that May
	of Shares		(b) Average Price		Announced Plans or		Yet Be Purchased Under
Period	Purchased(1)		Paid Per Share		Programs		the Plan or Programs
January 2008		285	$	46.61		-		-
February 2008		459		48.83		-		-
March 2008		354		59.85		-		-
Total		1,098	$	51.81		-		-

__________

(1)  The 1,098 shares related to the surrender of shares of common stock to satisfy tax withholding obligations in connection with the vesting of restricted stock issued to employees under our long-term incentive plan.

Item 3 - Defaults Upon Senior Securities

None.

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

None.

Item 5 - Other Information

None.

Item 6 - Exhibits

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

Exhibit Number		Description
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 8, 2008	By:  /s/S. P. Johnson, IV
	President and Chief Executive Officer
	(Principal Executive Officer)
Date:   May 8, 2008	By:  /s/Paul F. Boling
	Chief Financial Officer
	(Principal Financial and Accounting Officer)

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