American Noble Gas (AMNI) 8-K Index to Consolidated Financial Statements

Exhibit 99.1

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	E-2
Consolidated Financial Statements:
Consolidated Balance Sheets	E-3
Consolidated Statements of Operations	E-4
Consolidated Statements of Changes in Stockholders’ Equity	E-5
Consolidated Statements of Cash Flows	E-6
Notes to Consolidated Financial Statements	E-8

E-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of
Infinity Energy Resources, Inc.
Denver, Colorado

     We have audited the accompanying consolidated balance sheets of Infinity Energy Resources, Inc. as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2005. We also have audited management’s assessment, included in the accompanying Managements’ Report on Internal Control over Financial Reporting included in Item 9A, that Infinity Energy Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established inInternal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Criteria”). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on these financial statements, an opinion on management’s assessment, and an opinion on the effectiveness of the Company’s internal control over financial reporting 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 perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audit of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

     A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

     Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

     In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Infinity Energy Resources, Inc. as of December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, management’s assessment that Infinity Energy Resources, Inc. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Criteria”). Furthermore, in our opinion, Infinity Energy Resources, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established inInternal Control-Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO Criteria”).

     As discussed in Note 1 to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 19 to the consolidated financial statements, the Company may not generate sufficient liquidity to meet its financial obligations which raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 19. The financial statements do not include adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result, should the Company be unable to continue as a going concern.

/s/ Ehrhardt Keefe Steiner & Hottman PC

March 3, 2006 (except Note 19, as to which the date is October 6, 2006)
Denver, Colorado

E-2

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	December 31,
	2005			2004
	(In thousands, except share and per share data)
ASSETS
Current assets:
Cash and cash equivalents	$	7,942		$	3,052
Accounts receivable, less allowance for doubtful accounts of $70 (2005) and $85 (2004)		4,748			3,494
Note receivable		—			1,581
Inventories		453			286
Prepaid expenses and other		422			654
Total current assets		13,565			9,067
Property and equipment, at cost, net of accumulated depreciation		11,489			8,764
Oil and gas properties, using full cost accounting, net of accumulated depreciation, depletion, amortization and ceiling write-down:
Proved		43,699			28,792
Unproved		22,849			15,595
Intangible assets, at cost, less accumulated amortization		2,514			1,497
Other assets, net		168			333
Total assets	$	94,284		$	64,048
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Note payable and current portion of long-term debt	$	288		$	284
Accounts payable		5,035			4,001
Accrued liabilities		6,314			4,497
Current portion of asset retirement obligations		284			—
Total current liabilities		11,921			8,782
Long-term liabilities:
Production taxes payable		401			469
Asset retirement obligations, less current portion		1,129			635
Accrued interest		905			—
Derivative liabilities		9,837			—
Long-term debt, less current portion		39,874			11,330
Subordinated convertible notes payable		—			14,010
Total liabilities		64,067			35,226
Commitments and contingencies (Note 10)
Stockholders’ equity:
Preferred stock, par value $.0001, authorized 10,000,000 shares, issued and outstanding - -0- (2005) and -0- (2004) shares		—			—
Common stock, par value $.0001, authorized 75,000,000 shares, issued and outstanding 13,501,988 (2005) and 10,628,196 (2004) shares		1			1
Additional paid-in-capital		58,335			43,363
Accumulated deficit		(28,119	)		(14,542	)
Total stockholders’ equity		30,217			28,822
Total liabilities and stockholders’ equity	$	94,284		$	64,048

See Notes to Consolidated Financial Statements.

E-3

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	For the Years Ended December 31,
	2005			2004			2003
	(In thousands, except per share data)
Revenue:
Oilfield service operations	$	21,583		$	14,721		$	11,634
Exploration and production		9,192			6,267			6,589
Total revenue		30,775			20,988			18,223
Cost of revenue:
Oilfield service operations		10,769			7,890			6,222
Oil and gas production expenses		3,548			1,914			2,162
Oil and gas production taxes		877			722			759
Total cost of revenue		15,194			10,526			9,143
Gross profit		15,581			10,462			9,080
General and administrative expenses		5,836			5,462			5,311
Depreciation, depletion, amortization and accretion		7,451			5,198			3,074
Ceiling write-down of oil and gas properties		13,450			4,100			2,975
		26,737			14,760			11,360
Operating loss		(11,156	)		(4,298	)		(2,280	)
Other income (expense):
Financing costs:
Interest expense		(2,486	)		(1,232	)		(1,594	)
Amortization of loan discount and costs		(1,066	)		(1,741	)		(6,146	)
Early extinguishment of debt		(1,276	)		(356	)		(55	)
Change in derivative fair value		2,908			—			—
Gain (loss) on sales of other assets		(96	)		2,824			20
Other		(405	)		170			130
Total other expense		(2,421	)		(335	)		(7,645	)
Net loss before income taxes		(13,577	)		(4,633	)		(9,925	)
Income taxes		—			—			—
Net loss	$	(13,577	)	$	(4,633	)	$	(9,925	)
Basic and diluted net loss per share	$	(1.05	)	$	(0.49	)	$	(1.23	)
Weighted average shares outstanding (basic and diluted)		12,936			9,495			8,048

See Notes to Consolidated Financial Statements.

E-4

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
For the years ended December 31, 2005, 2004 and 2003

								(Accumulated						Accumulated
					Additional			Deficit)			Total			Other
	Common Stock				Paid-In			Retained			Comprehensive			Comprehensive			Stockholders’
	Shares		Amount		Capital			Earnings			Loss			Income (Loss)			Equity
	(In thousands, except share data)
Balance, December 31, 2002		7,558,462	$	1	$	22,871		$	16					$	(77	)	$	22,811
Issuance of common stock upon the exercise of options and warrants		146,169		—		824			—						—			824
Conversion of subordinated convertible notes and accrued interest into common stock		499,401		—		3,236			—						—			3,236
Options and warrants granted in connection with amendments and agreements related to bridge loans		—		—		5,790			—						—			5,790
Comprehensive loss:
Net loss		—		—		—			(9,925	)	$	(9,925	)		—			(9,925	)
Change in fair value of fixed price delivery contract, net of tax benefit		—		—		—			—			257			257			257
Reclassifications, net of income tax expense		—		—		—			—			(82	)		(82	)		(82	)
Comprehensive loss											$	(9,750	)
Balance, December 31, 2003		8,204,032		1		32,721			(9,909	)					98			22,911
Issuance of common stock in private equity placement, net of financings costs		2,027,000		—		8,918			—						—			8,918
Issuance of common stock to partially repay related party debt		125,000		—		500			—						—			500
Issuance of common stock upon the exercise of options and warrants		146,300		—		428			—						—			428
Conversion of subordinated convertible notes and accrued interest into common stock		125,864		—		796			—						—			796
Comprehensive loss:
Net loss		—		—		—			(4,633	)		(4,633	)		—			(4,633	)
Reclassifications, net of income tax expense		—		—		—			—			(98	)		(98	)		(98	)
Comprehensive loss											$	(4,731	)
Balance, December 31, 2004		10,628,196		1		43,363			(14,542	)					—			28,822
Reclassification of non-employee warrants to derivative liabilities		—		—		(6,090	)		—						—			(6,090	)
Reclassification of non-employee warrants from derivative liabilities in connection with exercise		—		—		2,174			—						—			2,174
Issuance of common stock upon the exercise of options and warrants		857,556		—		4,707			—						—			4,707
Conversion of subordinated convertible notes and accrued interest into common stock		2,016,236		—		14,181			—						—			14,181
Comprehensive loss:
Net loss		—		—		—			(13,577	)		(13,577	)		—			(13,577	)
Comprehensive loss											$	(13,577	)
Balance, December 31, 2005		13,501,988	$	1	$	58,335		$	(28,119	)				$	—		$	30,217

See Notes to Consolidated Financial Statements.

E-5

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Years Ended December 31,
	2005			2004			2003
	(In thousands)
Cash flows from operating activities:
Net loss	$	(13,577	)	$	(4,633	)	$	(9,925	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion, amortization, accretion and ceiling write-down		20,901			9,298			6,049
Amortization of loan discount and costs		1,066			1,741			6,146
Non-cash early extinguishment of loan cost		1,052			356			55
Change in fair value of derivative liabilities		(2,908	)		—			—
Impairment of note receivable and other		530			—			—
(Gain) loss on sales of other assets		96			(2,824	)		(20	)
Unrealized loss on commodity derivative instruments		28			—			—
Change in operating assets and liabilities
Increase in accounts receivable		(1,273	)		(1,687	)		(252	)
(Increase) decrease in inventories		(167	)		65			(11	)
(Increase) decrease in prepaid expenses and other		232			(89	)		(12	)
Increase in accounts payable		1,034			1,526			33
Increase in accrued liabilities		2,636			1,710			782
Net cash provided by operating activities		9,650			5,463			2,845
Cash flows from investing activities:
Capital expenditures — exploration and production		(39,271	)		(11,714	)		(6,274	)
Capital expenditures — oilfield services		(4,190	)		(1,149	)		(460	)
Acquisitions — exploration and production		(330	)		(516	)		—
Acquisitions — oilfield services, net of cash acquired		—			(1,189	)		—
Proceeds from sale of fixed assets — exploration and production		133			156			—
Proceeds from sale of fixed assets — oilfield services		31			4,654			105
Increase in other assets		(31	)		(200	)		(288	)
Proceeds from note receivable		1,204			16			15
Net cash used in investing activities		(42,454	)		(9,942	)		(6,902	)
Cash flows from financing activities:
Proceeds from notes payable		434			295			—
Proceeds from borrowings on long-term debt		45,000			5,845			11,453
Proceeds from issuance of common stock		4,707			9,666			824
Debt and equity issuance costs		(2,751	)		(320	)		—
Repayment of notes payable		(406	)		(664	)		—
Repayment of long-term debt		(9,290	)		(8,018	)		(8,360	)
Net cash provided by financing activities		37,694			6,804			3,917
Net increase (decrease) in cash and cash equivalents		4,890			2,325			(140	)
Cash and cash equivalents, beginning of period		3,052			727			867
Cash and cash equivalents, end of period	$	7,942		$	3,052		$	727

See Notes to Consolidated Financial Statements.

E-6

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)

	For the Years Ended December 31,
	2005		2004		2003
	(In thousands)
Supplemental cash flow disclosures:
Cash paid for interest, net of amounts capitalized	$	1,175	$	436	$	1,590
Non-cash transactions:
Non-cash costs capitalized in the full cost pool for oil and gas properties		764		1,070		2,715
Property and equipment acquired through capital lease or assumption of debt		189		195		968
Oil and gas properties acquired through seller financed debt		—		—		263
Options and warrants granted in connection with debt, recorded as loan costs or debt discount		8,828		120		5,791
Conversion of subordinated convertible notes and accrued interest to common stock		14,181		796		3,236
Issuance of common stock to partially repay related party debt		—		500		—
Issuance of additional notes in lieu of cash interest payment on 7% subordinated convertible notes		—		795		379

See Notes to Consolidated Financial Statements.

E-7

INFINITY ENERGY RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Summary of Significant Accounting Policies

Nature of Operations

     Effective September 9, 2005, Infinity, Inc. merged with and into its wholly-owned subsidiary Infinity Energy Resources, Inc., a Delaware corporation, for the purpose of changing its domicile from Colorado to Delaware. As a result of the merger, the legal domicile of Infinity, Inc. was changed to Delaware and its name was changed to Infinity Energy Resources, Inc. At the effective time of the merger, shares of Infinity, Inc. were converted into an equal number of shares of common stock of Infinity Energy Resources, Inc.

     Infinity Energy Resources, Inc. and its subsidiaries (collectively, “Infinity” or the “Company”) are engaged in the acquisition, exploration, development and production of natural gas and crude oil in the United States and the acquisition and exploration of oil and gas properties in Nicaragua. In addition, the Company provides oilfield services in the Mid-Continent region and in northeast Wyoming.

Basis of Presentation

     The consolidated financial statements include the accounts of Infinity Energy Resources, Inc. and its wholly-owned subsidiaries, which include Consolidated Oil Well Services, Inc., Infinity Oil & Gas of Wyoming, Inc., Infinity Oil and Gas of Texas, Inc., Infinity Oil & Gas of Kansas, Inc. and CIS — Oklahoma, Inc. All significant intercompany balances and transactions have been eliminated in consolidation.

Reclassifications

     Certain prior period amounts in the accompanying consolidated financial statements have been reclassified to conform to the current year presentation.

Management Estimates

     The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates with regard to the consolidated financial statements include the estimated carrying value of unproved properties, the estimate of proved oil and gas reserve volumes and the related present value of estimated future net cash flows and the ceiling test applied to capitalized oil and gas properties, the estimated cost and timing related to asset retirement obligations, the estimated fair value of derivative liabilities and the realizability of deferred tax assets.

Cash and Cash Equivalents

     For purposes of reporting cash flows, cash and cash equivalents consist of cash on hand and demand deposits with financial institutions. At times, the Company maintains deposits in financial institutions in excess of federally insured limits. Management monitors the soundness of the financial institutions and believes the Company’s risk is negligible. The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents.

E-8

Accounts Receivable

     The Company’s revenue producing activities are conducted primarily in Colorado, Kansas, Oklahoma, Texas and Wyoming. The Company grants credit to qualified customers, which potentially subjects the Company to credit risk resulting from, among other factors, adverse changes in the industries in which the Company operates and the financial condition of its customers. The Company continuously monitors collections and payments from its customers and maintains an allowance for doubtful accounts based upon historical experience and any specific customer collection issues identified.

Inventories

     Inventories, consisting primarily of cement mix, sand, fuel and chemicals, are stated at the lower of cost or market. Cost has been determined on the first-in, first-out method.

Derivative Instruments

     The Company accounts for derivative instruments or hedging activities under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 133,Accounting for Derivative Instruments and Hedging Activities.SFAS No. 133 requires the Company to record derivative instruments at their fair value. If the derivative is designated as a fair value hedge, the changes in the fair value of the derivative and of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of changes in the fair value of the derivative are recorded in other comprehensive income (loss) and are recognized in the statement of operations when the hedged item affects earnings. Ineffective portions of changes in the fair value of cash flow hedges, if any, are recognized in earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized in earnings.

     The Company periodically hedges a portion of its oil and gas production through swap and collar agreements. The purpose of the hedges is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk.

     The Company’s Senior Secured Notes (see Note 6) include certain terms, conditions and features that are separately accounted for as embedded derivatives at estimated fair value. In addition, the related warrants issued with the Senior Secured Notes and non-employee options and warrants are also separately accounted for as freestanding derivatives at estimated fair value. The determination of fair value includes significant estimates by management including the term of the instruments, volatility of the price of the Company’s common stock, interest rates and the probability of conversion, redemption or exercise, among other items. The fluctuations in estimated fair value may be significant from period to period, which, in turn, may have a significant impact on the Company’s reported financial condition and results of operations. See Note 7.

Property and Equipment

     Depreciation and amortization are computed using the straight-line method over the following estimated useful lives:

Assets	Useful Lives
Buildings	30 years
Site improvements	15 years
Machinery, equipment and vehicles	3-20 years
Office furniture and equipment	3-10 years

Long-Lived Assets

     Long-lived assets to be held and used in the Company’s business are reviewed for impairment whenever events or changes in circumstances indicate that the related carrying amount may not be recoverable. When the carrying amounts of long-lived assets exceed the fair value, which is generally based on discounted expected future cash flows, the Company records an impairment. No impairments were recorded during the years ended December 31, 2005, 2004 or 2003.

E-9

Oil and Gas Properties

     The Company follows the full cost method of accounting for exploration and development activities. Accordingly, all costs incurred in the acquisition, exploration, and development of properties (including costs of surrendered and abandoned leaseholds, delay lease rentals and dry holes) and the fair value of estimated future costs of site restoration, dismantlement, and abandonment activities are capitalized. Overhead related to exploration and development activities is also capitalized. The Company capitalized $884,000, $652,000 and $49,000 of internal costs during the years ended December 31, 2005, 2004 and 2003, respectively. Costs associated with production and general corporate activities are expensed in the period incurred.

     Pursuant to full cost accounting rules, the Company must perform a “ceiling test” each quarter. The ceiling test provides that capitalized costs less related accumulated depletion and deferred income taxes for each cost center may not exceed the sum of (1) the present value of future net revenue from estimated production of proved oil and gas reserves using current costs and prices, including the effects of derivative instruments accounted for as cash flow hedges but excluding the future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, and a discount factor of 10%; plus (2) the cost of properties not being amortized, if any; plus (3) the lower of cost or estimated fair value of unproved properties included in the costs being amortized, if any; less (4) income tax effects related to differences in the book and tax basis of oil and gas properties.

     At December 31, 2005, the carrying amount of oil and gas properties subject to amortization exceeded the full cost ceiling limitation by approximately $13,450,000 based upon an average natural gas price of $8.21 per Mcf and an average oil price of $60.74 per barrel in effect at that date. In 2004 and 2003, the Company also recorded ceiling writedowns of $4,100,000 and $2,975,000, respectively.

     Depletion of proved oil and gas properties is computed on the units-of-production method, with oil and gas being converted to a common unit of measure based on their relative energy content, whereby capitalized costs, as adjusted for future development costs and asset retirement obligations, are amortized over the total estimated proved reserve quantities. The costs of wells in progress and unevaluated properties, including any related capitalized interest, are not amortized. On a quarterly basis, such costs are evaluated for inclusion in the costs to be amortized resulting from the determination of proved reserves, impairments, or reductions in value. To the extent that the evaluation indicates these properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized. Abandonments of unproved properties are accounted for as an adjustment to capitalized costs related to proved oil and gas properties, with no losses recognized. See Note 17 for additional discussion of unevaluated properties.

     Proceeds from the sales of oil and gas properties are accounted for as adjustments to capitalized costs with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas, in which case the gain or loss is recognized in income. Expenditures for maintenance and repairs are charged to oil and gas production expense in the period incurred.

Asset Retirement Obligations

     The Company records estimated future asset retirement obligations pursuant to the provisions of SFAS No. 143,Accounting for Asset Retirement Obligations.SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which the obligation is incurred with a corresponding increase in the carrying amount of the related long-lived asset. Subsequent to initial measurement, the asset retirement obligation is required to be accreted each period to present value. The Company’s asset retirement obligations consist of costs related to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties. Capitalized costs are depleted as a component of the full cost pool using the units of

E-10

production method. The following table summarizes the activity for the Company’s asset retirement obligations for the years ended December 31, 2005, 2004 and 2003:

	2005			2004		2003
	(In thousands)
Asset retirement obligations at January 1	$	635		$	521	$	448
Accretion expense		70			21		17
Liabilities incurred		51			93		56
Liabilities assumed		17			—		—
Liabilities settled		(199	)		—		—
Revision in estimates		839			—		—
Asset retirement obligations at December 31		1,413			635		521
Less: current portion of asset retirement obligations		(284	)		—		—
Asset retirement obligations at December 31, less current portion	$	1,129		$	635	$	521

Capitalized Interest

     The Company capitalizes interest costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring these projects to their intended use. Interest costs capitalized in 2005, 2004 and 2003 were $1,451,000, $635,000 and $382,000, respectively.

Intangible Assets

     Intangible assets consist principally of loan costs and goodwill. Loan costs are amortized over the terms of the related debt instruments using the effective interest method. Goodwill is not amortized, but is reviewed for impairment at least annually. As of December 31, 2005, goodwill was not impaired.

     The Company capitalizes amortization of loan costs to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Amortization of loan costs is capitalized only for the period that activities are in progress to bring these projects to their intended use. Total loan cost amortization capitalized for 2005, 2004 and 2003 was $261,000, $555,000 and $2,715,000, respectively.

Revenue Recognition

     The Company accounts for natural gas sales using the sales method. Under this method, revenue is recognized based on actual volumes sold by the Company, which may be more or less than the Company’s share of pro-rata production from certain wells. Natural gas imbalances at December 31, 2005 and 2004 were immaterial. The Company recognizes sales of oil when title to the product is transferred. The Company recognizes revenue from oilfield services when the services are provided and collection is reasonably assured.

Transportation Costs

     The Company accounts for transportation costs under Emerging Issues Task Force Issue 00-10,Accounting for Shipping and Handling Fees and Costs, whereby amounts paid for transportation are classified as operating expenses.

Per Share Information

     Basic earnings per share is computed by dividing net earnings from continuing operations by the weighted average number of shares of common stock outstanding during each period, excluding treasury shares. Diluted earnings per share is computed by adjusting the average number of shares of common stock outstanding for the dilutive effect, if any, of common stock equivalents such as stock options, warrants and convertible debt.

E-11

Stock Options

     The Company applies Accounting Principles Board (“APB”) Opinion No. 25,Accounting for Stock Issued to Employees, and related interpretations in accounting for its stock option plans. Accordingly, no compensation cost has been recognized for options granted to employees under the stock option plans because the fair value of the stock equaled or was less than the option exercise price at the date of grant. Had compensation costs for employee stock options been determined based upon the fair value at the grant date consistent with the methodology prescribed under SFAS No. 123,Accounting for Stock-Based Compensation, the Company’s net loss and loss per share would have been as follows (see Note 8):

	For the Years Ended December 31
	2005			2004			2003
	(In thousands,
	except per share amounts)
Net loss as reported	$	(13,577	)	$	(4,633	)	$	(9,925	)
Deduct: Total stock-based employee compensation expense, determined under fair value based method for all awards, net of tax		(3,177	)		(1,703	)		(26	)
Pro forma net loss	$	(16,754	)	$	(6,336	)	$	(9,951	)
Basic and diluted loss per share as — reported	$	(1.05	)	$	(0.49	)	$	(1.23	)
Basic and diluted loss per share — pro forma	$	(1.30	)	$	(0.67	)	$	(1.23	)

     For options granted during the years ended December 31, 2005, 2004 and 2003, the estimated fair value of the options granted utilizing the Black-Scholes pricing model under the Company’s plan was based on weighted average risk-free interest rates of 4.15%, 1.5% and 1.5%, respectively, expected option life of 10 years for 2005 and 2004 and 5 years for 2003, expected volatility of approximately 67%, 147% and 131%, respectively, and no expected dividends.

Income Taxes

     The Company uses the asset and liability method of accounting for income taxes. This method requires the recognition of deferred tax liabilities and assets for the expected future tax consequences of temporary differences between financial accounting bases and tax bases of assets and liabilities. The tax benefits of tax loss carryforwards and other deferred taxes are recorded as an asset to the extent that management assesses the utilization of such assets to be more likely than not. When the future utilization of some portion of the deferred tax asset is determined not to be more likely than not, a valuation allowance is provided to reduce the recorded deferred tax asset. As of December 31, 2005 and 2004, the Company had recorded a full valuation allowance for its net deferred tax asset.

Comprehensive Income (Loss)

     The Company has elected to report comprehensive income (loss) in the consolidated statement of stockholders’ equity. Comprehensive income (loss) is composed of net income (loss) and all changes to stockholders’ equity, except those due to investments by stockholders, changes in additional paid-in capital and distributions to stockholders.

Recently Issued Accounting Pronouncements

     In December 2004, the FASB issued SFAS No. 123(R),Share-Based Payment, which is a revision of SFAS No. 123,Accounting for Stock-Based Compensation.SFAS No. 123(R) supersedes APB Opinion No. 25,Accounting for Stock Issued to Employees, and amends SFAS No. 95,Statement of Cash Flows.SFAS No. 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values. The pro forma disclosures, previously permitted under SFAS No. 123 will no longer be an alternative to financial statement recognition. SFAS No. 123(R) also requires the tax benefits in excess of recognized compensation expenses to be reported as a financing cash flow, rather than as an operating cash flow as required under current literature. This requirement may serve to reduce the Company’s future cash provided by operating activities and increase future cash provided by financing activities, to the extent of associated tax benefits that may be realized in the future.

E-12

     SFAS No. 123(R) must be adopted no later than January 1, 2006 and permits public companies to adopt its requirements using one of two methods:

• A “modified prospective” method in which compensation cost is recognized beginning with the effective date based on the requirements of SFAS No. 123(R) for all share-based payments granted after the adoption date and based on the requirements of SFAS No. 123 for all awards granted to employees prior to the effective date of SFAS No. 123(R) that remain unvested on the adoption date.

• A “modified retrospective” method which includes the requirements of the modified prospective method described above, but also permits entities to restate either all prior periods presented or prior interim periods of the year of adoption based on the amounts previously recognized under SFAS No. 123 for purposes of pro forma disclosures.

     The Company adopted the provisions of SFAS No. 123(R) on January 1, 2006 using the modified prospective method. The adoption of SFAS No. 123(R) had no impact on the Company’s results of operations because all employee stock options outstanding at December 31, 2005 were fully vested. As permitted by SFAS No. 123, through December 31, 2005 the Company accounted for share-based payments to employees using the intrinsic value method prescribed by APB Opinion No. 25 and related interpretations. As such, the Company generally did not recognize compensation expense associated with employee stock option grants. Had the Company adopted SFAS No. 123(R) in prior periods, the impact would have approximated the impact of SFAS No. 123 as described in the pro forma disclosures above underStock Options.

     In March 2005, the FASB issued FASB Interpretation (“FIN”) 47,Accounting for Conditional Asset Retirement Obligations — an interpretation of FASB Statement No. 143.FIN 47 clarifies that conditional asset retirement obligations meet the definition of liabilities and should be recognized when incurred if their fair values can be reasonably estimated. The Company adopted the provisions of FIN 47 effective December 31, 2005. The adoption of FIN 47 had no impact on the Company’s financial position or results of operations.

     In February 2006, the FASB issued SFAS No. 155,Accounting for Certain Hybrid Financial Instruments — an amendment of FASB Statements No. 133 and 140.SFAS No. 155 resolves issues addressed in SFAS No. 133 Implementation Issue No. D1,Application of Statement 133 to Beneficial Interests in Securitized Financial Assets.SFAS No. 155 will become effective for the Company’s fiscal year after September 15, 2006. The impact of SFAS No. 155 will depend on the nature and extent of any new derivative instruments entered into after the effective date.

Note 2 — Accounts Receivable

     Accounts receivable consists of the following:

	December 31,
	2005			2004
	(In thousands)
Accounts receivable oil field services	$	2,771		$	2,740
Revenue receivable oil and gas production		2,004			722
Other receivables		43			117
Total receivables		4,818			3,579
Less allowance for doubtful accounts		(70	)		(85	)
Net receivables	$	4,748		$	3,494

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Note 3 — Property and Equipment

     Property and equipment consists of the following:

	December 31,
	2005			2004
	(In thousands)
Buildings, site costs and improvements	$	1,601		$	777
Machinery, equipment, vehicles and aircraft		16,610			13,569
Office furniture and equipment		548			467
Total cost		18,759			14,813
Less accumulated depreciation		(7,270	)		(6,049	)
Net property and equipment	$	11,489		$	8,764

     Depreciation expense related to property and equipment for the years ended December 31, 2005, 2004 and 2003 was $1,468,000, $1,617,000 and $1,580,000, respectively.

Note 4 — Intangible Assets

     Intangible assets consist of the following:

	December 31,
	2005			2004
	(In thousands)
Loan costs	$	2,889		$	4,032
Goodwill		225			225
Other		20			56
		3,134			4,313
Less accumulated amortization		(620	)		(2,816	)
Net intangible assets	$	2,514		$	1,497

     During the years ended December 31, 2005, 2004 and 2003, the Company recorded amortization related to intangible assets of $1,735,000, $2,100,000 and $6,211,000, respectively.

Note 5 — Accrued Liabilities

     Accrued liabilities consist of the following:

	December 31,
	2005		2004
	(In thousands)
Production taxes payable — current portion	$	516	$	236
Oil and gas revenue payable to oil and gas property owners		680		131
Accrued interest		247		223
Accrued drilling costs		2,918		2,650
Other accrued liabilities		1,953		1,257
	$	6,314	$	4,497

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Note 6 — Debt

     Debt consists of the following:

	December 31,
	2005			2004
	(In thousands)
Senior Secured Notes, net of discount of $7,417 at December 31, 2005	$	37,583		$	—
Promissory note to seller (for a 50% interest in an aircraft), with interest at 7.0% due quarterly. Annual principal payments equal to 5% of the current outstanding principal due each February until paid in full. The note was settled in February 2006 in connection with the sale of the related aircraft. See Note 16		2,203			2,326
8% Subordinated Convertible Notes		—			2,493
7% Subordinated Convertible Notes		—			11,517
$25 million Development Credit Facility		—			5,000
Various revolving credit and term loans		—			3,582
Other		376			706
		40,162			25,624
Less current portion		(288	)		(284	)
Long-term debt	$	39,874		$	25,340

     Maturities of debt are as follows:

Year Ending December 31,	(In thousands)
2006	$	288
2007		88
2008		—
2009		37,583
2010		—
Thereafter		2,203
	$	40,162

Senior Secured Notes Facility

     On January 13, 2005, the Company entered into a securities purchase agreement (the “Senior Secured Notes Facility”) with affiliates of Promethean Asset Management, LLC and Angelo, Gordon & Co., L.P. (collectively, the “Buyers”), pursuant to which Infinity sold, and the Buyers purchased, $30 million aggregate principal amount of senior secured notes (the “Initial Notes”) due January 13, 2009 and five-year warrants to purchase 924,194 shares of the Company’s common stock at an exercise price of $9.09 per share and 732,046 shares of the Company’s common stock at an exercise price of $11.06 per share (collectively, the “Initial Warrants”). The Initial Notes have an initial maturity of 48 months subject to extension for an additional twelve months upon the mutual agreement of Infinity and the Buyers. Pursuant to the terms of the Senior Secured Notes Facility, on September 7, 2005 and December 9, 2005, the Company sold, and the Buyers purchased, $9.5 million and $5.5 million, respectively, of additional principal amount of senior secured notes (the “Additional Notes” and together with the Initial Notes, the “Notes”) due March 7, 2009 and June 9, 2009, respectively, and five-year warrants to purchase 283,051 shares, 224,202 shares, 191,882 shares and 151,988 shares of the Company’s common stock at exercise prices of $9.40 per share, $11.44 per share, $8.03 per share and $9.77 per share, respectively (collectively, the “Additional Warrants” and together with the Initial Warrants, the “Warrants”). The Additional Notes have initial maturities of 42 months (54 months if the maturity of the Initial Notes is extended). The Notes bear interest at the 3-month LIBOR (London Interbank Offered Rate) plus 675 basis points, adjusted the first business day of each calendar quarter (11.23% at December 31, 2005).

     The Notes are secured by essentially all of the assets of Infinity and its subsidiaries and are guaranteed by each of Infinity’s active subsidiaries. The Notes are redeemable by Infinity for cash at any time during the first year at 105% of par value, declining by 1% per year thereafter (101% during any extended maturity period), together with any accrued and unpaid interest. Under certain circumstances, Infinity has the option to repay the Notes with direct issuances of shares of registered common stock in lieu of cash at a conversion rate equal to 95% of the weighted average trading price of shares of the Company’s common stock on the trading day preceding the conversion (the “Conversion Option”). See Note 16.

E-15

     Under certain circumstances at quarterly intervals and over a three year period, Infinity has the option to sell additional Notes, along with additional Warrants, in amounts up to $15 million in any rolling twelve-month period, up to an additional $30 million. The additional Notes would have an initial maturity of 42 months (54 months if the maturity of the Initial Notes is extended). The issuance of additional Notes is subject to Infinity’s satisfaction of various closing conditions. The ability to issue additional Notes or the requirement to prepay Notes prior to maturity will depend upon a maximum Notes balance calculated quarterly based generally upon a combination of financial performance of Consolidated and the SEC after-tax PV-10% value of the Company’s proved reserves. The maximum Notes balance at December 31, 2005 exceeded the Notes outstanding on that date. The Notes include terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers, and acquisitions.

     Under the provisions of SFAS No. 133 and EITF 00-19,Accounting for Derivative Financial Instruments Index to, and Potentially Settled in, a Company’s Own Stock, the Conversion Option and the Warrants qualify as derivatives. As a result, effective with the issuance of each series of Notes, the Company bifurcated the Conversion Option from the Notes and accounted for it and the Warrants as derivatives (see Note 7). The initial fair values of the Conversion Option and the Warrants, which aggregated $388,000 and $8,440,000, respectively, for all three series of Notes issued in 2005, were recorded as debt discount. The debt discount is being amortized over the initial maturities of the Notes utilizing the effective interest method.

Promissory Note to Seller

     In connection with the 2003 acquisition of a 50% interest in an aircraft, the Company entered into a promissory note in favor of the seller. As of December 31, 2005, the interest rate on the promissory note was 7.0% with interest payable quarterly. The note and accrued interest were settled in full in February 2006 in connection with the sale of the aircraft (see Note 16). Since the promissory note was settled with the proceeds from the sale of a non-current asset, the full balance of the promissory note has been classified as long-term.

8% Convertible Subordinated Notes

     Effective June 13, 2001, the Company sold $6,475,000 in 8% Subordinated Convertible Notes in a private placement. Interest on the notes accrued at a rate of 8% per annum. The notes were convertible into one share of common stock at $5 per share and were scheduled to mature on June 13, 2006. The Company incurred costs of $502,000 associated with the placement, which were capitalized as loan costs. The Company also issued warrants to purchase 220,000 shares of common stock at $5.90 per share. The Company capitalized additional loan costs of $925,000 related to the fair value of the warrants.

     On January 13, 2005, the Company called for redemption all of the remaining 8% Subordinated Convertible Notes outstanding on February 28, 2005. The holders of all $2,493,000 of 8% Subordinated Convertible Notes outstanding at December 31, 2004 converted the debt and accrued interest into 517,296 shares of the Company’s common stock. The remaining unamortized loan costs of $156,000 were expensed as early extinguishment of debt. During 2004 and 2003, the holders of $300,000 and $1,450,000, respectively, of 8% Subordinated Convertible Notes converted the debt and accrued interest into 63,197 shares and 295,689 shares, respectively, of the Company’s common stock.

7% Convertible Subordinated Notes

     Effective April 22, 2002, the Company sold $12,540,000 in 7% Subordinated Convertible Notes in a private placement. Interest on the notes accrued at a rate of 7% per annum. The notes were convertible to one share of common stock at $8.625 per share and were scheduled to mature on April 22, 2007. The Company incurred costs of $866,000 associated with the placement, which were capitalized as loan costs. The Company also issued warrants to purchase 200,000 shares of common stock at $9.058 per share. The Company capitalized additional loan costs of $1,386,000 related to the fair value of the warrants.

     On February 25, 2005, the Company called for redemption all of the remaining 7% Subordinated Convertible Notes outstanding on April 22, 2005 at a redemption price of 102.8% plus accrued and unpaid interest. Holders of $11,479,000 of 7% Subordinated Convertible Notes outstanding at December 31, 2004 converted the debt and accrued interest into 1,498,940 shares of the Company’s common stock, and the remaining balance of $38,000 plus accrued interest was paid in full on April 22, 2005. The unamortized loan costs of $753,000 were expensed as early extinguishment of debt. During 2004 and 2003, the holders of $462,000 and $1,735,000,

E-16

respectively, of 7% Subordinated Convertible Notes converted the debt and accrued interest into 62,685 shares and 203,712 shares, respectively, of the Company’s common stock.

$25 Million Development Credit Facility

     In September 2003, the Company established a secured revolving credit facility with a bank. Interest on the amounts outstanding accrued at prime rate plus 1.0%. The Company incurred $110,000 in loan costs and approximately $57,000 in legal costs to establish the facility. These costs were capitalized as loan costs. The facility was repaid in full with proceeds from the Senior Secured Notes Facility discussed above and terminated on January 13, 2005.

Revolving Credit and Term Loans

     Effective July 9, 2004, Consolidated borrowed $5,400,000 under an amended credit facility with a bank. Amounts outstanding accrued interest at the prime rate plus 1.25% per annum. The credit facility was repaid in full with proceeds from the Senior Secured Notes Facility discussed above and terminated on January 13, 2005.

Debt Discount

     As discussed above, in connection with the issuance of the Notes the Company recorded debt discount of $8,828,000, which is being amortized over the initial maturities of the Notes utilizing the effective interest method. The Company capitalizes amortization of debt discount to oil and gas properties on expenditures made in connection with exploration and development projects that are not subject to current depletion. Amortization of debt discount is capitalized only for the period that activities are in progress to bring these projects to their intended use. Total debt discount amortized during 2005 was $647,000, net of $764,000 capitalized to oil and gas properties. There was no debt discount amortization capitalized for 2004 and 2003.

Note 7 — Derivative Instruments

Commodity Derivatives

     The Company periodically hedges a portion of its oil and gas production through fixed-price physical contracts and commodity derivative contracts. The purpose of the hedges is to provide a measure of stability to the Company’s cash flows in an environment of volatile oil and gas prices and to manage the exposure to commodity price risk. As of December 31, 2005 the Company had the following oil collar derivative arrangements outstanding:

Term of Arrangements	Bbls per Day		Floor Price		Ceiling Price
January 1, 2006 — June 30, 2006		50	$	50.00	$	64.40
October 1, 2005 — December 31, 2006		50	$	52.50	$	74.00

     All of the Company’s collar arrangements have been designated as cash flow hedges. As of December 31, 2005, the Company had a derivative liability of approximately $28,000, which is included in Accrued liabilities on the accompanying Consolidated Balance Sheet. During the year ended December 31, 2005, the Company recognized ineffectiveness of approximately $28,000 under its collar arrangements, which is reflected in Other expense in the accompanying Consolidated Statements of Operations. No amounts were received or paid by the Company during 2005 under its collar arrangements. During 2004 and 2003, the Company reclassified from other comprehensive income to natural gas revenue, gains of approximately $155,000 and $133,000, respectively, related to certain fixed-price delivery contracts that had been designated as cash flow hedges.

     Subsequent to December 31, 2005, the Company entered into the following oil collar:

Term of Arrangement	Bbls per Day		Floor Price		Ceiling Price
January 1, 2007 — June 30, 2007		50	$	57.50	$	77.50

E-17

Other Derivatives

     As more fully discussed in Note 6 above, in January, September and December 2005, the Company issued Notes and Warrants. Under the provisions of SFAS No. 133 and EITF 00-19 the Company bifurcated the Conversion Option associated with the Notes and accounted for it and the Warrants as derivatives. The initial fair values of the Conversion Option and the Warrants, which aggregated $388,000 and $8,440,000, respectively, for all three series of Notes issued in 2005, were recorded as debt discount. Subsequent changes in the fair value of those derivatives have been recorded as Changes in derivative fair value in the accompanying Consolidated Statements of Operations. During 2005, the Company recognized Changes in derivative fair value of $34,000 and $1,885,000 related to the decrease in the fair value of the Conversion Option and Warrants, respectively. The terms of the Notes and Warrants contain other embedded derivatives that management determined to have de minimus value.

     As a result of the issuance of the Initial Notes in January 2005, under the provisions of EITF 00-19, the Company was no longer able to conclude that it has sufficient authorized and unissued shares available to settle its previously issued non-employee options and warrants (the “Non-employee Options and Warrants”) (see Note 8) after considering the commitment to potentially issue common stock under terms of the Notes if ever there is an event of default. As such, effective with the issuance of the Initial Notes on January 13, 2005, the Company reclassified the fair value of the Non-employee Options and Warrants out of stockholders’ equity on the accompanying Consolidated Balance Sheet and recognized them as a derivative liability of $6,090,000. Changes in the fair value of the Non-employee Options and Warrants will be recorded as Change in derivative fair value in the accompanying Consolidated Statements of Operations so long as they continue to not qualify for equity classification. Non-employee Options and Warrants that are ultimately settled in common stock will be remeasured prior to settlement and then reclassified back to stockholders’ equity; however, any gains or losses previously recognized on those instruments will remain in earnings. During 2005, in connection with the exercise of 538,850 Non-employee Options and Warrants, the Company reclassified $2,174,000 back to stockholders’ equity. During 2005, the Company recognized Changes in derivative fair value of $989,000 related to the decrease in the fair value of these instruments.

Note 8 — Stockholders’ Equity

Private Institutional Equity Placements

     In January 2004, the Company issued 1,000,000 shares of common stock in exchange for $4,000,000. In November 2004, the Company issued 1,027,000 shares of common stock in exchange for $5,237,700. Costs associated with the issuances totaled $320,000.

Non-Employee Warrants and Options

     In connection with the issuance of the Notes during 2005, the Company issued five-year warrants to purchase an aggregate of 2,507,363 shares of the Company’s common stock at a weighted average price of $9.87 per share. Through December 31, 2005, none of these warrants have been exercised.

     In connection with the issuance of bridge notes in 2003, the Company issued warrants to purchase an aggregate of 1,163,500 shares of the Company’s common stock at $8.75 per share, with expiration dates ranging from January 23, 2008 through June 27, 2008. The warrant agreement for 250,000 of the warrants issued contains anti-dilution provisions that require the Company to adjust the exercise price and the number of warrants outstanding if the Company sells stock at less than the exercise price. As a result of the private institutional placements of equity discussed above in January and November 2004, the exercise price of the warrants was adjusted to $7.88 per share and the number of shares to be acquired under the warrants was increased by 27,746. The associated value of approximately $120,000 was recorded as offering costs.

E-18

     The following table summarizes non-employee option and warrant activity for the years ended December 31, 2005, 2004 and 2003:

						Weighted Average
				Weighted Average		Grant Date Fair
	Number of Shares			Price Per Share		Value Per Share
Outstanding, January 1, 2003		1,030,000		$	7.66	$
Granted		1,163,500			8.75		4.98
Exercised		(83,350	)		7.34
Outstanding, December 31, 2003		2,110,150			8.27
Granted		47,746			8.24		4.80
Outstanding, December 31, 2004		2,157,896			8.17
Granted		2,507,363			9.87		3.38
Exercised		(546,850	)		6.97
Outstanding, December 31, 2005		4,118,409			9.36

     The following table summarizes information about non-employee warrants and options outstanding at December 31, 2005:

	Number
	Outstanding and
	Exercisable at		Weighted Average
	December 31,		Remaining	Weighted Average
Range of Exercise Prices	2005		Contractual Life	Exercise Price
$7.34 – 8.03		558,428	3.1 years	$	7.85
$8.75 – 9.77		2,603,733	3.2 years	$	9.02
$11.06 – 11.44		956,248	4.2 years	$	11.15
		4,118,409

Options Under Employee Option Plans

     In 2005, the Company’s stockholders approved the 2005 Equity Incentive Plan (the “2005 Plan”), under which both incentive and non-statutory stock options may be granted to employees, officers, non-employee directors and consultants. An aggregate of 475,000 shares of the Company’s common stock are reserved for issuance under the 2005 Plan. Options granted under the 2005 Plan allow for the purchase of common stock at prices not less than the fair market value of such stock at the date of grant, become exercisable immediately or as directed by the Company’s Board of Directors and generally expire ten years after the date of grant. The Company also has other equity incentive plans with terms similar to the 2005 Plan.

     The Company granted 530,000, 403,750 and 10,000 options to employees under the plans during the years ended December 31, 2005, 2004 and 2003, respectively. At December 31, 2005, there were 140,881 shares available for grant under the plans, of which 140,000 are available under the 2005 Plan.

     The following table summarizes stock option activity for the years ended December 31, 2005, 2004 and 2003:

						Weighted Average
				Weighted Average		Grant Date Fair
	Number of Shares			Price Per Share		Value Per Share
Outstanding, January 1, 2003		1,140,900		$	5.23	$
Granted		10,000			8.75		5.25
Canceled or forfeited		(61,781	)		7.28
Exercised		(62,819	)		3.38
Outstanding, December 31, 2003		1,026,300			5.25
Granted		403,750			4.26		4.22
Canceled or forfeited		(118,500	)		7.22
Exercised		(146,300	)		2.92
Outstanding, December 31, 2004		1,165,250			5.00
Granted		530,000			7.83		6.00
Exercised		(312,000	)		3.07
Outstanding, December 31, 2005		1,383,250			6.52

E-19

     The following table summarizes information about stock options outstanding at December 31, 2005:

	Number					Number
	Outstanding at		Weighted Average			Exercisable at
Range of	December 31,		Remaining	Weighted Average		December 31,		Weighted Average
Exercise Prices	2005		Contractual Life	Exercise Price		2005		Exercise Price
$4.26 – 5.00		620,250	2.2 years	$	4.58		620,250	$	4.58
$7.51 – 7.80		365,000	9.6 years	$	7.53		365,000	$	7.53
$8.50 – 8.70		398,000	5.2 years	$	8.62		398,000	$	8.62
		1,383,250					1,383,250

Note 9 — Income Taxes

     The provision for income taxes consists of the following:

	For the Years Ended December 31,
	2005			2004			2003
	(In thousands)
Current income tax expense	$	—		$	—		$	—
Deferred income tax benefit		(5,464	)		(1,784	)		(4,003	)
Change in valuation allowance and other		5,464			1,784			4,003
Total income tax benefit	$	—		$	—		$	—

     The effective income tax rate varies from the statutory federal income tax rate as follows:

	For the Years Ended December 31,
	2005			2004			2003
	(In thousands)
Federal income tax rate		(34.0	)%		(34.0	)%		(34.0	)%
State income tax rate		(4.5	)		(6.0	)		(6.0	)
Tax benefit of derivatives settled with equity		1.9			—			—
Other temporary and permanent differences		(3.6	)		—			—
Change in valuation allowance and other		40.2			40.0			40.0
Effective tax rate		—	%		—	%		—	%

     The significant temporary differences and carry-forwards and their related deferred tax asset (liability) and deferred tax asset valuation allowance balances are as follows:

	December 31,
	2005			2004
	(In thousands)
Deferred tax assets
Accruals and other	$	214		$	132
Net operating loss carry-forward		13,635			10,387
Gross deferred tax assets		13,849			10,519
Deferred tax liabilities
Property and equipment		1,185			4,694
Derivative liabilities		1,375			—
Gross deferred tax liabilities		2,560			4,694
Net deferred tax asset		11,289			5,825
Less valuation allowance		(11,289	)		(5,825	)
Deferred tax asset	$	—		$	—

     For income tax purposes, the Company has net operating loss carry-forwards of approximately $35,416,000, which expire from 2015 through 2025. The Company has provided for a valuation allowance of $11,289,000 due to the uncertainty of realizing the tax benefits from its net deferred tax asset.

E-20

     During the years ended December 31, 2005, 2004 and 2003, the Company realized certain tax benefits related to stock option plans in the amounts of $505,000, $172,000 and $164,000, respectively. Such benefits were recorded as a deferred tax asset as they increased the Company’s net operating losses and an increase in additional paid in capital. The recognition of the valuation allowance offset the impact of this benefit.

Note 10 — Commitments and Contingencies

Gas Gathering Contracts

     In June 2001, the Company entered into a long-term gas gathering contract, which expires in December 2008, for natural gas production from the Company’s field in Sweetwater County, Wyoming. Under the contract, as amended on April 4, 2003, the Company pays gas gathering fees per thousand cubic feet (“Mcf”) delivered. The Company is obligated to pay a fee of $.40 per Mcf on the first 7,500,000 Mcf and $.25 per Mcf thereafter. Additionally, the Company had annual volume commitments for five years starting September 1, 2001. If the Company exceeded the minimum in any year, the excess reduced the following year’s commitment. If the Company did not meet the minimum in any year, the shortfall was added to the following years. Through December 31, 2005, the Company had delivered approximately 4,000,000 Mcf. While the Company has failed to deliver the volumes required under the contract, the pipeline operator has also not provided the compression and gathering capabilities it was required to provide under the contract. Management has received a verbal commitment from the operator that the volume commitments will be adjusted and management does not believe there will be a contract shortfall under the renegotiated volumes and therefore, anticipates no additional costs under the contract.

     In June 2005, the Company entered into a long-term gas gathering contract for natural gas production from the Company’s properties in Erath County, Texas, under which the Company pays a gathering fee of $0.35 per Mcf gathered. The contract contains minimum delivery volume commitments through June 30, 2015 associated with firm transportation rights. The Company may, at its discretion and with notice, reduce the minimum daily delivery volumes by up to 50%. Based on production volumes through December 31, 2005, the Company has accrued a liability of approximately $248,000 as a delivery commitment shortfall under the contract.

Fixed Price Delivery Contracts

     During 2004, the Company entered into a fixed price delivery contract for the period from April 1, 2004 through March 31, 2006 for 2,000 MMbtu per day of natural gas from certain of the Company’s Wyoming properties. The fixed price for the period April 1, 2004 through March 31, 2005 was $4.40 per MMBtu and the fixed price for the period April 1, 2005 through March 31, 2006 is $4.15 per MMBtu. Sales under this fixed price contract are accounted for as normal sales agreements under the exemption in SFAS No. 133.

Lease Agreements

     The Company leases office space under an operating lease with a lease term through September 2007. Future minimum lease payments under the non-cancelable operating lease are as follows at December 31, 2005:

Year Ending December 31,	Operating Lease
	(In thousands)
2006	$	97
2007		69
Total minimum lease payments	$	166

     Rental expense for the years ended December 31, 2005, 2004 and 2003 was $153,000, $133,524 and $142,926, respectively.

Regulations

     The Company’s oil and gas operations are subject to various Federal, state and local laws and regulations. The Company could incur significant expense to comply with new or existing laws and non-compliance could have a material adverse effect on the Company’s operations.

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Environmental

     The Company uses injection wells to dispose of water into underground rock formations. If future wells produce water of lesser quality than allowed under state laws or if water is produced at rates greater than can be injected, the Company could incur additional costs to dispose of its water.

Note 11 — Retirement Plan

     The Company has a 401(k) plan covering substantially all of its employees. Effective January 1, 2004, the Company began matching, dollar for dollar, employee contributions up to 4% of gross pay. The Company recognized expense of $152,000 and $112,000 related to such contributions during the years ended December 31, 2005 and 2004, respectively. There were no Company contributions made to the plan during 2003.

Note 12 — Industry Segments

     Segment information has been prepared in accordance with SFAS No. 131,Disclosures about Segments of an Enterprise and Related Information, which requires disclosure of information related to certain operating segments of the Company. The Company has two reportable segments: (i) oil and gas production and (ii) oil field services. The Company’s oil and gas production segment is engaged in the acquisition, exploration, development and production of natural gas and crude oil in Colorado, Texas and Wyoming. The Company’s oil field services segment provides pressure-pumping services associated with the drilling and completion of oil and gas wells, including cementing, acidizing, fracturing, and water hauling and has operations principally in Kansas, Oklahoma, and Wyoming.

     The segment data presented below was prepared on the same basis as the consolidated financial statements:

	Oil Field		Oil & Gas			Corporate and
	Services		Production			Other			Total
	(In thousands)
Revenue
For the year ended December 31, 2005	$	21,583	$	9,192		$	—		$	30,775
For the year ended December 31, 2004		14,721		6,267			—			20,988
For the year ended December 31, 2003		11,634		6,589			—			18,223
Depreciation, depletion, amortization and accretion
For the year ended December 31, 2005		1,268		6,033			150			7,451
For the year ended December 31, 2004		1,450		3,611			137			5,198
For the year ended December 31, 2003		1,421		1,561			92			3,074
Ceiling write-down
For the year ended December 31, 2005		—		13,450			—			13,450
For the year ended December 31, 2004		—		4,100			—			4,100
For the year ended December 31, 2003		—		2,975			—			2,975
Operating income (loss)
For the year ended December 31, 2005		6,712		(14,870	)		(2,998	)		(11,156	)
For the year ended December 31, 2004		2,669		(4,823	)		(2,144	)		(4,298	)
For the year ended December 31, 2003		1,411		(1,630	)		(2,061	)		(2,280	)
Total assets
As of December 31, 2005		14,552		68,299			11,433			94,284
As of December 31, 2004		10,972		48,001			5,075			64,048
As of December 31, 2003		9,069		40,220			5,977			55,266
Capital expenditures
For the year ended December 31, 2005		4,190		39,590			11			43,791
For the year ended December 31, 2004		2,247		15,652			53			17,952
For the year ended December 31, 2003		460		6,076			198			6,734

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Note 13 — Significant Customers

     During 2005, oil field services provided to one unrelated third party represented 10% of total revenue. In addition, during 2005, oil and gas sales to one unrelated customer represented 10% of total revenue.

     During 2004, oil field services provided to one unrelated third party represented 10% of total revenue. In addition, during 2004, oil and gas sales to one unrelated customer represented 26% of total revenue.

     During 2003, oil and gas sales to two unrelated third parties represented 27% and 12% of total revenue.

Note 14 — Fair Value of Financial Instruments

     The carrying values of the Company’s cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities represent the fair value due to the short-term nature of the accounts. Long-term debt at December 31, 2005, with a carrying value of approximately $40.2 million, is estimated to have a fair value between $44 million and $45 million. See Note 6 for the terms of the long-term debt obligations.

     The fair value of the Company’s non-current derivative liabilities, all of which relate to the Conversion Option, Warrants and Non-employee Options and Warrants, is estimated using various models and assumptions related to the term of the instruments, estimated volatility of the price of the Company’s common stock, interest rates and the probability of conversion, redemption or exercise, among other items.

Note 15 — Earnings Per Share

     For the years ended December 31, 2005, 2004 and 2003, all of the Company’s common stock equivalents were anti-dilutive. Therefore, the impact of 5,501,659, 5,320,892 and 4,991,746 common stock equivalents outstanding as of December 31, 2005, 2004 and 2003, respectively, were not included in the calculation of diluted loss per share because their effect was anti-dilutive. The number of common stock equivalents excluded from the diluted loss per share calculations does not include any shares that may be issued in the future should the Company elect to repay Notes outstanding under the Senior Secured Notes Facility with direct issuances of shares of registered common stock in lieu of cash. See Note 16.

Note 16 — Subsequent Events

Conversion of Accrued Interest and Senior Secured Notes

     In accordance with terms of the Senior Secured Notes Facility, in January 2006, the Company elected to settle approximately $861,000 of interest accrued at December 31, 2005 (due January 3, 2006) through the issuance of 126,084 shares of common stock. Since the interest was settled with other than current assets, the accrued interest at December 31, 2005 has been classified as long-term. In addition, also in accordance with terms of the Senior Secured Notes Facility, in 2006, through March 3, 2006, the Company converted $3 million principal amount of Notes, along with accrued interest of $37,000, into 382,062 shares of common stock.

Sale of Aircraft

     In February 2006, the Company sold its 50% interest in an aircraft for net proceeds of approximately $2.3 million and recognized a gain of approximately $292,000. In conjunction with the sale of the aircraft, the Company settled the related promissory note and accrued interest.

Note 17 — Supplemental Oil and Gas Information

Estimated Proved Oil and Gas Reserves (Unaudited)

     Proved oil and gas reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and

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operating conditions. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities of proved oil and gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities of oil and gas that are ultimately recovered.

     All of the Company’s proved reserves are located in the United States. The following information about the Company’s proved and proved developed oil and gas reserves was developed from reserve reports prepared by independent reserve engineers:

	Natural Gas			Crude Oil
	(Mcf)			(Barrels)
Proved reserves as of December 31, 2002		95,790,200			182,700
Revisions of previous estimates		(90,374,776	)		1,991
Extension, discoveries and other additions		3,175,927			66,102
Production		(1,080,456	)		(57,654	)
Proved reserves as of December 31, 2003		7,510,895			193,139
Purchases of reserves in place		1,476,067			—
Revisions of previous estimates		(1,230,288	)		16,535
Extension, discoveries and other additions		1,239,700			17,571
Production		(953,428	)		(33,668	)
Proved reserves as of December 31, 2004		8,042,946			193,577
Purchases of reserves in place		—			140,591
Revisions of previous estimates		(2,887,783	)		550,832
Extension, discoveries and other additions		6,819,586			20,262
Production		(875,543	)		(68,497	)
Proved reserves as of December 31, 2005		11,099,206			836,765
Proved Developed Reserves as of:
December 31, 2003		4,724,523			124,968
December 31, 2004		3,773,033			117,031
December 31, 2005		5,031,235			712,094

     The 2003 revisions to the previous estimates of reserves is due primarily to the following factors:

• operational issues at the existing Labarge wells;

• a lack of financial resources to rectify the operational issues on a timely basis or to complete exploration on other wells; and

• geological studies that indicate the producing Pipeline wells were producing from the sands rather than the coals thus leading the Company to change the classification of Pipeline from a coal play to a sand play.

Costs Incurred in Oil and Gas Activities

     Costs incurred in connection with the Company’s oil and gas acquisition, exploration and development activities are shown below.

	For the Years Ended December 31
	2005		2004		2003
	(In thousands)
Property acquisition costs
Proved	$	330	$	516	$	1,099
Unproved		5,745		3,625		661
Total property acquisition costs		6,075		4,141		1,760
Development costs		17,099		6,156		3,168
Exploration costs		17,583		5,294		3,492
Asset retirement costs		907		93		503
Total costs	$	41,664	$	15,684	$	8,923

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Aggregate Capitalized Costs

     Aggregate capitalized costs relating to the Company’s oil and gas producing activities, and related accumulated depreciation, depletion, amortization and ceiling write-down are as follows:

	December 31,
	2005			2004
	(In thousands)
Proved oil and gas properties	$	75,484		$	41,210
Unproved oil and gas properties		22,849			15,595
Total		98,333			56,805
Less accumulated depreciation, depletion, amortization and ceiling write-down		(31,785	)		(12,418	)
Net capitalized costs	$	66,548		$	44,387

Costs Not Being Amortized

     Oil and gas property costs not being amortized at December 31, 2005, by year that the costs were incurred are as follows:

Year Ended December 31,	(In thousands)
2005	$	12,879
2004		2,601
2003		1,745
Prior		5,624
Total costs not being amortized	$	22,849

     Unevaluated costs include $5,897,000 relating to the Company’s Labarge prospect in southwest Wyoming. Substantially all of the acreage in the prospect is subject to an ongoing Bureau of Land Management environmental impact statement (“EIS”). The EIS must be completed before the Company can continue development. Unevaluated costs include approximately $1,160,000 relating to the Company’s concessions offshore Nicaragua. The Company expects to execute a definitive exploration and production contract covering the approximate 1,400,000 acres during 2006. The Company anticipates that the majority of all the unproved costs in the table above will be classified as proved costs within the next five years.

Oil and Gas Operations

     Aggregate results of operations in connection with the Company’s oil producing activities are shown below:

	For the Years Ended December 31
	2005			2004			2003
	(In thousands)
Revenue	$	9,192		$	6,268		$	6,589
Production costs and taxes		(4,425	)		(2,636	)		(2,920	)
Depreciation, depletion, amortization and accretion		(6,033	)		(3,578	)		(1,467	)
Ceiling write-down		(13,450	)		(4,100	)		(2,975	)
Results of operations from producing activities (excluding corporate overhead and interest costs)	$	(14,716	)	$	(4,046	)	$	(773	)
Depletion per Mcf equivalent	$	4.60		$	3.06		$	0.92

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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)

     Future oil and gas sales and production and development costs have been estimated using prices and costs in effect at the end of the years indicated, except in those instances where the sale of oil and natural gas is covered by contracts, as required by SFAS No. 69,Disclosures about Oil and Gas Producing Activities.SFAS No. 69 requires that net cash flow amounts be discounted at 10%. This information does not represent the fair market value of the Company’s proved oil and gas reserves.

	For the Years Ended December 31
	2005			2004			2003
	(In thousands)
Future cash inflows	$	141,982		$	56,585		$	51,592
Future production costs		(49,010	)		(18,552	)		(16,205	)
Future development costs		(16,785	)		(3,450	)		(2,913	)
Future income tax expense		(656	)		(400	)		(2,765	)
Future net cash flows		75,531			34,183			29,709
10% annual discount for estimated timing on cash flows		(32,014	)		(10,471	)		(8,887	)
Standardized measure of discounted future cash flows	$	43,517		$	23,712		$	20,822

     The following table presents the average year-end spot market gas price and oil price used to compute future cash inflows for each period:

	For the Years Ended December 31
	2005		2004		2003
Weighted average gas price per Mcf	$	8.21	$	6.07	$	6.06
Weighted average oil price per barrel	$	60.74	$	40.25	$	31.34

     Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the Company’s proved oil and gas reserves at December 31, 2005, 2004 and 2003 assuming continuation of existing economic conditions.

     The following reconciles the change in the standardized measure of discounted future net cash flow:

	For the Years Ended December 31
	2005			2004			2003
Beginning of period	$	23,712		$	20,822		$	55,053
Extensions, discoveries and other additions		12,328			2,912			9,004
Purchases of reserves in place		442			2,840			—
Net change in sales and transfer prices, net of production costs		(1,305	)		(4,118	)		76,823
Revision of previous quantity estimates		12,809			241			(170,455	)
Development costs incurred during the period		1,525			5,023			976
Sales of oil and gas, net of production costs and taxes		(4,767	)		(3,632	)		(3,679	)
Changes in future development costs		402			(3,026	)		13,144
Net change in income taxes		(156	)		1,817			26,834
Changes in production rates and other		(3,875	)		(1,462	)		4,719
Accretion of discount		2,402			2,295			8,403
End of period	$	43,517		$	23,712		$	20,822

     Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to the Company’s proved oil and gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Company’s proved oil and gas reserves.

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Note 18 — Quarterly Consolidated Financial Information (Unaudited)

     The following table provides selected quarterly consolidated financial results for the years ended December 31, 2005 and 2004.

	Quarter
	First			Second			Third		Fourth
	(In thousands, except per share amounts)
2005
Total revenue	$	5,515		$	7,651		$	8,805	$	8,804
Gross profit	$	2,903		$	3,924		$	4,439	$	4,315
Net income (loss)	$	(9,463	)	$	4,356		$	646	$	(9,116	)
Earnings (loss) per share	$	(0.81	)	$	0.33		$	0.05	$	(0.68	)
Earnings (loss) per diluted share	$	(0.81	)	$	0.31		$	0.00	$	(0.68	)
2004
Total revenue	$	3,567		$	5,045		$	6,606	$	5,770
Gross profit	$	1,628		$	2,518		$	3,542	$	2,774
Net (loss) income	$	(1,765	)	$	(1,102	)	$	3,121	$	(4,887	)
(Loss) earning per share	$	(0.19	)	$	(0.12	)	$	0.33	$	(0.49	)
(Loss) earning per diluted share	$	(0.19	)	$	(0.12	)	$	0.29	$	(0.49	)

     The Company recorded full cost ceiling writedowns during the fourth quarters of 2005 and 2004, of $13,450,000 and $4,100,000, respectively.

     The Company restated net income (loss), earnings (loss) per share and earnings (loss) per diluted share for the first, second and third quarters of 2005 to correct the accounting for certain derivatives embedded in or resulting from the issuance of the Company’s senior secured notes in 2005.

Note 19 — Going Concern

     As of June 30, 2006, the Company was in violation of certain of the covenants under its Senior Secured Notes Facility, including the maximum trade payable balance covenant. As a result, on August 9, 2006 the Company and the Note holders entered into a waiver and amendment to the Senior Secured Notes Facility and the Notes that waived the violations at June 30, 2006 and provided for the following terms:

Ø	repayment or conversion of $2.5 million principal amount of Notes by September 15, 2006 (a total of $2,547,000 of principal and interest was converted into 614,500 shares of common stock by September 15, 2006);
Ø	repayment or conversion of $2.0 million principal amount of Notes (plus prepayment premiums and accrued interest) per month for nine of the next ten months commencing October 2, 2006;
Ø	repayment in cash of $9.0 million principal amount of Notes (plus prepayment premiums and accrued interest) on each of January 15, 2007, April 15, 2007 and July 15, 2007;
Ø	re-pricing of the exercise price of the outstanding Warrants from a weighted-average exercise price of $9.81 per share to $5.00 per share and increasing the number of Warrants from approximately 3.0 million to approximately 5.8 million;
Ø	removal of the Company’s ability to sell additional notes or warrants under the Senior Secured Notes Facility.

     The Company was unable to comply with the terms of the amended Notes. As such, effective on October 2, 2006, the Notes were further amended to provide for the following terms:

Ø	increase in the outstanding principal Notes balance by 20%, or $9 million, plus an additional $1.4 million equal to the interest that would have been due on October 2, 2006, to arrive at a new principal Notes balance of $55.4 million;
Ø	a final maturity date for all remaining Notes, less the aggregate balance of any converted Notes (see below), plus accrued interest but with no prepayment premium, due in cash on January 15, 2007;
Ø	deferral of the January 2, 2007 interest payment to the final maturity of the Notes on January 15, 2007;
Ø	limitation on aggregate trade payable in excess of 90 days beyond invoice due date not to exceed $7.5 million and a requirement to reduce trade payables to a maximum not exceeding $6.0 million by January 1, 2007 or at any time thereafter;

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Ø	removal of the mandatory prepayment or conversion of $2.0 million of principal on the first business day of each month beginning October 2, 2006, as set forth in the August waiver;
Ø	conversion prior to January 15, 2007, at the election of the Note holders (unless the Notes are repaid prior in full by the Company) in the following amounts:

• up to approximately $3.4 million plus accrued interest commencing October 3, 2006 (includes the October interest on all of the Notes)

• up to an additional $2.0 million plus accrued interest commencing November 1, 2006

• up to an additional $2.0 million plus accrued interest commencing December 1, 2006

     If the Company is unable to maintain compliance with the terms of the amended Notes, the Note holders could declare a triggering event, which would entitle the Note holders to a 20% premium on the increased principal balance of the outstanding Notes, accelerate the due date of the Notes, and increase the interest rate on the Notes.

     The Company has engaged a financial advisor to assist in the Company’s efforts to secure new debt financing, the proceeds from which would be used to repay all or a portion of the outstanding Notes. In addition, the Company has engaged a separate financial advisor to assist in the evaluation of strategic alternatives, which may include the sale of all or part of the Company’s: (i) approximately 162,000 net developed and undeveloped acres in Texas, Colorado and Wyoming; (ii) oilfield services subsidiary, Consolidated; or (iii) 1.4 million-acre prospect in two concessions in the Caribbean Sea offshore Nicaragua. If the Company were to sell a portion of its assets, including Consolidated, proceeds from such a sale would be used to repay all or a portion of the outstanding Notes. There can be no assurances that the Company will be able secure new debt financing on acceptable terms or that the Company will be able to close on a sale of any assets for sufficient proceeds by January 15, 2007. Due to the uncertainties related to these matters, there exists substantial doubt about the Company’s ability to continue as a going concern. The financial statements do not include any adjustments relating to the recoverability and classification of asset carrying amounts or the amount and classification of liabilities that might result should the Company be unable to continue as a going concern.

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