Exhibit 99.1

 

Item 8.

FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

CARRIZO OIL & GAS, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

		PAGE
Reports of Independent Registered Public Accounting Firms			F-2
Consolidated Balance Sheets, December 31, 2010 and 2009			F-4
Consolidated Statements of Operations for the Years Ended December 31, 2010, 2009 and 2008			F-5
Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2010, 2009 and 2008			F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009 and 2008			F-7
Notes to Consolidated Financial Statements			F-8

 

F-1

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders

Carrizo Oil & Gas, Inc.:

We have audited the accompanying consolidated balance sheets of Carrizo Oil & Gas, Inc. and subsidiaries (the Company) as of December 31, 2010 and 2009, and the related consolidated statements of operations, shareholders’ equity, and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perfo.rm the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Carrizo Oil & Gas, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Carrizo Oil & Gas, Inc.’s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 31, 2011, expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

March 31, 2011, except for the 2010 and 2009 condensed consolidating financial information, as presented in Note 16, which is as of April 29, 2011

 

F-2

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of

Carrizo Oil & Gas, Inc.

We have audited the accompanying consolidated statements of operations, shareholders’ equity and cash flows of Carrizo Oil & Gas, Inc. for the year ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated statements of operations, shareholders’ equity and cash flows of Carrizo Oil & Gas, Inc. for the year ended December 31, 2008 are presented fairly in all material respects in conformity with U.S. generally accepted accounting principles.

/s/ Pannell Kerr Forster of Texas, P.C.

Houston, Texas

March 12, 2009

(Except for Notes 4, 5 and 6 for which the

date is August 17, 2009, and Note 16 for

which the date is April 29, 2011)

 

F-3

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CARRIZO OIL & GAS, INC.

CONSOLIDATED BALANCE SHEETS

 

		December 31,
		2010				2009
		(In thousands, except per share amount)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents		$	4,128			$	3,837
Accounts receivable, net
Oil and gas sales			16,027				13,202
Joint interest billing			14,309				4,901
Related party			—				445
Other			560				2,793
Advances to operators			487				540
Fair value of derivative instruments			17,698				8,404
Other current assets			7,123				1,278
Total current assets			60,332				35,400
PROPERTY AND EQUIPMENT, NET
Oil and gas properties using the full cost method of accounting:
Proved oil and gas properties, net			626,665				399,182
Costs not subject to amortization			352,479				330,607
Other property and equipment, net			3,913				3,911
TOTAL PROPERTY AND EQUIPMENT, NET			983,057				733,700
DEFERRED FINANCING COSTS, NET			14,670				9,738
INVESTMENTS			3,392				3,358
FAIR VALUE OF DERIVATIVE INSTRUMENTS			7,257				6,477
DEFERRED INCOME TAXES			72,587				70,217
INVENTORY			1,646				3,292
OTHER ASSETS			1,193				925
TOTAL ASSETS		$	1,144,134			$	863,107
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable, trade		$	33,653			$	19,907
Revenue and royalties payable			23,864				27,390
Current state tax payable			4,052				107
Accrued drilling costs			26,884				17,251
Accrued interest			5,953				1,922
Other accrued liabilities			11,838				11,013
Advances for joint operations			3,407				1,739
Current maturities of long-term debt			160				148
Deferred income taxes			5,286				1,474
Other current liabilities			3,907				1,777
Total current liabilities			119,004				82,728
LONG-TERM DEBT, net of current maturities and debt discount			558,094				520,188
ASSET RETIREMENT OBLIGATIONS			6,369				5,410
FAIR VALUE OF DERIVATIVE INSTRUMENTS			715				2,818
OTHER LIABILITIES			3,316				4,354
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS’ EQUITY:
Common stock, $0.01 par value, 90,000 shares authorized, 38,906 and 31,100 shares issued and outstanding at December 31, 2010 and 2009, respectively)			389				311
Additional paid-in capital			630,845				431,757
Accumulated deficit			(174,598	)			(184,548	)
Accumulated other comprehensive income, net of income taxes			—				89
Total shareholders’ equity			456,636				247,609
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	1,144,134			$	863,107

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

 

F-4

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

 

		For the Years Ended December 31,
		2010				2009				2008
		(In thousands, except per share amounts)
REVENUES:
Oil and gas revenues		$	138,123			$	112,699			$	209,829
Other revenues			1,339				1,380				6,848
TOTAL REVENUES			139,462				114,079				216,677
COSTS AND EXPENSES:
Lease operating			23,662				25,050				28,666
Production tax			3,648				132				5,141
Ad valorem tax			3,707				5,022				4,078
Gas purchases			1,336				1,497				6,570
Depreciation, depletion and amortization			47,030				52,005				58,311
Impairment of oil and gas properties			2,731				338,914				178,470
General and administrative (inclusive of stock-based compensation expense of $16,608, $11,297 and $5,958 for the years ended December 31, 2010, 2009 and 2008, respectively)			35,906				30,136				23,425
Accretion expense related to asset retirement obligations			216				308				154
TOTAL COSTS AND EXPENSES:			118,236				453,064				304,815
OPERATING INCOME (LOSS)			21,226				(338,985	)			(88,138	)
OTHER INCOME AND EXPENSES:
Gain (loss) on derivative instruments, net			47,782				41,465				37,499
Loss on extinguishment of debt			(31,023	)			—				(5,689	)
(Impairment) recovery of investment in Pinnacle Gas Resources, Inc.			165				(2,091	)			—
Interest expense			(43,264	)			(38,286	)			(30,257	)
Capitalized interest			20,746				19,696				20,527
Other income, net			47				49				286
INCOME (LOSS) BEFORE INCOME TAXES			15,679				(318,152	)			(65,772	)
INCOME TAX (EXPENSE) BENEFIT			(5,729	)			113,307				20,725
NET INCOME (LOSS)		$	9,950			$	(204,845	)		$	(45,047	)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAXES:
Increase (decrease) in fair value of investment in Pinnacle Gas Resources, Inc., net of income taxes			17				55				(6,724	)
Reclassification of cumulative (increase) decrease in market value of investment in Pinnacle Gas Resources, Inc., net of income taxes			(106	)			1,333				—
COMPREHENSIVE INCOME (LOSS)		$	9,861			$	(203,457	)		$	(51,771	)
BASIC INCOME (LOSS) PER COMMON SHARE		$	0.29			$	(6.61	)		$	(1.49	)
DILUTED INCOME (LOSS) PER COMMON SHARE		$	0.29			$	(6.61	)		$	(1.49	)
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
BASIC			33,861				31,006				30,326
DILUTED			34,305				31,006				30,326

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

 

F-5

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

 

		Common Stock								Additional Paid-in Capital				Retained Earnings				Accumulated Other Comprehensive Income (Loss)				Shareholders’ Equity
		Shares				Amount
		(In thousands, except share amounts)
BALANCE, January 1, 2008			28,009,152			$	280			$	239,672			$	65,344			$	5,425			$	310,721
Common stock issued, net of offering costs			2,587,500				26				135,049				—				—				135,075
Conversion premium related to Senior Convertible Notes			—				—				40,207				—				—				40,207
Stock options exercised for cash			65,400				1				261				—				—				262
Stock-based compensation			—				—				6,013				—				—				6,013
Restricted stock awards, net of forfeitures			203,306				2				(63	)			—				—				(61	)
Stock repurchased to settle tax withholding obligations			(5,711	)			—				(361	)			—				—				(361	)
Other Comprehensive loss, net of income taxes:
Fair value adjustment to Investment in Pinnacle, net of income tax benefit of $3,621			—				—				—				—				(6,724	)			(6,724	)
Net loss			—				—				—				(45,047	)			—				(45,047	)
Total comprehensive loss			—				—				—				—				—				(51,771	)
BALANCE, December 31, 2008			30,859,647			$	309			$	420,778			$	20,297			$	(1,299	)		$	440,085
Stock options exercised for cash			5,000				—				9				—				—				9
Stock-based compensation			—				—				10,543				—				—				10,543
Restricted stock awards and units, net of forfeitures			226,286				2				304				—				—				306
Other			9,500				—				123				—				—				123
Other Comprehensive loss, net of income taxes:
Fair value adjustment to Investment in Pinnacle, net of income tax expense of $31			—				—				—				—				55				55
Reclassification of cumulative decrease in fair of Investment in Pinnacle, net of income tax benefit of $758			—				—				—				—				1,333				1,333
Net loss			—				—				—				(204,845	)			—				(204,845	)
Total comprehensive loss			—				—				—				—				—				(203,457	)
BALANCE, December 31, 2009			31,100,433			$	311			$	431,757			$	(184,548	)		$	89			$	247,609
Stock options exercised for cash			266,433				3				687				—				—				690
Stock-based compensation											10,290				—				—				10,290
Restricted stock awards and units, net of forfeitures			344,311				3				(1,101	)			—				—				(1,098	)
Common stock issued, net of offering costs			7,195,000				72				188,462				—				—				188,534
Other			—				—				750				—				—				750
Other Comprehensive loss, net of income taxes:
Fair value adjustment to Investment in Pinnacle, net of income tax expense of $9			—				—				—				—				17				17
Reclassification of cumulative increase in fair of Investment in Pinnacle, net of income tax expense of $59			—				—				—				—				(106	)			(106	)
Net income			—				—				—				9,950				—				9,950
Total comprehensive income			—				—				—				—				—				9,861
BALANCE, December 31, 2010			38,906,177			$	389			$	630,845			$	(174,598	)		$	—			$	456,636

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

 

F-6

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CARRIZO OIL & GAS, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

		For the Years Ended December 31,
		2010				2009				2008
		(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	9,950			$	(204,845	)		$	(45,047	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities-
Depreciation, depletion and amortization			47,030				52,005				58,311
Impairment of oil and gas properties			2,731				338,914				178,470
Unrealized (gain) loss on derivative instruments			(14,564	)			33,401				(43,859	)
Allowance for doubtful accounts			485				772				(166	)
Accretion of discount on asset retirement obligations			216				308				154
Loss on extinguishment of debt			31,023				—				4,601
Stock-based compensation			16,608				11,297				5,952
Deferred income taxes			1,493				(113,374	)			(20,920	)
Amortization of discount and deferred financing costs, net of amounts capitalized			7,716				5,898				1,825
Impairment (recovery) of investment in Pinnacle Gas Resources, Inc.			(165	)			2,091				—
Other			3,262				5,865				5,272
Changes in operating assets and liabilities-
Accounts receivable			(10,040	)			(656	)			5,119
Other, net			(2,173	)			(876	)			(3,661	)
Accounts payable			913				558				(1,476	)
Accrued liabilities			(69	)			2,014				4,179
Net cash provided by operating activities			94,416				133,372				148,754
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures			(347,808	)			(182,907	)			(571,291	)
Change in capital expenditure payables and accruals			22,540				(25,685	)			11,808
Proceeds from sales of oil and gas properties			54,217				48,524				3,259
Advances to operators			53				(204	)			776
Advances for joint operations			1,668				(2,076	)			2,943
Other			(966	)			(105	)			(2,840	)
Net cash used in investing activities			(270,296	)			(162,453	)			(555,345	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from common stock offerings, net of offering costs			188,534				—				135,075
Proceeds from stock options exercised			690				9				262
Proceeds from borrowings and issuances			916,308				128,113				778,182
Debt repayments			(917,148	)			(96,461	)			(498,923	)
Payments of debt issuance and retirement costs			(12,213	)			(3,927	)			(10,847	)
Net cash provided by financing activities			176,171				27,734				403,749
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			291				(1,347	)			(2,842	)
CASH AND CASH EQUIVALENTS, beginning of year			3,837				5,184				8,026
CASH AND CASH EQUIVALENTS, end of year		$	4,128			$	3,837			$	5,184
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest, net of amounts capitalized		$	24,218			$	16,347			$	4,160
Cash paid for income taxes		$	95			$	67			$	30

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

 

F-7

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CARRIZO OIL & GAS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. NATURE OF OPERATIONS

Carrizo Oil & Gas, Inc. is an independent energy company which, together with its subsidiaries (collectively referred to herein as the “Company”), is engaged in the exploration, development and production of oil and gas in the United States and the U.K. North Sea. The Company’s current operations are principally focused in proven, producing oil and gas plays in the Barnett Shale in North Texas, the Marcellus Shale in Pennsylvania, New York and West Virginia, the Eagle Ford Shale in South Texas, the Niobrara formation in Colorado and the Huntington Field located in the U.K. North Sea.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and LLCs where the Company, as a partner or member, has undivided interests in the oil and gas properties.

Investments

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

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

Reclassifications

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

Use of Estimates

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

Significant estimates include volumes of proved oil and gas reserves which are used in calculating the amortization of proved oil and gas property costs, the present value of future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and asset retirement obligations. Other significant estimates include the, impairment of unproved properties, fair values of derivative instruments, stock-based compensation, the collectability of outstanding receivables, and contingencies. Proved oil and gas reserve estimates have numerous inherent uncertainties. The accuracy of any reserve estimate is a function of the quality and quantity of available data and the application of engineering and geological interpretation and judgment to available data. Subsequent drilling results, testing and production may justify revisions of such estimates. Accordingly, proved oil and gas reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. In addition, proved oil and gas reserve estimates are vulnerable to changes in market prices of oil and gas. Such prices have been volatile in the past and can be expected to be volatile in the future.

Estimates are based on current assumptions that may be materially affected by changes to future economic conditions such as the market prices of oil and gas, the credit worthiness of counterparties, interest rates and the market value and volatility of the Company’s common stock. Future changes in these assumptions may affect these significant estimates materially in the near term.

 

F-8

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Oil and Gas Properties

Oil and gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized to costs centers established on a country-by-country basis. Internal costs directly identified with acquisition, exploration and development activities are capitalized and totaled $5.3 million, $5.6 million, and $7.8 million for the years ended December 31, 2010, 2009, and 2008, respectively. Costs related to production, general corporate overhead or similar activities are expensed as incurred.

Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting oil and natural gas liquids to gas equivalents at the ratio of one barrel of oil or natural gas liquids to six thousand cubic feet of gas, which represents their approximate relative energy content. The equivalent unit-of-production rate is computed on a quarterly basis by dividing production by proved oil and gas reserves at the beginning of the quarter which is applied to capitalized oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus the estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values. Average DD&A per Mcfe was $1.25, $1.55, and $2.23 for the years ended December 31, 2010, 2009 and 2008, respectively.

Costs not subject to amortization include unevaluated leasehold costs, seismic costs associated with specific unevaluated properties, related capitalized interest and the cost of exploratory wells in progress. Significant costs are assessed individually on a quarterly basis to determine whether or not and to what extent proved reserves have been assigned to the properties or if an impairment has occurred, in which case the related costs are added to the oil and gas property costs subject to amortization. Factors the Company considers in its impairment assessment include drilling results by the Company and other operators, the terms of oil and gas leases not held by production and drilling capital expenditure plans. The Company expects to complete its evaluation of the majority of its unproved properties within the next two to five years. Insignificant costs are grouped by major area and added to the oil and gas property costs subject to amortization based on the average primary lease terms of the properties. The Company capitalized interest costs associated with its unevaluated leasehold and seismic costs of $20.7 million, $19.7 million, and $20.5 million for the years ended December 31, 2010, 2009 and 2008, respectively. Interest is capitalized using a weighted-average interest rate based on outstanding borrowings.

Proceeds from the sale of oil and gas properties are recognized as a reduction of capitalized oil and gas property costs with no gain or loss recognized, unless the sale significantly alters the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company has not had any sales of oil and gas properties that significantly alter that relationship.

In connection with the formation of ACP II Marcellus LLC (“ACP II”), the Company’s partner in one of its joint ventures in the Marcellus Shale, Carrizo (Marcellus) LLC (“Carrizo Marcellus”), a wholly-owned subsidiary of the Company, was issued a class of interests (“B Units”) in ACP II. The B Units entitle the Company to certain percentages of cash distributions to affiliates of Avista Capital Partners, LP, (together with its affiliates, “Avista”), if, when and only to the extent that those cash distributions exceed certain internal rates-of-return and return-on-investment thresholds with respect to Avista’s investment in ACP II as set forth in the limited liability company agreement of ACP II. Because the B Units do not provide the Company with an ownership interest in the oil and gas properties of ACP II, the Company is not required to pay for property acquisition, exploration or development costs associated with ACP II’s ownership interest in oil and gas properties, nor do the B Units entitle the Company to recognize oil and gas production and therefore, proved reserves associated with ACP II’s ownership interest in oil and gas properties. However, under the full cost method of accounting, cash distributions received on the B Units are considered proceeds from the sale of oil and gas properties which are recognized as a reduction of capitalized oil and gas property costs. See Note 10. Related Party Transactions.

Capitalized costs, less accumulated amortization and related deferred income taxes, are limited to the “cost center ceiling” equal to (1) the sum of (A) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (B) the costs of properties not subject to amortization, and (C) the lower of cost or estimated fair value of unproved properties included in the costs being amortized; less (2) related income tax effects. If the net capitalized costs exceed the cost center ceiling, the excess is recognized as an impairment of oil and gas properties. An impairment recognized in one period may not be reversed in a subsequent period even if higher oil and gas prices increase the cost center ceiling applicable to the subsequent period.

The estimated future net revenues used in the ceiling test are calculated using average quoted market prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period. Prior to December 31, 2009, prices and costs used to calculate future net revenues were those as of the end of the appropriate quarterly period. Prices are held constant indefinitely and are not changed except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices used in the ceiling test computation do not include the impact of derivative instruments because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment.

 

F-9

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

Asset Retirement Obligations

The Company’s oil and gas properties require expenditures to plug and abandon wells after the reserves have been depleted. The asset retirement obligation is recognized when the well is drilled with an associated increase in oil and gas property costs. The asset retirement obligation is recorded at fair value and requires estimates of the costs to plug and abandon wells, the costs to restore the surface, the remaining lives of wells based on oil and gas reserve estimates and future inflation rates. The obligation is discounted using a credit-adjusted risk-free interest rate which is accreted over time to its expected settlement value. Estimated costs consider historical experience, third party estimates and state regulatory requirements and do not consider salvage values. At least annually, the Company reassesses its asset retirement obligations to determine whether a change in the estimated obligation is necessary. On a quarterly basis, the Company evaluates whether there are indicators that suggest the estimated cash flows underlying the obligation have materially changed and updates its estimated obligation if necessary.

Cash and Cash Equivalents

Cash and cash equivalents include highly liquid investments with maturities of three months or less when purchased.

Revenue Recognition

Oil and gas sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company follows the sales method of accounting for oil and gas revenues whereby revenue is recognized for all oil and gas sold to purchasers, regardless of whether the sales are proportionate to the Company’s ownership interest in the property. Production imbalances are recognized as an asset or liability to the extent that the Company has an imbalance on a specific property that is in excess of its remaining proved oil and gas reserves. Oil and gas sales volumes are not significantly different from the Company’s share of production and as of December 31, 2010 and 2009, the Company did not have any material production imbalances.

The Company purchases natural gas at the wellhead from a third-party operator under a purchase and sales agreement whereby the Company recognizes revenue when title to the natural gas transfers to a third party purchaser. The Company remits the sales proceeds to the third-party operator which is recorded at the cost of the natural gas purchased. These purchases and sales are recorded in gas purchases and other revenues in the statements of operations and totaled $1.3 million, $1.5 million and $6.6 million for the years ended December 31, 2010, 2009 and 2008, respectively.

Deferred Financing Costs

Deferred financing costs were $14.7 million (net of $6.3 million of accumulated amortization) and $9.7 million (net of $3.9 million of accumulated amortization) as of December 31, 2010 and 2009, respectively and include legal fees, accounting fees, underwriting fees, printing costs, and other direct costs associated with the issuance of the debt instruments and costs associated with revolving credit facilities. The capitalized costs are amortized to interest expense using the effective interest method over the terms of the debt instruments or credit facilities, which is through October 2018 for the Senior Notes due 2018 (“Senior Notes”), May 2013 for the Convertible Senior Notes and October 2012 for the Prior Credit Facility as defined in Note 6. Debt.

Supplemental Cash Flow Information

The consolidated statements of cash flows for the years ended December 31, 2010, 2009 and 2008 do not include the non-cash fair value adjustments to the carrying amount of the Company’s investment in Pinnacle Gas Resources, Inc. recognized in other comprehensive income, net of income taxes of $0, $0.1 million, and $(6.7) million, respectively, net of income taxes.

Financial Instruments

The Company’s financial instruments consist of cash and cash equivalents, receivables, payables, derivative instruments and current and long-term debt. The carrying amounts of cash and cash equivalents, receivables, payables and short-term debt approximate fair value due to the highly liquid or short-term nature of these instruments. The carrying amount of long-term debt under the Prior Credit Facility approximates fair value as these borrowings bear interest at variable rates of interest. The carrying amounts of the Senior Notes and Convertible Senior Notes do not approximate fair value because the notes bear interest at fixed rates of interest. See Note 12. Fair Value Measurements.

 

F-10

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Stock-Based Compensation

The Company grants stock options, stock appreciation rights (“SARs”) that may be settled in cash or common stock (“Stock SARs”), SARs that may only be settled in cash (“Cash SARs”), restricted stock awards and restricted stock units to directors, employees and independent contractors. The Company recognized the following stock-based compensation expenses for the periods indicated which is reflected as general and administrative expense in the consolidated statements of operations:

 

		Years Ended December 31,
		2010				2009				2008
		(In millions)
Stock Options and SARs		$	6.7			$	1.2			$	0.1
Restricted Stock Awards and Units			9.9				10.1				5.9
Total Stock-Based Compensation Expense		$	16.6			$	11.3			$	6.0
Tax Benefit		$	6.2			$	4.1			$	2.1

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

The Company uses the Black-Scholes-Merton option pricing model to compute the fair value of stock options and SARs, which requires the Company to make the following assumptions:

 

•

The risk-free interest rate is based on the zero-coupon United States Treasury yield for the expected term at date of grant.

 

•

The dividend yield on the Company’s common stock is assumed to be zero since the Company does not pay dividends and has no current plans to do so in the future.

 

•

The volatility of the Company’s common stock is based on daily, historical volatility of the market price of the Company’s common stock over a period of time equal to the expected term and ending on the grant date.

 

•

The expected term is based on historical exercise experience for various groups of employees and directors.

Restricted Stock Awards and Units. For restricted stock awards and units, stock-based compensation expense is based on the grant-date fair value and recognized over the vesting period (generally one to three years) using the straight-line method, except for award or units with performance conditions, in which case the Company uses the graded vesting method. The fair value of restricted stock awards and units is based on the average of the high and low price of the Company’s common stock on the grant date. For restricted stock awards and units granted to independent contractors, stock-based compensation expense is based on fair value remeasured at each reporting period and recognized over the vesting period (generally three years) using the straight-line method.

Derivative Instruments

The Company uses derivative instruments, typically fixed-rate swaps, costless collars, puts, calls and basis differential swaps, to manage commodity price risk associated with a portion of its forecasted oil and gas production. Derivative instruments are recognized at their current fair value as assets or liabilities in the consolidated balance sheets. Although the derivative instruments provide an economic hedge of the Company’s exposure to commodity price risk associated with oil and gas production, because the Company elected not to meet the criteria to qualify its derivative instruments for hedge accounting treatment, unrealized gains and losses as a result of changes in the fair value of derivative instruments are recognized as gain (loss) on derivative instruments, net in the consolidated statements of operations. Realized gains and losses as a result of cash settlements with counterparties to the Company’s derivative instruments are also recorded as gain (loss) on derivative instruments, net in the consolidated statements of operations. The Company offsets fair value amounts recognized for derivative instruments executed with the same counterparty.

 

F-11

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The Company’s Board of Directors establishes risk management policies and reviews derivative instruments, including volumes, types of instruments and counterparties, on a quarterly basis. These policies require that derivative instruments be executed only by the President or Chief Financial Officer after consultation with 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. See Note 11, Derivative Instruments for further discussion of the Company’s derivative instruments.

Income Taxes

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

Concentration of Credit Risk

Substantially all of the Company’s accounts receivable result from oil and gas sales, joint interest billings to third parties in the oil and gas industry or drilling and completion advances to third-party operators for development costs of wells in progress. This concentration of customers and joint interest owners may impact the Company’s overall credit risk in that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not require collateral from its customers. The Company generally has the right to offset revenue against related billings to joint interest owners.

Derivative instruments subject the Company to a concentration of credit risk. See Note 11. Derivative Instruments for further discussion of concentration of credit risk related to the Company’s derivative instruments.

Accounts Receivable and Allowance for Doubtful Accounts

The Company establishes an allowance for doubtful accounts when it determines that it will not collect all or a part of an accounts receivable balance. The Company assesses the collectability of its accounts receivable on a quarterly basis and adjusts the allowance as necessary using the specific identification method. A roll forward of the allowance for doubtful accounts is as follows (in thousands):

 

January 1, 2008		$	1,430
Charged to general and administrative expense			(166	)
December 31, 2008			1,264
Charged to general and administrative expense			772
December 31, 2009			2,036
Charged to general and administrative expense			485
Amounts written off			(51	)
December 31, 2010		$	2,470

Major Customers

Sales to individual customers constituting 10% or more of total revenues were as follows:

 

		Year Ended December 31,
		2010				2009				2008
DTE Energy Trading, Inc.			63	%			54	%			39	%
Cokinos Natural Gas Company			*				*				11	%
Crosstex Energy			*				*				10	%

 

(*)	Revenues were below 10%.

 

F-12

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Net Income (Loss) Per Share

Supplemental net income (loss) per share information is provided below:

 

		Year Ended December 31,
		2010				2009				2008
		(In thousands, except per share amounts)
Net income (loss)		$	9,950			$	(204,845	)		$	(45,047	)
Weighted average common shares outstanding			33,861				31,006				30,326
Effect of dilutive instruments			444				—				—
Diluted weighted average shares outstanding			34,305				31,006				30,326
Net income (loss) per share
Basic		$	0.29			$	(6.61	)		$	(1.49	)
Diluted		$	0.29			$	(6.61	)		$	(1.49	)

Basic net income (loss) per common share is based on the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per common share is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the period which include restricted stock units, stock options, Stock SARs expected to be settled in common stock, warrants and convertible debt. The Company excluded 23,688 shares related to restricted stock units, stock options and Stock SARs expected to be settled in common stock from the calculation of dilutive shares for the year-ended December 31, 2010, because the grant prices were greater than the average market prices of the common shares for the period and would be antidilutive to the computation. The Company excluded 1,205,770 and 685,854 shares related to stock options and Stock SARs expected to be settled in common stock from the calculation of dilutive shares for the years ended December 31, 2009 and 2008 due to the net losses reported in those periods. Shares of common stock subject to issuance upon the conversion of the Convertible Senior Notes did not have an effect on the calculation of dilutive shares for the years ended December 31, 2010, 2009 or 2008 because the conversion price was in excess of the market price of the common stock for those periods.

Commitments and Contingencies

Liabilities are recognized for contingencies when it is both probable that an asset has been impaired or that a liability has been incurred and that the amount of such loss is reasonably estimable.

Foreign Currency

The U.S. dollar is the functional currency for the Company’s operations in the U.K. North Sea. Transaction gains or losses that occur due to the realization of assets and the settlement of liabilities using a currency denominated in other than the functional currency are recorded as other income, net in the consolidated statements of operations.

Recently Adopted Accounting Pronouncements

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

In January 2010, the FASB issued Accounting Standards Update No. 2010-03 to align the oil and gas reserve estimation and disclosure requirements of Topic 932 (“Extractive Industries — Oil and Gas”) with the requirements of the Securities and Exchange Commission (“SEC”) Release 33-8994. This release is effective for financial statements issued on or after January 1, 2010. The Company adopted this guidance effective December 31, 2009. This release changes the accounting and disclosure requirements of oil and gas reserves and is intended to modernize and update the oil and gas disclosure requirements, to align them with current industry practices and to adapt to changes in technology. The new rules permit the use of new technologies to determine proved reserves, allow companies to disclose their probable and possible reserves and allow proved undeveloped reserves to be maintained beyond a five-year period only if justified by specific circumstances. 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 reserve 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 average market prices for sales of oil and gas on the first calendar day of each month during the preceding 12-month period prior to the end of the current reporting period.

 

F-13

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3. INVESTMENTS

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

 

		December 31,
		2010				2009
		(In thousands)
Pinnacle Gas Resources, Inc.		$	869			$	835
Oxane Materials, Inc.			2,523				2,523
		$	3,392			$	3,358

Pinnacle Gas Resources, Inc.

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

At March 31, 2009, the market value of the Company’s investment in Pinnacle had consistently remained below its book value since October 2008. The Company determined that the impairment was other than temporary, and accordingly, recognized an impairment of $2.1 million at March 31, 2009. At December 31, 2010, the Company reported the fair value of its investment in Pinnacle at $0.9 million (based on the closing price of Pinnacle’s common stock on December 31, 2010).

On January 25, 2011, Pinnacle announced that it had been acquired by Powder Holdings, LLC, an entity controlled by SW Energy Capital LP. Under the terms of the merger agreement, Pinnacle stockholders are entitled to receive $0.34 per share in cash for each share of Pinnacle common stock. As of December 31, 2010, the Company owned 2,555,825 shares of Pinnacle common stock.

Oxane Materials, Inc.

In May 2008, the Company entered into a strategic alliance agreement with Oxane Materials, Inc. (“Oxane”) in connection with the development of a proppant product to be used in the Company’s exploration and production program. The Company contributed approximately $2.0 million to Oxane in exchange for warrants to purchase Oxane common stock and for certain exclusive use and preferential purchase rights with respect to the proppant. The Company simultaneously invested an additional $500,000 in a convertible promissory note from Oxane. The convertible promissory note 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.

4. PROPERTY AND EQUIPMENT, NET

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

 

		December 31,
		2010				2009
		(In thousands)
Proved oil and gas properties		$	941,267			$	667,907
Accumulated depreciation, depletion and amortization			(314,602	)			(268,725	)
Proved oil and gas properties, net		$	626,665			$	399,182
Costs not subject to amortization:
Unevaluated leaseholds and seismic costs			258,139				258,300
Capitalized interest			38,782				34,563
Exploratory wells in progress			55,558				37,744
Total costs not subject to amortization			352,479				330,607
Other property and equipment			7,314				6,475
Accumulated depreciation			(3,401	)			(2,564	)
Other property and equipment, net			3,913				3,911
Total property and equipment, net		$	983,057			$	733,700

 

F-14

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Costs not subject to amortization totaling $352.5 million at December 31, 2010 include the cost of unevaluated leaseholds and seismic costs associated with specific unevaluated properties of $258.1 million, exploratory wells in progress of $55.6 million and capitalized interest of $38.8 million and such costs were incurred in the following periods: $184.2 million in 2010, $40.9 million in 2009, $124.2 million in 2008 and $3.2 million in 2007 and prior years.

The net capitalized costs of the Company’s United States and U.K. North Sea oil and gas properties did not exceed their respective cost center ceilings and accordingly, did not result in impairments at December 31, 2010. In June 2010, the Company concluded that it was uneconomical to pursue development on the license covering the Monterey field in the U.K. North Sea and terminated further development efforts. Because the U.K. cost center had no proved reserves at that time, the $2.7 million ($1.7 million net of income taxes) of costs associated with the license covering the Monterey field resulted in an impairment for the year ended December 31, 2010.

The net capitalized costs of the Company’s United States oil and gas properties exceeded the cost center ceiling at March 31, 2009 resulting in an impairment of $216.4 million ($140.6 million net of income taxes), at December 31, 2009, resulting in an impairment of $122.5 million ($78.1 million net of income taxes) and at December 31, 2008, resulting in an impairment of $178.5 million ($116.0 million net of income taxes). To measure the cost ceiling for the first quarter of 2009, the Company elected to use a pricing date subsequent to the balance sheet date, as allowed by the accounting requirements in effect at the time. Had the Company used prices in effect as of March 31, 2009, the Company would have recognized an impairment of $323.2 million ($206.1 million net of tax) for the first quarter of 2009. The option to use a pricing date subsequent to the balance sheet date is no longer available under the oil and gas reserve estimation and disclosure requirements which the Company adopted effective December 31, 2009.

Decreases in oil and gas prices as well as changes in production rates, levels of reserves, evaluation of costs not subject to amortization, future development and production costs could result in future impairments of oil and gas properties.

During the fourth quarter of 2009, the Company sold its Mansfield pipeline and gathering system in the Barnett Shale to Delphi Midstream Partners, LLC for $34.7 million and a 12.5% working interest in 16 drilling units in the Barnett Shale to a subsidiary of Sumitomo Corporation (“Sumitomo”) for $15.7 million for certain costs previously incurred by the Company with respect to these drilling units, including Sumitomo’s proportionate share of certain land, seismic and drilling costs.

As discussed further in Note 10. Related Party Transactions, in September 2010, the Company completed the sale of 20% of its interests in substantially all of its oil and gas properties in Pennsylvania that had been subject to the Avista joint venture to Reliance for $13.1 million in cash and a commitment by Reliance to pay 75% of certain of the Company’s future development costs up to approximately $52.0 million. The proceeds were recognized as a reduction of proved oil and gas properties, net and 20% of the unevaluated leasehold and seismic costs associated with these properties (approximately $16.0 million) was also transferred to proved oil and gas properties, net.

During the third and fourth quarters of 2010, ACP II declared and paid cash distributions to affiliates of Avista. Because these distributions exceeded Avista’s internal rates-of-return and return-on-investment thresholds, the Company received cash distributions of approximately $38.8 million on its B Units during the third and fourth quarters of 2010, which were recognized as reductions of capitalized oil and gas property costs.

 

F-15

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5. INCOME TAXES

The components of income tax (expense) benefit were as follows:

 

		Year Ended December 31,
		2010				2009				2008
		(In thousands)
Current income tax (expense) benefit:
Federal		$	—			$	(6	)		$	(29	)
State			(4,236	)			(65	)			(195	)
Total current tax (expense) benefit			(4,236	)			(71	)			(224	)
Deferred income tax (expense) benefit:
Federal			(4,937	)			111,325				20,949
State			3,444				2,053				—
Total deferred tax (expense) benefit			(1,493	)			113,378				20,949
Total income tax (expense) benefit		$	(5,729	)		$	113,307			$	20,725

For the years ended December 31, 2010, 2009 and 2008, all of the Company’s income is derived from domestic activities. Actual income tax expense (benefit) differs from income tax expense (benefit) computed by applying the U.S. federal statutory corporate rate of 35% to pretax income as follows:

 

		Year Ended December 31,
		2010				2009				2008
		(In thousands)
(Expense) Benefit at the statutory rate		$	(5,488	)		$	111,353			$	23,020
State income taxes, net of federal benefit			(792	)			2,270				(123	)
Nondeductible expenses			(46	)			(35	)			(1,930	)
Other			597				(281	)			(242	)
Total income tax (expense) benefit		$	(5,729	)		$	113,307			$	20,725

Deferred income taxes result from temporary differences between the recognition of income and expenses for financial reporting purposes and for tax purposes. At December 31, 2010 and 2009, the tax effects of these temporary differences resulted principally from the following:

 

		December 31,
		2010				2009
		(In thousands)
Deferred income tax assets:
Net operating loss carryforward		$	52,683			$	29,629
Property and equipment			57,201				84,919
Stock-based compensation			4,855				1,963
Allowance for doubtful accounts			915				738
Equity in loss of Pinnacle			422				399
Valuation allowance			—				(399	)
Adjustment to fair value of investment in Pinnacle			713				707
Other			590				224
			117,379				118,180
Deferred income tax liabilities:
Unamortized discount on Convertible Senior Notes			2,372				16,352
Capitalized interest			38,812				30,455
Fair value of derivatives			8,894				2,630
			50,078				49,437
Net deferred income tax asset		$	67,301			$	68,743

 

F-16

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At December 31, 2010 and 2009, the net deferred income tax asset is classified as follows:

 

		December 31,
		2010				2009
		(In thousands)
Noncurrent deferred tax asset		$	72,587			$	70,217
Current deferred tax liability			(5,286	)			(1,474	)
Net deferred income tax asset		$	67,301			$	68,743

As of December 31, 2010, the Company had income tax net operating loss (“NOL”) carryforwards of approximately $160.2 million which expire between 2019 and 2030 if not utilized in earlier periods. The realization of the deferred tax assets related to the NOL carryforward is dependent on the Company’s ability to generate taxable income in the future. The Company believes it will be able to generate sufficient taxable income in the NOL carryforward period. As such, the Company believes that it is more likely than not that its deferred tax assets will be fully realized.

The ability of the Company to utilize the NOL to reduce future taxable income is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by the Company during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of the Company. In the event of an ownership change, Section 382 of the Code imposes an annual limitation on the amount of a Company’s taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (a) the fair market value of the equity of the company multiplied by (b) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. As of December 31, 2010, the Company believes an ownership change occurred in February 2005 with an annual limitation of $12.6 million. Because the Company’s pre-change NOL is $9.8 million, the Company does not believe it has a Section 382 limitation on the ability to utilize its NOL as of December 31, 2010. Future equity transactions involving the Company or 5% shareholders of the Company (including, potentially, relatively small transactions and transactions beyond the Company’s control) could cause further ownership changes and therefore a limitation on the annual utilization of NOLs.

The Company receives a tax deduction during the period stock options are exercised, generally for the excess of the price at which the stock is sold over the exercise price of the option. The Company also receives a tax deduction during the period restricted stock awards and restricted stock units vest, generally for the excess of the value at which the awards or units vest over the grant-date fair value used to recognize stock-based compensation expense. Because these stock-based compensation tax deductions did not reduce current taxes payable as a result of NOL carryforwards, the benefit of these tax deductions has not been reflected in the NOL carryforward deferred tax asset. Stock-based compensation deductions included in NOL carryforwards of $160.2 million but not reflected in deferred tax assets were $17.8 million at December 31, 2010. The Company plans to recognize the $6.6 million deferred tax asset associated with these stock-based compensation tax deductions when all other components of the NOL tax asset have been fully utilized. If and when the stock-based compensation deduction related NOL tax asset is realized, the tax benefit of reducing current taxes payable will be credited directly to additional paid-in capital.

At December 31, 2010, the Company had no material uncertain tax positions and the tax years since 1999 remain open to review by federal and various state tax jurisdictions.

 

F-17

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6. DEBT

At December 31, 2010 and 2009, debt consisted of the following:

 

		December 31,
		2010				2009
		(In thousands)
Senior Notes		$	400,000			$	—
Unamortized Discount for Senior Notes			(2,751	)			—
Convertible Senior Notes			73,750				373,750
Unamortized Discount for Convertible Senior Notes			(6,405	)			(45,122	)
Senior Secured Revolving Credit Facility			93,500				191,400
Other			160				308
			558,254				520,336
Less: current maturities			(160	)			(148	)
		$	558,094			$	520,188

Senior Notes

On November 2, 2010, the Company issued $400 million aggregate principal amount of 8.625% Senior Notes due 2018 (“Senior Notes”) at a price to the initial purchasers of 99.302% of the principal amount in a private placement. The Senior Notes are guaranteed by certain of the Company’s subsidiaries: CCBM, Inc.; CLLR, Inc.; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC; Carrizo Marcellus Holding, Inc.; Hondo Pipeline, Inc.; Bandelier Pipeline Holding, LLC; Chama Pipeline Holding LLC; and Mescalero Pipeline, LLC. The net proceeds of $387.5 million (after deducting the initial purchasers’ discount and the Company’s expenses) were used to repay in full borrowings outstanding under the Prior Credit Facility (defined below) and to fund in part the tender offer for $300 million of the Convertible Senior Notes as described below.

The Senior Notes bear interest at 8.625% per annum which is payable semi-annually on each October 15 and April 15. The Senior Notes mature on October 15, 2018 with interest payable semi-annually. At any time prior to October 15, 2013, the Company may, subject to certain conditions, on one or more occasions, redeem up to 35% of the aggregate principal amount of Senior Notes at a redemption price of 108.625%, of the principal amount, plus accrued and unpaid interest, if any, to the redemption date using the net cash proceeds of one or more equity offerings by the Company. Prior to October 15, 2014, the Company may redeem all or part of the Senior Notes at 100% of the principal amount thereof, plus accrued and unpaid interest and a make whole premium. On and after October 15, 2014, the Company may redeem all or a part of the Senior Notes, at redemption prices decreasing from 104.313% of the principal amount to 100% of the principal amount on October 15, 2017, plus accrued and unpaid interest. If a Change of Control (as defined in the Indenture governing the Senior Notes) occurs, the Company may be required by holders to repurchase Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus any accrued but unpaid interest.

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

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

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

 

F-18

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Convertible Senior Notes

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

In November 2010, the Company completed a tender offer for $300 million aggregate principal amount outstanding of the Convertible Senior Notes for an aggregate consideration of approximately $306.3 million, including accrued and unpaid interest on the Convertible Senior Notes. Each holder received $1,000 for each $1,000 principal amount of Convertible Senior Notes purchased in the tender offer, plus accrued and unpaid interest. The Company recognized a $31.0 million pre-tax loss on extinguishment of debt as a result of the purchase of the Convertible Senior Notes in the tender offer, substantially all of which was non-cash representing the associated unamortized discount and deferred financing costs. After the Company’s purchase of $300 million aggregate principal amount of Convertible Senior Notes, $73.8 million aggregate principal amount of Convertible Senior Notes remained outstanding as of December 31, 2010.

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

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

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

The Convertible Senior Notes are subject to customary non-financial covenants and events of default, including a cross default under the Revolving Credit Facility (defined below), the occurrence and continuation of which could result in the acceleration of amounts due under the Convertible Senior Notes.

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

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

The Company valued the Convertible Senior Notes at May 21, 2008, as $309.6 million of debt and $64.2 million of equity representing the fair value of the conversion premium. The resulting debt discount is being amortized to interest expense through June 1, 2013, the first date on which the holders may require the Company to repurchase the Convertible Senior Notes, resulting in an effective interest rate of approximately 8% for the Convertible Senior Notes. Approximately $27.1 million of the remaining debt discount associated with the Convertible Senior Notes purchased in the tender offer discussed above, was recognized as a component of the loss on the extinguishment of debt. Amortization of the debt discount amounted to $2.2 million and $3.1 million for the three months ended December 31, 2010 and 2009, respectively, and $11.6 million and $12.1 million for the years ended December 31, 2010 and 2009, respectively.

 

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Prior Senior Secured Revolving Credit Facility

As of December 31, 2010, the Company had a senior secured revolving credit facility (the “Prior Credit Facility”) with Wells Fargo Bank, N.A., as administrative agent. The Prior Credit Facility provided for a revolving credit facility up to the lesser of the borrowing base or $350 million. It was secured by substantially all of the Company’s proved oil and gas assets and was guaranteed by certain of the Company’s subsidiaries: CCBM, Inc.; CLLR, Inc.; Carrizo (Marcellus) LLC; Carrizo (Marcellus) WV LLC; Carrizo Marcellus Holding, Inc.; Hondo Pipeline, Inc.; Bandelier Pipeline Holding, LLC; Chama Pipeline Holding LLC; and Mescalero Pipeline, LLC. In January 2011, the Company replaced this facility with a new secured revolving credit facility. See Note 13. Subsequent Events for further discussion.

In December 2010, the borrowing base was decreased from $375 million to $350 million as a result of the net increase in debt associated with the $400 million issuance of the Senior Notes and the $300 million tender for the Convertible Senior Notes.

If the outstanding principal balance of the revolving loans under the Prior Credit Facility exceeded the borrowing base at any time, the Company had 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 have been in addition to any payments that would have come due as a result of the quarterly borrowing base reductions. Otherwise, any unpaid principal or interest would have been due at maturity.

The annual interest rate on each base rate borrowing was (a) the greatest of the agent’s Prime Rate, the Base CD Rate plus 1.0% and the Federal Funds Effective Rate plus 0.5%, plus (b) a margin between 1.00% and 2.00% (depending on the then-current level of borrowing base usage), but such interest rate was never lower than the adjusted Daily LIBO rate on such day plus a margin between 2.25% to 3.25% (depending on the current level of borrowing base usage). The interest rate on each Eurodollar loan was 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 December 31, 2010, the average interest rate for amounts outstanding under the Prior Credit Facility was 3.0%.

The Prior Credit Facility contained covenants in which the Company was required to maintain until the Prior Credit Facility was terminated in January 2011: (1) a minimum current ratio of 1.00 to 1.00 (as defined in the Prior Credit Facility); and (2) a maximum total net debt (which excludes certain amounts attributable to the Convertible Senior Notes) to Consolidated EBITDA (as defined in the Prior Credit Facility) of (a) 4.25 to 1.00 for the fiscal quarters ending on or after December 31, 2010 and on or before June 30, 2011, (b) 4.50 to 1.00 for the fiscal quarters ending on or after September 30, 2011 and on or before December 31, 2011, and (c) 4.00 to 1.00 for each fiscal quarter ending on or after March 31, 2012; and (3) a maximum ratio of senior debt (which excludes the aggregate principal amount of the senior notes and the Convertible Senior Notes) to Consolidated EBITDA of (a) 2.25 to 1.00 for the fiscal quarters ending on or after December 31, 2010 and on or before June 30, 2011, (b) 2.50 to 1.00 for the fiscal quarters ending on or after September 30, 2011 and on or before December 31, 2011 and (c) 2.25 to 1.00 for each fiscal quarter ending on or after March 31, 2012. As defined in the Prior Credit Facility, the current ratio was 2.80 to 1, the total net debt to Consolidated EBITDA ratio was 3.42 to 1 and the ratio of senior debt to Consolidated EBITDA ratio was 0.58 to 1 as of December 31, 2010. Because the calculation of the financial ratios are made as of a certain date, the financial ratios could have fluctuated significantly period to period as the amounts outstanding under the Prior Credit Facility were dependent on the timing of cash flows related to operations, capital expenditures, sales of oil and gas properties and securities offerings.

The Prior Credit Facility also placed restrictions on indebtedness, dividends to shareholders, liens, investments, mergers, acquisitions, asset dispositions, repurchase or redemption of the Company’s common stock, swap agreements, transactions with affiliates and other matters.

The Prior Credit Facility was subject to customary events of default, the occurrence and continuation of which could have resulted in the acceleration of amounts due under the facility by the agent or the lenders.

At December 31, 2010, the Company had $93.5 million of borrowings outstanding under the Prior Credit Facility. The Company also issued $4.1 million of letters of credit which reduced the amounts available under the Prior Credit Facility. Availability under the $350 million borrowing base was subject to the terms and covenants of the Prior Credit Facility. The Prior Credit Facility was used to fund ongoing working capital needs and the remainder of the Company’s capital expenditure plan only to the extent such amounts exceeded the cash flow from operations, proceeds from the sale of oil and gas properties and securities offerings.

 

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7. ASSET RETIREMENT OBLIGATIONS

The following is a roll forward of asset retirement obligations:

 

		Year Ended December 31, 2010				Year Ended December 31, 2009
		(In thousands)
Asset retirement obligations at beginning of period		$	5,410			$	6,503
Liabilities incurred			181				444
Liabilities settled			(288	)			(36	)
Accretion expense			216				308
Revisions of previous estimates			850				(1,809	)
Asset retirement obligations at end of period		$	6,369			$	5,410

The revisions of previous estimates for the year ended December 31, 2010, related primarily to increases in estimates of abandonment costs of wells in the Gulf Coast. The revisions of previous estimates for the year ended December 31, 2009, related primarily to increases in the estimated life of wells in the Barnett Shale.

8. 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, the Company does not expect these matters to have a materially adverse effect on the financial position or results of operations 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.

The Company has an operating lease agreement for its corporate offices that expires in December 2011. Under the terms of the lease agreement, the Company received rent abatements equal to six months of lease payments and a build out allowance that is being amortized to expense over the term of the lease. In 2006 and 2010, the Company amended its lease agreement to expand the leased office space. The lease term for the additional space also expires in December 2011. Rent expense included in general and administrative expense for the years ended December 31, 2010, 2009 and 2008 was $1.0 million, $0.9 million and $0.9 million, respectively, and includes rent expense for the Company’s corporate office and a field office.

At December 31, 2010, total minimum commitments from long-term non-cancelable operating leases, drilling rig, seismic and pipeline volume commitments as follows:

 

		Amount
		(In thousands)
2011		$	40,542
2012			24,346
2013			19,328
2014			14,194
2015			8,899
2016 and Thereafter			6,041
		$	113,350

 

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9. SHAREHOLDERS’ EQUITY AND STOCK INCENTIVE PLAN

Shareholders’ Equity

Common Stock. In December 2010, the Company sold 3.975 million shares of its common stock in an underwritten public offering at a price to the underwriter of $28.90 per share. The Company used the net proceeds of approximately $114.9 million to repay a portion of the outstanding borrowings under the Prior Credit Facility.

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

In February 2008, the Company sold 2.59 million shares of its common stock in an underwritten public offering at a price of $54.50 per share, raising $135.1 million of net proceeds. With a portion of the proceeds the Company repaid $85.0 million of outstanding borrowings under the Prior Credit Facility. The Company used the remaining proceeds to fund a portion of its 2008 capital expenditure program.

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

During 2010, the Company issued warrants to purchase 57,641 shares of the Company’s common stock to the third party’s affiliate in connection with purchases of leases by the third party under the Land Agreement.

Stock Incentive Plans

In 1997, the Company established the Incentive Plan of Carrizo Oil & Gas, Inc. (the “Incentive Plan”), which authorizes the granting of stock options, SARs that may be settled in cash or common stock (“Stock SARs”), restricted stock awards and restricted stock units to directors, employees and independent contractors. The Company may grant awards of up to 4,395,000 shares under the Incentive Plan and through December 31, 2010, has granted stock options, restricted stock awards and restricted stock units covering 3,700,672 shares through December 31, 2010, net of forfeitures and excludes Stock SARs the Company has elected to settle in cash.

 

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Stock Options and Stock SARs. The table below summarizes the activity for stock options and Stock SARs the Company expects to settle in common stock for the three years ended December 31, 2010, 2009 and 2008:

 

		Shares				Weighted- Average Exercise Prices				Weighted- Average Remaining Life (In years)				Aggregate Intrinsic  Value (In millions)
For the Year Ended December 31, 2008
Outstanding, beginning of period			761,921			$	4.67
Granted			—				—
Exercised			(65,400	)			4.01
Forfeited			(10,667	)			6.72
Outstanding, end of period			685,854			$	4.71
Exercisable, end of period			685,854			$	4.71
For the Year Ended December 31, 2009
Outstanding, beginning of period			685,854			$	4.71
Granted			214,609				20.18
Exercised			(5,000	)			1.81
Forfeited			—				—
Outstanding, end of period			895,463			$	8.43
Exercisable, end of period			680,854			$	4.73
For the Year Ended December 31, 2010
Outstanding, beginning of period			895,463			$	8.43
Granted			—				—
Exercised			(266,433	)			2.59
Forfeited			(2,493	)			18.56
Other			(211,683	)			20.22
Outstanding, end of period			414,854			$	6.10				2.16			$	11.75
Exercisable, end of period			414,854			$	6.10				2.16			$	11.75

During 2009, the Company granted 211,683 Stock SARs which the Company expected to settle in common stock. During July 2010, the Company elected to settle those Stock SARs in cash. Accordingly, during the third quarter of 2010, the Company recognized a fair value liability for the vested portion of the Stock SARs using assumptions in effect at the date the awards were modified and additional stock-based compensation expense of $0.3 million. The following table summarizes the weighted-average assumptions used in the Black-Scholes-Merton option pricing model to calculate the grant date and modification date fair values of the Stock SARs:

 

		2010				2009
Grant-date fair value		$	—			$	10.14
Modification date fair value		$	12.48			$	—
Volatility factor			60.7	%			61.3	%
Dividend yield			—				—
Risk-free interest rate			1.1	%			2.0	%
Expected term (in years)			4.3				4.1

No stock options or Stock SARs were granted during 2010 or 2008. The Stock SARs contain performance and service conditions. The performance conditions have been met for all awards.

At December 31, 2010, the liability for Stock SARs to be settled in cash was $3.5 million of which, $2.7 million is classified as other accrued liabilities representing the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder of $0.8 million, classified as other long-term liabilities. As of December 31, 2010, unrecognized compensation costs related to unvested Stock SARs to be settled in cash was $1.0 million and will be recognized as stock-based compensation expense over a weighted-average period of 1.4 years.

At December 31, 2010, all stock options were vested and accordingly, the Company had no unrecognized compensation costs related to outstanding stock options. The total intrinsic value (current market price less the stock option exercise price) of stock options exercised during the years ended December 31, 2010, 2009 and 2008 was $6.0 million, $0.1 million, and $2.5 million, respectively, and the Company received $0.7 million, $9,000, and $0.3 million in cash in connection with stock option exercises for the years ended December 31, 2010, 2009 and 2008, respectively.

 

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Restricted Stock Awards and Units. The Company began issuing restricted stock awards in 2005 and restricted stock units in 2009. Although shares of common stock are not released to the employee until vesting, restricted stock awards have the right to vote and accordingly, restricted stock awards are considered issued and outstanding at the date of grant. Restricted stock units are not considered issued and outstanding until converted into common shares and released to the employee upon vesting. The table below summarizes restricted stock award and unit activity for the years ended December 31, 2010, 2009 and 2008:

 

		Shares/ Units				Grant-date Fair Value
Unvested restricted stock awards and units at December 31, 2007			351,849			$	31.15
Granted			215,469				35.43
Vested			(217,113	)			28.65
Forfeited			(8,507	)			42.00
Unvested restricted stock awards and units at December 31, 2008			341,698				34.93
Granted			529,062				18.76
Vested			(390,655	)			25.49
Forfeited			(8,862	)			28.81
Unvested restricted stock awards and units at December 31, 2009			471,243				25.01
Granted			640,207				18.60
Vested			(380,668	)			23.42
Forfeited			(19,827	)			25.23
Unvested restricted stock awards and units at December 31, 2010			710,955			$	20.26

As of December 31, 2010, unrecognized compensation costs related to unvested restricted stock awards and units was $9.6 million and will be recognized as stock-based compensation expense over a weighted-average period of two years. The 2009 and 2010 grants of restricted stock awards and units contained performance and service conditions. The performance conditions have been met for all awards.

Cash- Settled Stock Appreciation Rights Plan

In June 2009, the Company established the Carrizo Oil & Gas, Inc. Cash-Settled Stock Appreciation Rights Plan (“Cash SARs Plan”). The Cash SARs Plan enables employees and independent contractors to share in the appreciation of Carrizo’s common stock, but does not require the issuance of shares. During 2010, the Company issued 408,804 Cash SARs. At December 31, 2010, the liability for Cash SARs was $4.3 million of which, $2.7 million is classified as other accrued liabilities representing the portion of the awards that are vested or are expected to vest within the next 12 months, with the remainder of $1.6 million, classified as other long-term liabilities. The following table summarizes the weighted-average assumptions used in the Black-Scholes-Merton option pricing model to calculate the fair value of the Cash SARs at December 31, 2010:

 

		Cash SARs Granted in  2010				Cash SARs Granted in  2009
December 31, 2010 fair value		$	23.06			$	21.57
Volatility factor			60.3	%			60.7	%
Dividend yield			—				—
Risk-free interest rate			1.8	%			1.7	%
Expected term (in years)			4.5				4.3

As of December 31, 2010, unrecognized compensation costs related to unvested Cash SARs was $6.8 million and will be recognized as stock-based compensation expense over a weighted-average period of 2.4 years. The 2010 grants of Cash SARs contained performance and service conditions. The performance conditions have been met for all awards.

 

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10. RELATED PARTY TRANSACTIONS

Marcellus Shale Joint Ventures. Effective August 1, 2008, Carrizo Marcellus, a wholly-owned subsidiary of the Company, entered into a joint venture arrangement with ACP II, an affiliate of Avista. In September 2010, the Company completed the sale of 20% of its interests in substantially all of its oil and gas properties in Pennsylvania that had been subject to the Avista joint venture to Reliance Marcellus II, LLC (“Reliance”), a wholly-owned subsidiary of Reliance Holding USA, Inc. and an affiliate of Reliance Industries Limited for $13.1 million in cash and a commitment by Reliance to pay 75% of certain of the Company’s future development costs up to approximately $52.0 million. The proceeds were recognized as a reduction of proved oil and gas properties, net and 20% of the unevaluated leasehold and seismic costs associated with these properties (approximately $16.0 million) was also transferred to proved oil and gas properties, net. Simultaneously with the closing of this transaction, ACP II closed the sale of its entire interest in the same properties to Reliance for a purchase price of approximately $327 million. At the time of entering into the agreements for these transactions, the Company and Avista agreed that B Unit distributions to the Company with respect to Avista’s sale of properties to Reliance would be principally based upon Avista’s return on investment and internal rates of return associated with such properties, subject to amounts withheld from distribution by ACP II’s board. During the third and fourth quarters of 2010, the Company received cash distributions of approximately $38.8 million from ACP II in respect of these B Units. In connection with these sales transactions, the Company and Avista amended the participation agreement and other joint venture agreements with Avista to provide that the properties that the Company and Avista sold to Reliance, as well as the properties the Company committed to the new joint venture with Reliance, are not subject to the terms of the Avista joint venture, and that the Avista joint venture’s area of mutual interest will generally not include Pennsylvania, the state in which those properties are located. The Company’s joint venture with Avista continues and now covers approximately 175,000 net acres, primarily in West Virginia and New York pursuant to the terms of the Avista area of mutual interest, effective December 31, 2010, the initial area of mutual interest was reduced to specified halos in which the Avista joint venture was active.

In December 2010 the Company entered into a settlement agreement with Reliance providing for the resolution of defects in title that Reliance alleged with respect to the properties it acquired from the Company and Avista in September 2010. In the agreement, the Company agreed to undertake specified curative measures with respect to the properties it and Avista sold to Reliance, and to indemnify Reliance on its own behalf and on behalf of Avista with respect to specified third party claims (in addition to existing customary indemnification obligations under the purchase agreement). In connection with entering into the settlement agreement, the Company entered into an agreement with Avista by which Avista agreed to indemnify the Company for amounts paid on Avista’s behalf by the Company under the settlement agreement, if any.

On November 16, 2010, Carrizo Marcellus assigned, via distribution and subsequent contribution, its interests in the joint venture with Avista to Carrizo (Marcellus) WV LLC (“Carrizo WV”), also a wholly-owned subsidiary of the Company. In connection with the assignment, Carrizo Marcellus assigned to Carrizo WV its rights and obligations under the participation agreement, as well as the related joint operating agreement, pursuant to which operatorship of the joint venture was assumed by Carrizo WV. In addition, Carrizo WV and the other parties thereto amended and restated the participation agreement on November 16, 2010, effective as of October 1, 2010. This amended and restated participation agreement amends the participation agreement by, among other things, (i) providing fixed percentages and thresholds for sharing net cash flow from hydrocarbon production and proceeds from the sales of underlying joint venture properties and (ii) eliminating provisions that have been performed and are inapplicable going forward.

The Company serves as operator of the properties covered by the joint venture with Avista under a joint operating agreement with Avista and also performs specified management services for the Avista affiliate that is the Company’s partner in the joint venture. An operating committee composed of one representative of each party provides overall supervision and direction of joint operations. Avista or its designee has the right to become a co-operator of the properties if all of its membership interests or substantially all of its assets are sold to an unaffiliated third party or if the Company defaults under the terms of any pledge of its interest in the properties.

The Company has agreed to jointly market Avista’s share of the production from the properties with its own until the cash flows and sale proceeds are allocated in accordance with the parties’ participating interests under the joint operating agreement. In connection with the formation of ACP II, Carrizo (Marcellus) was issued B Units in ACP II which entitle the Company to increasing percentages of cash distributions to affiliates of Avista Capital Partners, LP, if, when, and only to the extent that those cash distributions exceed certain internal rates-of-return and return-on-investment thresholds with respect to Avista’s investment as set forth in the limited liability company agreement of ACP II. The business and affairs of ACP II are managed under the direction of a three-member board of managers, consisting of employees and principals of Avista. The B Units have limited rights with respect to the actions of ACP II and no voting rights with respect to the election of managers.

During 2010, each party satisfied the Initial Cash Contribution and now has ability to transfer its interest in the joint venture to third parties subject in most instances to preferential purchase rights for transfers of less than 10% of its interest in joint venture properties, or to “tag along” rights for most other transfers.

 

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Steven A. Webster, Chairman of the Company’s Board of Directors, serves as Co-Managing Partner and President of Avista Capital Holdings, LP, which has the ability to control Avista. ACP II’s Board of Managers have the sole authority for determining whether, when and to what extent any cash distributions will be declared and paid to members of ACP II. Mr. Webster is not a member of ACP II’s Board of Managers. As previously disclosed, the Company has been a party to prior arrangements with affiliates of Avista Capital Holdings, LP in respect of the Company’s investment in Pinnacle Gas Resources, Inc.

ACP II Distributions. During the third and fourth quarters of 2010, the Company received cash distributions of $38.8 million on its B Unit investment in ACP II, which were recognized as a reduction of capitalized oil and gas property costs.

Avista Land Bank Agreement. In order to expand the Company’s lease acquisition efforts in the Marcellus Shale, the Company elected to enter into a lease option agreement effective August 1, 2008 with Avista. The terms and conditions of the lease purchase option arrangement with Avista were generally consistent with lease option arrangements that the Company has traditionally entered into with other third parties. Avista paid approximately $27.5 million for the oil and gas leases under the lease purchase option agreement and subsequently contributed these properties to the Company’s Marcellus joint venture with Avista, effective August 1, 2008.

Other Transactions. The Company’s Chairman of the Board, Mr. Steven A. Webster, serves on the Board of Directors of Basic Energy Services, Inc., Hercules Offshore, Inc., and Geokinetics, Inc., the parent of Geokinetics USA (formally Quantum Geophysical, Inc.), and previously served on the Board of Directors of each of Goodrich Petroleum, Brigham Exploration, Pinnacle Gas Resources, Inc. and Grey Wolf Inc. The Company’s Chief Executive Officer, Mr. S.P. Johnson, serves on the Board of Directors of Basic Energy Services, Inc. and Pinnacle Gas Resources, Inc. until the time of its sale in January 2011. Mr. Thomas L. Carter, Jr., a member of the Company’s Board of Directors, is the Chief Executive Officer and owner of a significant interest in Black Stone Minerals Company, L.P. (“Black Stone Minerals”). Mr. F. Gardner Parker serves on the Board of Directors for Hercules Offshore, Inc. Due to these relationships, the Company has deemed these companies to be related parties. The Company incurred the following costs with these related parties:

 

		Year Ended December 31,
		2010				2009				2008
		(In millions)
Basic Energy Services		$	0.3			$	0.1			$	0.4
Geokinetics, Inc.			—				0.4				—
Grey Wolf Inc. (1)			—				—				7.1
Hercules Offshore, Inc.			—				—				3.2

 

(1)	During 2009, Grey Wolf Inc. merged with another company and is no longer considered a related party at January 1, 2009.

It is the Company’s opinion that the transactions with these entities were executed at prevailing market rates. At December 31, 2010, 2009 and 2008, the Company had outstanding related-party net payable balances of approximately $58,000, $66,000 and $66,000, respectively.

In January 2006, the Company acquired certain oil and gas leases for approximately $1.1 million from Black Stone Acquisitions Partners I L.P., the general partner of which is Black Stone Minerals. Black Stone Acquisition Partners also retains a royalty interest in the acquired leases, which are located in Mississippi. During 2008, the Company acquired additional acreage located in Texas from Black Stone Minerals for approximately $0.2 million. During 2010 and 2009, the Company did not acquire any additional acreage from Black Stone Minerals. The terms and conditions of the lease agreement with Black Stone Acquisitions Partners I L.P. and Black Stone are generally consistent with the lease agreements that the Company has entered into with other third parties. Additionally, the Company operates four producing wells in which affiliates of Black Stone Minerals hold a royalty interest for which the Company paid approximately $0.1 million, $0.2 million and $0.6 million in 2010, 2009 and 2008, respectively.

The Company paid Mr. Webster less than $1,000 in each of 2010, 2009 and 2008 in overriding royalties that were incurred under a lease purchase option arrangement that expired in 2006.

11. DERIVATIVE INSTRUMENTS

The Company relies on various types of derivative instruments to manage its exposure to commodity price risk and to provide a level of certainty in its forward cash flows supporting its capital expenditure program. The derivative instruments typically used are fixed-rate swaps, costless collars, puts, calls and basis differential swaps. Under these derivative instruments, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at termination, expiration or exchanged for physical delivery contracts. The Company’s current long-term strategy is to manage exposure for a substantial, but varying, portion of forecasted production up to 36 months. The derivative instruments are carried at fair value in the consolidated balance sheets, with the changes in fair value included in the consolidated statements of operations for the period in which the changes occur.

 

F-26

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The fair value of derivative instruments at December 31, 2010 was a net asset of $24.1 million, 74% with Credit Suisse, 14% with Shell Energy North America (US) LP, 9% with Credit Agricole, and the remaining 3% with BNP Paribas and master netting agreements are in place with these counterparties. Because the counterparties are either investment grade financial institutions or an investment grade international oil and gas company, the Company believes it has minimal credit risk and accordingly does not currently require its counterparties to post collateral to support the asset positions of its derivative instruments. As such, the Company is exposed to credit risk to the extent of nonperformance by the counterparties to its derivative instruments. Although the Company does not currently anticipate such nonperformance, it continues to monitor the financial viability of its counterparties. Three of the four counterparties to the Company’s derivative instruments are lenders in the Company’s Revolving Credit Facility, and accordingly, the Company is not required to post collateral under these contracts as they are secured by the Revolving Credit Facility.

The following sets forth a summary of the Company’s natural gas derivative positions at average delivery location (Waha and Houston Ship Channel) prices as of December 31, 2010. Our crude oil derivative positions at December 31, 2010, were not significant.

 

Period		Volume (in MMbtu)				Weighted Average Floor Price ($/MMbtu)				Weighted Average Ceiling Price ($/MMbtu)
2011			21,340,000			$	5.96			$	6.34
2012			7,963,000			$	6.49			$	7.13

In connection with the derivative instruments above, the Company has entered into protective put spreads. When the market price declines below the short put price as reflected below, the Company will effectively receive the market price plus a put spread. For example, for 2011, if market prices fall below the short put price of $4.55, the floor price becomes the market price plus the put spread of $1.46 on 16,799,000 of the 21,340,000 MMBtus and the remaining 4,541,000 MMBtus have a long put price of $5.96.

 

Period		Volume (in MMbtu)				Weighted Average Short Put Price ($/MMbtu)				Weighted Average Long Put Price ($/MMbtu)				Weighted Average Put Spread ($/MMbtu)
2011			16,799,000			$	4.55			$	6.01			$	1.46
2012			6,404,000			$	5.20			$	6.41			$	1.21

For the years ended December 31, 2010, 2009 and 2008, the Company recorded the following related to its derivative instruments:

 

		Year Ended December 31,
		2010				2009				2008
		(In thousands)
Realized gain (loss)
Derivative instruments		$	33,218			$	74,866			$	(1,819	)
Interest rate swaps			—				—				(1,201	)
Loss on interest swap termination			—				—				(3,340	)
			33,218				74,866				(6,360	)
Unrealized gain (loss)
Derivative instruments			14,564				(33,401	)			41,104
Interest rate swaps			—				—				2,755
			14,564				(33,401	)			43,859
Gain on derivative instruments, net		$	47,782			$	41,465			$	37,499

 

F-27

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The Company deferred the payment and receipt of premiums associated with certain of its derivative instruments totaling a net liability of $3.9 million and $4.8 million at December 31, 2010 and December 31, 2009, respectively. The Company classified $3.9 million and $1.8 million as other current liabilities at December 31, 2010 and December 31, 2009, respectively, and $3.0 million as other non-current liabilities at December 31, 2009. These deferred premiums will be paid to the counterparty with each monthly settlement (January 2011 – December 2011) and recognized as a reduction of realized gain on derivative instruments.

12. FAIR VALUE MEASUREMENTS

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

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

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

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.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2010 and 2009, and indicate the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value:

 

December 31, 2010		Level 1				Level 2				Level 3				Total
		(In thousands)
Assets:
Investment in Pinnacle Gas Resources, Inc.		$	869			$	—			$	—			$	869
Derivative instruments			—				48,140				—				48,140
Liabilities:
Derivative instruments			—				(24,062	)			—				(24,062	)
Total		$	869			$	24,078			$	—			$	24,947
December 31, 2009		Level 1				Level 2				Level 3				Total
		(In thousands)
Assets:
Investment in Pinnacle Gas Resources, Inc.		$	835			$	—			$	—			$	835
Derivative instruments			—				14,881				—				14,881
Liabilities:
Derivative instruments			—				(2,818	)			—				(2,818	)
Total		$	835			$	12,063			$	—			$	12,898

The fair values of derivative instruments are based on a third-party pricing model which utilizes inputs that include (a) quoted forward prices for oil and gas, (b) discount rates, (c) volatility factors and (d) current market and contractual prices, as well as other relevant economic measures. The estimates of fair value are compared to the values provided by the counterparty for reasonableness. Derivative instruments are subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of the Company’s derivative instruments, but to date has not had a material impact on estimates of fair values. The fair values reported in the consolidated balance sheets are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. The assets and liabilities for derivative instruments included in the tables above are presented on a gross basis. The assets and liabilities for derivative instruments included in the consolidated balance sheets are presented on a net basis when such amounts are with the same counterparty and subject to master netting agreements. The fair values of the investment in Pinnacle are based on the closing price of Pinnacle’s common stock on December 31, 2010 and December 31, 2009. The Company had no transfers in or out of Levels 1 or 2 for the year ended December 31, 2010.

 

F-28

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Fair Value of Other Financial Instruments

The Company’s other financial instruments consist of cash and cash equivalents, receivables, payables and current and long-term debt. The carrying amounts of cash and cash equivalents, receivables, payables and short-term debt approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the borrowings under the Prior Credit Facility approximate the carrying amounts as of December 31, 2010, and were based upon interest rates currently available to the Company for borrowings with similar terms. The fair values of the Convertible Senior Notes and Senior Notes at December 31, 2010 were estimated at approximately $71.9 million and $412.0 million based on quoted market prices.

Other Fair Value Measurements

The initial measurement of asset retirement obligations at fair value is calculated using discounted future cash flows of internally estimated costs. Significant Level 3 inputs used in the calculation of asset retirement obligations include the costs of plugging and abandoning wells, the costs of surface restoration and reserve lives. See Note 7. Asset Retirement Obligations for a roll forward of the Company’s asset retirement obligations.

13. SUBSEQUENT EVENTS

Senior Secured Revolving Credit Facility

On January 27, 2011, the Company entered into a new $750 million secured revolving credit facility with a five-year term (“Revolving Credit Facility”) with BNP Paribas as the administrative agent, sole book runner and lead arranger in the nine-bank syndication. The Revolving Credit Facility provides for a revolving credit facility up to the lesser of (i) the Borrowing Base and (ii) $750 million. The Revolving Credit Facility matures on January 27, 2016. It is secured by substantially all of the Company’s assets and is guaranteed by certain of the Company’s subsidiaries: Bandelier Pipeline Holding, LLC, Carrizo Marcellus Holding Inc., Carrizo (Marcellus) LLC, Carrizo (Marcellus) WV LLC, CLLR, Inc., Hondo Pipeline, Inc. and Mescalero Pipeline, LLC.

The initial Borrowing Base under the Revolving Credit Facility is $350 million. The Borrowing Base will be redetermined by the lenders at least semi-annually on each May 1 and November 1, beginning May 1, 2011. The Company and the lenders may each request one unscheduled borrowing base redetermination between each scheduled redetermination. The Borrowing Base will also be reduced in certain circumstances as a result of certain issuances of senior notes, cancellation of certain hedging positions and as a result of certain asset sales. The amount the Company is able to borrow with respect to the Borrowing Base is subject to compliance with the financial covenants and other provisions of the Revolving Credit Facility.

If the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the Revolving Credit Facility exceeds the Borrowing Base at any time as a result of a redetermination of the Borrowing Base, 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, deliver reserve engineering reports and mortgages covering additional oil and gas properties 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 next six-month period. Upon certain adjustments to the Borrowing Base, the Company is required to make a lump sum payment in an amount equal to the amount by which the outstanding principal balance of the revolving loans and the aggregate face amount of all letters of credit under the Revolving Credit Facility exceeds the Borrowing Base. Otherwise, any unpaid principal 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 Federal Funds Effective Rate plus 0.5% and the adjusted LIBO rate for a three-month interest period on such day plus 1.00%, plus (b) a margin between 1.00% and 2.00% (depending on the then-current level of borrowing base usage). The interest rate on each Eurodollar loan will be the adjusted LIBO rate for the applicable interest period plus a margin between 2.00% to 3.00% (depending on the then-current level of borrowing base usage).

The Company is subject to certain covenants under the terms of the Revolving Credit Facility which include, but are not limited to, the maintenance of the following financial covenants: (1) a total net debt to Consolidated EBITDA (as defined in the Revolving Credit Facility) ratio of not more than (a) 4.75 to 1.00 for any fiscal quarter ending on or after March 31, 2011 and on or before December 31, 2011, (b) 4.25 to 1.00 for any fiscal quarter ending on or after March 31, 2012 and on or before June 30, 2012 and (c) 4.00 to 1.00 for any fiscal quarter ending on or after September 30, 2012; (2) a current ratio of not less than 1.0 to 1.0; (3) a senior debt to EBITDA ratio of not more than 2.50 to 1.00; and (4) an EBITDA to interest expense ratio of not less than 2.50 to 1.00.

 

F-29

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The Revolving Credit Facility also places restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.

The Revolving Credit Facility is subject to customary events of default, including a change in control (as defined in the Revolving Credit Facility). If an event of default occurs and is continuing, the Majority Lenders (as defined in the Revolving Credit Facility) may accelerate amounts due under the Revolving Credit Facility (except for a bankruptcy event of default, in which case such amounts will automatically become due and payable).

On January 27, 2011, the Company borrowed $112 million under the Revolving Credit Facility, which was used to repay in full indebtedness outstanding under the Senior Credit Agreement governing the Prior Credit Facility, to pay transaction costs associated with entrance into the Revolving Credit Facility and for other general business purposes. Future availability under the new Revolving Credit Facility, which currently has a $350 million borrowing base, is subject to the terms and covenants of the Revolving Credit Facility.

UK North Sea Credit Agreement

On January 28, 2011, the Company and Carrizo UK Huntington Ltd., a wholly-owned subsidiary of the Company incorporated in England and Wales (“Carrizo UK”), as Borrower, entered into a Senior Secured Multicurrency Credit Facility Agreement with BNP Paribas and Societe Generale, as lead arrangers and original lenders (the “Huntington Facility”). The Huntington Facility is secured by substantially all of Carrizo UK’s assets and is limited recourse to the Company. The Huntington Facility provides financing for a substantial portion of Carrizo UK’s share of costs associated with the Huntington Field development project in the U.K. North Sea. The Huntington Facility provides for a multi-currency credit facility consisting of (1) a term loan facility to be used to fund Carrizo UK’s share of project development costs, (2) a contingent cost overrun term loan facility and (3) a post-completion revolving credit facility providing for loans and letters of credit to be used to fund certain abandonment and decommissioning costs following project completion.

The total term loan facility commitment is $55 million, with availability under the facility subject to a borrowing base, which is currently in excess of the commitment. The total cost overrun facility commitment is $6.5 million, which may be utilized only when funds under the term loan facility have been exhausted and certain other requirements are satisfied. The total post-completion revolving credit facility commitment is $22.5 million. Availability under each of the term loan facility and the cost overrun facility is subject to borrowing bases that are generally based on consolidated cash flow and debt service projections for Carrizo UK attributable to certain proved reserves in the Huntington Field project. The borrowing bases of the term loan facility and the cost overrun facility will be redetermined by the lenders at least semi-annually on each April 1 and October 1 in connection with the updating and recalculation of revenue and cash flow projections with respect to the Huntington Field project, except that the first such redetermination and recalculation will take place on May 1, 2011. If the outstanding principal balance of the term loan facility and cost overrun facility exceeds the aggregate borrowing base for such facility at any time as a result of a redetermination of such facility’s borrowing base, Carrizo UK will be obligated to make a payment to cure the deficiency within five business days.

Initial borrowings under the term loan facility and cost overrun facility are conditioned on, among other things, the Company’s having made an approximately $22 million equity contribution to Carrizo UK, which has been completed. Prior to project completion, the Company may be required under the Huntington Facility to make an additional equity contribution to Carrizo UK in the event the term loan borrowing base is reduced to a level at or above the amount of borrowings then outstanding. The Company may be required under the Huntington Facility to make certain additional equity contributions to Carrizo UK in the event of certain specified projected Cost Overruns (as defined in the Huntington Facility). To the extent that the cost overrun facility and any required equity contribution are insufficient, the Company is required to fund any Cost Overruns on a 100% basis. If after project completion, the lenders reasonably determine that Carrizo UK is required to incur additional capital expenditures that were not contemplated by the Huntington Field development plan originally approved by the U.K. Department of Energy and Climate Change, the Company is required to fund such additional expenditures. The Company is responsible for making certain other payments under the Huntington Facility, including funding certain projected working capital shortfalls, providing cash collateral for letters of credit issued under the post-completion revolving credit facility and paying certain costs of the required hedging arrangements described below.

The annual interest rate on each borrowing is (a) LIBOR (EURIBOR for euro-denominated loans) for the applicable interest period, plus (b) a margin of (i) 3.50% until the completion of the Huntington Field development project and 3.0% thereafter for the term loan credit facility and post-completion revolving credit facility or (ii) 4.75% for the cost overrun facility. Borrowings under the term loan and cost overrun facilities are available until the earlier of December 31, 2012 or the achievement of certain project development milestones. The term loan and cost overrun facilities mature on December 31, 2014, subject to acceleration in the event that future projection estimates of remaining reserves in the project area have declined to less than 25% of the level initially projected by Carrizo UK and the lenders. Letters of credit under the post-completion revolving credit facility mature on December 31, 2016. Amounts outstanding under the term loan or cost overrun facility must be repaid according to the following schedule: (i) 45% will be due on December 31, 2012, (ii) 20% will be due on June 30, 2013, (iii) 20% will be due on December 31, 2013, (iv) 10% will be due on June 30, 2014 and (iv) the remaining 5% will be due on the final maturity date of December 31, 2014.

 

F-30

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The Huntington Facility requires Carrizo UK to enter into certain hedging arrangements to hedge a specified portion of the Huntington Field project’s exposure to fluctuating petroleum prices as well as changes in interest rates or exchange rates, and permits Carrizo UK to enter into additional hedging arrangements. The Huntington Facility places restrictions on Carrizo UK with respect to additional indebtedness, liens, the extension of credit, dividends or other payments to the Company or its other subsidiaries, investments, acquisitions, mergers, asset dispositions, commodity transactions outside of the mandatory hedging program, transactions with affiliates and other matters.

The Huntington Facility is subject to customary events of default. If an event of default occurs and is continuing, the Majority Lenders (as defined in the Huntington Facility) may accelerate amounts due under the Huntington Facility.

14. SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

The Company’s oil and gas properties are located in the U.S. and U.K.

Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities are summarized below:

 

		Year Ended December 31,
		2010				2009				2008
		(In thousands)
U.S.
Property acquisition costs
Unproved		$	126,783			$	35,248			$	271,618
Proved			—				—				—
Exploration costs			134,487				77,255				235,382
Development costs			62,952				55,270				49,626
Asset retirement obligations			1,031				(1,390	)			630
Total costs incurred		$	325,253			$	166,383			$	557,256
U.K.
Property acquisition costs
Unproved		$	806			$	—			$	—
Proved			—				—				—
Exploration costs			5,375				—				—
Development costs			—				—				—
Asset retirement obligations			—				—				—
Total costs incurred		$	6,181			$	—			$	—
Total Worldwide
Property acquisition costs
Unproved		$	127,589			$	35,248			$	271,618
Proved			—				—				—
Exploration costs			139,862				77,255				235,382
Development costs			62,952				55,270				49,626
Asset retirement obligations			1,031				(1,390	)			630
Total costs incurred		$	331,434			$	166,383			$	557,256

Costs incurred excludes capitalized interest on unproved properties of $20.8 million, $19.7 million, and $20.5 million for the years ended December 31, 2010, 2009 and 2008, respectively, and includes capitalized overhead of $5.3 million, $5.6 million, and $7.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.

 

F-31

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Proved Oil and Gas Reserve Quantities

Proved reserves are generally those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future years from known reservoirs under existing economic conditions, operating methods and government regulations. Proved developed reserves include proved reserves that can be expected to be produced through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are generally proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Proved oil and gas reserve quantities at December 31, 2010, 2009 and 2008, and the related discounted future net cash flows before income taxes are based on estimates prepared by LaRoche Petroleum Consultants, Ltd., Ryder Scott Company Petroleum Engineers, and Fairchild and Wells, Inc. Such estimates have been prepared in accordance with guidelines established by the SEC.

The Company’s net proved oil and gas reserves and changes in net proved oil and gas reserves, which are located in the U.S. and U.K., are summarized below:

 

		Millions of Cubic Feet of Natural Gas at December 31,
		U.S.				U.K.				Worldwide
Proved developed and undeveloped reserves —
January 1, 2008			248,433				—				248,433
Extensions and discoveries			146,189				—				146,189
Revisions of previous estimates			21,661				—				21,661
Production			(23,547	)			—				(23,547	)
End of year - December 31, 2008			392,736				—				392,736
Proved developed reserves at beginning of year			122,598				—				122,598
Proved developed reserves at end of year			216,229				—				216,229
Proved undeveloped reserves at beginning of year			125,835				—				125,835
Proved undeveloped reserves at end of year			176,507				—				176,507
January 1, 2009			392,736				—				392,736
Extensions and discoveries			196,400				—				196,400
Revisions of previous estimates			(42,867	)			—				(42,867	)
Sales of reserves in place			(3,195	)			—				(3,195	)
Production			(30,027	)			—				(30,027	)
End of year - December 31, 2009			513,047				—				513,047
Proved developed reserves at beginning of year			216,229				—				216,229
Proved developed reserves at end of year			292,695				—				292,695
Proved undeveloped reserves at beginning of year			176,507				—				176,507
Proved undeveloped reserves at end of year			220,352				—				220,352
January 1, 2010			513,047				—				513,047
Extensions and discoveries			240,347				4,684				245,031
Revisions of previous estimates			(54,132	)			—				(54,132	)
Production			(34,095	)			—				(34,095	)
End of year - December 31, 2010			665,167				4,684				669,851
Proved developed reserves at beginning of year			292,695				—				292,695
Proved developed reserves at end of year			358,543				—				358,543
Proved undeveloped reserves at beginning of year			220,352				—				220,352
Proved undeveloped reserves at end of year			306,624				4,684				311,308

 

F-32

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		Crude Oil, Condensate and Natural Gas Liquids at December 31,
		U.S.				U.K.				Worldwide
Proved developed and undeveloped reserves —
January 1, 2008			16,531				—				16,531
Extensions and discoveries			2,088				—				2,088
Revisions of previous estimates			36				—				36
Production			(347	)			—				(347	)
End of year - December 31, 2008			18,308				—				18,308
Proved developed reserves at beginning of year			6,536				—				6,536
Proved developed reserves at end of year			7,869				—				7,869
Proved undeveloped reserves at beginning of year			9,995				—				9,995
Proved undeveloped reserves at end of year			10,439				—				10,439
January 1, 2009			18,308				—				18,308
Extensions and discoveries			2,373				—				2,373
Revisions of previous estimates			(5,375	)			—				(5,375	)
Production			(503	)			—				(503	)
End of year - December 31, 2009			14,803				—				14,803
Proved developed reserves at beginning of year			7,869				—				7,869
Proved developed reserves at end of year			6,898				—				6,898
Proved undeveloped reserves at beginning of year			10,439				—				10,439
Proved undeveloped reserves at end of year			7,905				—				7,905
January 1, 2010			14,803				—				14,803
Extensions and discoveries			10,961				5,263				16,224
Revisions of previous estimates			(2,102	)			—				(2,102	)
Production			(452	)			—				(452	)
End of year - December 31, 2010			23,210				5,263				28,473
Proved developed reserves at beginning of year			6,898				—				6,898
Proved developed reserves at end of year			7,387				—				7,387
Proved undeveloped reserves at beginning of year			7,905				—				7,905
Proved undeveloped reserves at end of year			15,823				5,263				21,086

Natural gas extensions and discoveries are primarily attributable to the following:

 

2010		Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Barnett Shale and Eagle Ford Shale, as well as an increase in previously estimated proved undeveloped reserves based on operational performance; Additions of U.K. proved undeveloped reserves as a result of the approval of the Huntington Field Development Plan by the Company and its joint venture partners and the U.K. Department of Energy and Climate Change in November 2010.
2009		Additions to proved developed and undeveloped reserves as a result of drilling and additional offset locations in the Barnett Shale recognized under the oil and gas reserve estimation and disclosure requirements which the Company adopted effective December 31, 2009.
2008		Additions to proved developed and undeveloped reserves as a result of drilling in the Barnett Shale.

Natural gas revisions of previous estimates are primarily attributable to the following:

 

2010		Positive price revisions offset by negative quantity revisions due to a planned shift in future drilling priorities focusing more on drilling in the core of the Barnett Shale, which resulted in removing natural gas reserves previously classified as proved undeveloped in the Barnett Shale.
2009		Negative price revisions primarily in the Barnett Shale and Gulf Coast.
2008		Positive performance revisions primarily in the Barnett Shale.

 

F-33

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Crude oil, condensate and natural gas liquids and extensions and discoveries are primarily attributable to the following:

 

2010		Additions of U.S. proved developed and undeveloped reserves as a result of drilling and offset locations in the Eagle Ford Shale; Additions of U.K. proved undeveloped reserves as a result of the approval of the Huntington Field Development Plan by the Company and its joint venture partners and the U.K. Department of Energy and Climate Change in November 2010.

Crude oil, condensate and natural gas liquids revisions of previous estimates are primarily attributable to the following:

 

2009		The oil and gas reserve estimation and disclosure requirements, which the Company adopted effective December 31, 2009, resulted in the removal of 5.4 MMBls of crude oil reserves previously classified as proved undeveloped in the Camp Hill Field that were not associated with wells that were expected to be both drilled prior to December 31, 2014 and into which the Company then planned to inject steam prior to December 31, 2014.

Standardized Measure

The standardized measure of discounted future net cash flows relating to proved oil and gas reserves is as follows:

 

		Crude Oil, Condensate and Natural Gas Liquids at December 31,
		U.S.				U.K.				Worldwide
2010
Future cash inflows		$	3,514,978			$	432,231			$	3,947,209
Future production costs			(952,148	)			(96,782	)			(1,048,930	)
Future development costs			(597,444	)			(78,439	)			(675,883	)
Future income taxes			(415,021	)			(128,619	)			(543,639	)
Future net cash flows			1,550,365				128,391				1,678,756
Less 10% annual discount to reflect timing of cash flows			(895,681	)			(34,289	)			(929,970	)
Standard measure of discounted future net cash flows		$	654,684			$	94,102			$	748,786
2009
Future cash inflows		$	2,150,293			$	—			$	2,150,293
Future production costs			(943,774	)			—				(943,774	)
Future development costs			(297,023	)			—				(297,023	)
Future income taxes			(73,656	)			—				(73,656	)
Future net cash flows			835,840				—				835,840
Less 10% annual discount to reflect timing of cash flows			(453,747	)			—				(453,747	)
Standard measure of discounted future net cash flows		$	382,093			$	—			$	382,093
2008
Future cash inflows		$	2,501,460			$	—			$	2,501,460
Future production costs			(868,027	)			—				(868,027	)
Future development costs			(315,837	)			—				(315,837	)
Future income taxes			(223,828	)			—				(223,828	)
Future net cash flows			1,093,768				—				1,093,768
Less 10% annual discount to reflect timing of cash flows			(582,819	)			—				(582,819	)
Standard measure of discounted future net cash flows		$	510,949			$	—			$	510,949

Effective December 31, 2009, the Company adopted the new requirements for oil and gas reserve estimation and disclosure which require that reserve estimates and future cash flows be based on the average market prices for sales of oil and gas on the first calendar day of each month during the year. The average prices used for 2010 and 2009 under these rules were $74.39 and $56.10 per barrel, respectively, for crude oil and condensate, $35.18 and $23.18 per barrel, respectively, for natural gas liquids, and $3.50 and $3.30 per Mcf, respectively, for natural gas. Future cash inflows for 2008 were computed by applying year-end prices to year-end quantities of proved oil and gas reserves under the oil and gas reserve estimation and disclosure requirements in effect at that time. The price used in computing the December 31, 2008 reserve estimates and future cash flows was $40.12 per barrel for oil and condensate, $19.62 per barrel for natural gas liquids, and $4.99 per Mcf for natural gas.

 

F-34

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Future operating expenses and development costs are computed primarily by the Company’s petroleum engineers by estimating the expenditures to be incurred in developing and producing the Company’s proved oil and gas reserves at the end of the year, based on year end costs and assuming continuation of existing economic conditions. Future income taxes are based on year-end statutory rates, adjusted for the tax basis of oil and gas properties and available applicable tax assets. A discount factor of 10% was used to reflect the timing of future net cash flows. The standardized measure of discounted future net cash flows is not intended to represent the replacement cost or fair value of the Company’s oil and gas properties. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved, anticipated future changes in prices and costs, and a discount factor more representative of the time value of money and the risks inherent in oil and gas reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of discounted future net cash flows relating to proved oil and gas reserves are summarized below:

 

		Year Ended December 31,
		2010				2009				2008
Changes in Standardized Measure:
Standardized measure — beginning of year		$	382,093			$	510,949			$	662,370
Revisions to reserves proved in prior years:
Net change in sales prices and production costs related to future production			263,663				(254,511	)			(371,924	)
Net change in estimated future development costs			83				108,831				(80,780	)
Net change due to revisions in quantity estimates			(25,451	)			(71,840	)			44,643
Accretion of discount			39,833				59,589				83,931
Changes in production rates (timing) and other			49,806				(70,616	)			(67,218	)
Total revisions			327,934				(228,547	)			(391,348	)
Net change due to extensions and discoveries, net of estimated future development and production costs			351,831				76,419				228,037
Net change due to sales of minerals in place			—				748				—
Sales of oil and gas produced, net of production costs			(115,800	)			(80,997	)			(171,944	)
Previously estimated development costs incurred			43,940				34,816				91,832
Net change in income taxes			(241,212	)			68,705				92,002
Net change in standardized measure of discounted future net cash flows			366,693				(128,856	)			(151,421	)
Standardized measure — end of year		$	748,786			$	382,093			$	510,949

 

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15. SELECTED QUARTERLY FINANCIAL DATA AND RESTATEMENT OF PREVIOUSLY ISSUED INTERIM FINANCIAL STATEMENTS (UNAUDITED)

The following table presents summarized quarterly financial information for the years ended December 31, 2010 and 2009:

 

2010		First				Second				Restated Third				Fourth
		(In thousands, except per share amounts)
Revenues		$	39,424			$	33,191			$	30,812			$	36,035
Costs and expenses, net			(19,688	)			(31,406	)			(17,978	)			(60,440	)(1)
Net income (loss)		$	19,736			$	1,785			$	12,834			$	(24,405	)
Basic net income (loss) per share		$	0.64			$	0.05			$	0.37			$	(0.69	)
Diluted net income (loss) per share		$	0.63			$	0.05			$	0.37			$	(0.69	)
2009		First				Second				Restated Third				Fourth
		(In thousands, except per share amounts)
Revenues		$	31,203			$	26,171			$	23,847			$	32,858
Costs and expenses, net			(156,748	)(2)			(32,187	)			(28,642	)			(101,347	)(2)
Net loss		$	(125,545	)		$	(6,016	)		$	(4,795	)		$	(68,489	)
Basic net loss per share		$	(4.07	)		$	(0.19	)		$	(0.15	)		$	(2.20	)
Diluted net loss per share		$	(4.07	)		$	(0.19	)		$	(0.15	)		$	(2.20	)

 

(1)	The fourth quarter of 2010 includes a pre-tax loss on extinguishment of debt of $31.0 million.

(2)	The first and fourth quarters of 2009 include pre-tax impairments of oil and gas properties of $216.4 million and $122.5 million, respectively.

The sum of the individual quarterly basic and diluted income (loss) per share amounts may not agree with year-to-date basic and diluted income (loss) per share as each quarterly computation is based on the weighted average number of common shares outstanding during that period.

During the third quarter of 2010, the Company received cash distributions of $20.8 million on its B Unit investment in ACP II. The Company followed the cost method of accounting for the B Units and recognized cash distributions received with respect to the B Units as Distribution Income-Related Party in the consolidated statements of operations included in the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2010. However, the Company subsequently concluded that under the full cost method of accounting, the cash distributions should be considered proceeds from the sale of oil and gas properties and accordingly, should be recognized as a reduction of capitalized oil and gas property costs.

The effect of restating the Company’s financial statements for the three-month and nine-month periods ended September 30, 2010 to recognize the cash distributions received on the B Units as a reduction of capitalized oil and gas property costs rather than distribution income-related party and related income tax effects, resulted in a decrease in net income and total shareholders’ equity of $11.5 million from the previously reported amounts for the three months and nine months ended September 30, 2010 which represents a decrease in diluted income per common share of $0.32 and $0.34 from the previously reported amounts for the three-months and nine months ended September 30, 2010, respectively, with a corresponding decrease in proved oil and gas properties of $20.5 million and an increase in income tax assets and liabilities of $9.0 million from the previously reported amounts as of September 30, 2010. The restatement also resulted in a decrease in cash flows from operating activities and a corresponding increase in cash flows from investing activities of $20.8 million from the previously reported amounts for the nine months ended September 30, 2010.

The restatement did not affect the Company’s balance of cash and cash equivalents as of September 30, 2010 nor did it effect net income or loss for any of the Company’s previously issued financial statements for periods prior to the three-month period ended September 30, 2010. EBITDA, as defined in both the Company’s Prior Credit Facility and Revolving Credit Facility, includes cash distributions received on the Company’s B Unit investment in ACP II and, accordingly, the restatement had no and will have no impact on the Company’s compliance with the financial covenants under the terms of the Prior Credit Facility or Revolving Credit Facility and will have no impact on the Company’s ability to draw on the Revolving Credit Facility’s available borrowing base.

 

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The following tables report the full effect of the restatement on the Company’s consolidated balance sheet as of September 30, 2010, the consolidated statements of operations for the three-month and nine-month periods then ended and the consolidated statement of cash flows for the nine-month period then ended:

CONSOLIDATED BALANCE SHEET

 

		September 30, 2010 As Previously Reported				September 30,  2010 Restated
		(In thousands) (Unaudited)
ASSETS
PROPERTY AND EQUIPMENT, NET
Oil and gas properties using the full-cost method of accounting:
Proved oil and gas properties, net		$	502,506			$	481,988
TOTAL PROPERTY AND EQUIPMENT, NET			949,568				929,050
DEFERRED INCOME TAXES			49,441				60,370
TOTAL ASSETS		$	1,080,495			$	1,070,906
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Current state tax payable		$	1,989			$	2,311
Deferred income taxes			6,405				8,015
Total current liabilities			112,328				114,260
SHAREHOLDERS’ EQUITY:
Accumulated deficit			(138,672	)			(150,193	)
Total shareholders’ equity			375,356				363,835
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	1,080,495			$	1,070,906

 

F-37

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CONSOLIDATED STATEMENTS OF OPERATIONS

 

		For the Three Months Ended September 30, 2010								For the Nine Months  Ended September 30, 2010
		As Previously Reported				Restated				As Previously Reported				Restated
		(In thousands, except per share amounts) (Unaudited)
COSTS AND EXPENSES:
Depreciation, depletion and amortization		$	10,369			$	10,094			$	31,289			$	31,014
TOTAL COSTS AND EXPENSES			29,173				28,898				83,056				82,781
OPERATING INCOME			1,639				1,914				20,371				20,646
OTHER INCOME AND EXPENSES:
Distribution income - related party			20,793				—				20,793				—
INCOME BEFORE INCOME TAXES			39,156				18,638				73,689				53,171
INCOME TAX EXPENSE			(14,801	)			(5,804	)			(27,813	)			(18,816	)
NET INCOME		$	24,355			$	12,834			$	45,876			$	34,355
COMPREHENSIVE INCOME		$	24,339			$	12,818			$	45,860			$	34,339
BASIC INCOME PER COMMON SHARE		$	0.70			$	0.37			$	1.38			$	1.03
DILUTED INCOME PER COMMON SHARE		$	0.69			$	0.37			$	1.36			$	1.02

 

F-38

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CONSOLIDATED STATEMENT OF CASH FLOWS

 

		For the Nine Months  Ended September 30, 2010
		As Previously Reported				Restated
		(In thousands) (Unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income		$	45,876			$	34,355
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation, depletion and amortization			31,289				31,014
Deferred income taxes			25,716				16,719
Net cash provided by operating activities		$	99,632			$	78,839
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from the sale of oil and gas properties		$	15,042			$	35,835
Net cash used in investing activities		$	(229,258	)		$	(208,465	)

16. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

On October 28, 2010, the Company and certain of its wholly owned subsidiaries Bandelier Pipeline Holding, LLC, Carrizo (Marcellus) LLC, Carrizo (Marcellus) WV LLC, Carrizo Marcellus Holding Inc., CCBM, Inc., Chama Pipeline Holding LLC, CLLR, Inc, Hondo Pipeline, Inc. and Mescalero Pipeline, LLC (collectively, the “Subsidiary Guarantors”) entered into a Purchase Agreement (the “Purchase Agreement”) with Credit Suisse Securities (USA) LLC, Wells Fargo Securities, LLC and RBC Capital Markets Corporation (as predecessor in interest to RBC Capital Markets, LLC), as representatives of a group of initial purchasers (collectively, the “Initial Purchasers”), pursuant to which the Company agreed to sell $400 million aggregate principal amount of the Company’s 8.625% Senior Notes due 2018 (the “Senior Notes”). The Senior Notes were offered and sold in a transaction exempt from the registration requirements under the Securities Act of 1933, as amended (the “Securities Act”). The Senior Notes were resold in private placements to qualified institutional buyers in reliance on Rule 144A under the Securities Act and to non-U.S. persons in reliance on Regulation S. The offering closed on November 2, 2010.

In connection with the issuance and sale of the Senior Notes, on November 2, 2010, the Company and the Subsidiary Guarantors entered into a Registration Rights Agreement (the “Registration Rights Agreement”) with Credit Suisse Securities (USA) LLC, Wells Fargo Securities, LLC and RBC Capital Markets, LLC. The Registration Rights Agreement requires the Company and the Subsidiary Guarantors to file an exchange offer registration statement with the SEC with respect to an offer to exchange the Senior Notes for substantially identical notes that are registered under the Securities Act. Certain, but not all, of the Company’s wholly owned subsidiaries have issued full, unconditional and joint and several guarantees of the Senior Notes, will guarantee the exchange offer notes and may guarantee future issuances of debt securities.

The rules of the SEC require that condensed consolidating financial information be provided for a subsidiary that has guaranteed the debt of a registrant issued in a public offering, where the guarantee is full, unconditional and joint and several and where the voting interest of the subsidiary is 100% owned by the registrant. The Company is, therefore, presenting condensed consolidating financial information as of December 31, 2010 and 2009, and for each of the three years in the period ended December 31, 2010 on a parent company, combined guarantor subsidiaries, eliminating entries, and consolidated basis and should be read in conjunction with the consolidated financial statements. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiary guarantors operated as independent entities.

Investments in subsidiaries are accounted for by the respective parent company using the equity method for purposes of this presentation. Results of operations of subsidiaries are therefore reflected in the parent company’s investment accounts and earnings. The principal elimination entries set forth below eliminate investments in subsidiaries and intercompany balances and transactions. In condensed consolidating financial statements, the net income and equity of the parent company ordinarily is equal to the net income and equity of the consolidated entity. The Company’s oil and gas properties are accounted for using the full cost method of accounting whereby impairments and DD&A are calculated and recorded on a consolidated and country by country basis. However, when calculated separately on a legal entity basis, the combined totals of parent company and subsidiary impairments and DD&A can be more or less than the consolidated totals as a result of differences in the properties each entity owns including costs incurred, production rates, reserve mix, future development costs, etc. For example, for the year ended December 31, 2009 and 2008, on a consolidated basis, the Company recorded impairments of oil and gas properties totaling $338.9 million and $178.5 million respectively. For the year ended December 31, 2009 and 2008, on a parent company and subsidiary combined basis, the Company recorded impairments of oil and gas properties totaling $335.3 million and $172.3 million. Accordingly, elimination entries are also required to eliminate any differences between consolidated and parent company and subsidiary company combined impairments and DD&A.

 

F-39

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING BALANCE SHEETS

 

		December 31, 2010
		Parent Company				Combined Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
ASSETS
Current assets		$	1,029,000			$	22,733			$	(991,401	)		$	60,332
Property and equipment, net			194,243				784,790				4,024				983,057
Investments in subsidiaries			(139,829	)			—				139,829				—
Other assets			99,876				78,288				(77,419	)			100,745
Total assets		$	1,183,290			$	885,811			$	(924,967	)		$	1,144,134
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities		$	85,783			$	1,024,622			$	(991,401	)		$	119,004
Long-term liabilities			644,315				1,018				(76,839	)			568,494
Shareholders’ equity			453,192				(139,829	)			143,273				456,636
Total liabilities and shareholders’ equity		$	1,183,290			$	885,811			$	(924,967	)		$	1,144,134
		December 31, 2009
		Parent Company				Combined Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
ASSETS
Current assets		$	810,265			$	17,891			$	(792,756	)		$	35,400
Property and equipment, net			190,386				543,314				0				733,700
Investments in subsidiaries			(164,781	)			—				164,781				—
Other assets			22,956				91,746				(20,695	)			94,007
Total assets		$	858,826			$	652,951			$	(648,670	)		$	863,107
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities		$	58,684			$	816,800			$	(792,756	)		$	82,728
Long-term liabilities			553,404				932				(21,566	)			532,770
Shareholders’ equity			246,738				(164,781	)			165,652				247,609
Total liabilities and shareholders’ equity		$	858,826			$	652,951			$	(648,670	)		$	863,107

 

F-40

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS

 

		For the Year Ended December 31, 2010
		Parent Company				Combined Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
Revenues		$	34,548			$	104,914			$	—			$	139,462
Costs and expenses			66,451				55,809				(4,024	)			118,236
Operating income (loss)			(31,903	)			49,105				4,024				21,226
Other income and (expenses)			4,974				(10,521	)			—				(5,547	)
Income (loss) before income taxes			(26,929	)			38,584				4,024				15,679
Income tax (expense) benefit			9,264				(13,542	)			(1,451	)			(5,729	)
Equity in income (loss) of subsidiaries			25,042				—				(25,042	)			—
Net income (loss)		$	7,377			$	25,042			$	(22,469	)		$	9,950
		For the Year Ended December 31, 2009
		Parent Company				Combined Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
Revenues		$	39,628			$	74,451			$	—			$	114,079
Costs and expenses			114,588				337,722				754				453,064
Operating loss			(74,960	)			(263,271	)			(754	)			(338,985	)
Other income and (expenses)			29,207				(8,374	)			—				20,833
Loss before income taxes			(45,753	)			(271,645	)			(754	)			(318,152	)
Income tax benefit			15,815				96,357				1,135				113,307
Equity in income (loss) of subsidiaries			(175,288	)			—				175,288				—
Net loss		$	(205,226	)		$	(175,288	)		$	175,669			$	(204,845	)
		For the Year Ended December 31, 2008
		Parent Company				Combined Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
Revenues		$	94,409			$	122,268			$	—			$	216,677
Costs and expenses			193,696				111,873				(754	)			304,815
Operating income (loss)			(99,287	)			10,395				754				(88,138	)
Other income and (expenses)			24,825				(2,459	)			—				22,366
Income (loss) before income taxes			(74,462	)			7,936				754				(65,772	)
Income tax (expense) benefit			22,138				(1,149	)			(264	)			20,725
Equity in income (loss) of subsidiaries			6,787				—				(6,787	)			—
Net income (loss)		$	(45,537	)		$	6,787			$	(6,297	)		$	(45,047	)

 

F-41

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CARRIZO OIL & GAS, INC.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

 

		For the Year Ended December 31, 2010
		Parent Company				Combined Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
Net cash provided by operating activities		$	24,781			$	69,635			$	—			$	94,416
Net cash used in investing activities			(200,871	)			(268,069	)			198,644				(270,296	)
Net cash provided by financing activities			176,171				198,644				(198,644	)			176,171
Net increase in cash and cash equivalents			81				210				—				291
Cash and cash equivalents, beginning of year			1,337				2,500				—				3,837
Cash and cash equivalents, end of year		$	1,418			$	2,710			$	—			$	4,128
		For the Year Ended December 31, 2009
		Parent Company				Combined Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
Net cash provided by operating activities		$	75,919			$	57,453			$	—			$	133,372
Net cash used in investing activities			(102,753	)			(151,541	)			91,841				(162,453	)
Net cash provided by financing activities			27,734				91,841				(91,841	)			27,734
Net increase (decrease) in cash and cash equivalents			900				(2,247	)			—				(1,347	)
Cash and cash equivalents, beginning of year			437				4,747								5,184
Cash and cash equivalents, end of year		$	1,337			$	2,500			$	—			$	3,837
		For the Year Ended December 31, 2008
		Parent Company				Combined Guarantor Subsidiaries				Eliminations				Consolidated
		(In thousands)
Net cash provided by operating activities		$	59,762			$	88,992			$	—			$	148,754
Net cash used in investing activities			(471,098	)			(501,906	)			417,659				(555,345	)
Net cash provided by financing activities			403,749				417,659				(417,659	)			403,749
Net increase (decrease) in cash and cash equivalents			(7,587	)			4,745				—				(2,842	)
Cash and cash equivalents, beginning of year			8,024				2								8,026
Cash and cash equivalents, end of year		$	437			$	4,747			$	—			$	5,184

 

F-42