Newfield Exploration (NFX) 8-K/A Financial Statements and Exhibits

EXHIBIT 99.2

Inland Resources Inc.

Consolidated Financial Statements
As of June 30, 2004
(Unaudited)

INLAND RESOURCES INC.

INDEX TO INTERIM FINANCIAL STATEMENTS — Unaudited

	PAGE
Consolidated Balance Sheet– June 30, 2004		2
Consolidated Income Statements– For the six months ended June 30, 2004 and 2003		3
Consolidated Statement of Stockholders’ Equity– For the six months ended June 30, 2004		4
Consolidated Statements of Cash Flows– For the six months ended June 30, 2004 and 2003		5
Notes to the Consolidated Financial Statements–Unaudited		6

INLAND RESOURCES INC.

CONSOLIDATED BALANCE SHEET
(In thousands except for share amounts)
Unaudited

	June 30,
	2004
ASSETS
Current Assets:
Cash and cash equivalents	$	4,357
Accounts receivable and accrued sales		8,924
Inventory		1,656
Other current assets		777
Total current assets		15,714
Property and Equipment, at cost:
Oil and gas properties (successful efforts method)		297,156
Accumulated depletion, depreciation and amortization		(71,174	)
		225,982
Other property and equipment, net		9,957
Total property and equipment, net		235,939
Other long-term assets, net		3,117
Total assets	$	254,770
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	8,614
Accrued expenses		6,772
Fair market value of derivative instruments		20,743
Current portion of long term debt		2,591
Total current liabilities		38,720
Senior secured debt		120,000
Other notes payable		4,479
Asset retirement obligation		3,805
Total long term liabilities		128,284
Commitments and Contingencies(Notes 2 and 7)
Stockholders’ Equity:
Common stock, par value $.001; 20,000 shares authorized, 10,000 issued and outstanding as of June 30, 2004		–
Additional paid-in capital		185,307
Accumulated other comprehensive loss		(20,744	)
Accumulated deficit		(76,797	)
Total stockholders’ equity		87,766
Total Liabilities and Stockholders’ Equity	$	254,770

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

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INLAND RESOURCES INC.

CONSOLIDATED INCOME STATEMENTS
(In thousands)
Unaudited

	Six Months Ended
	June 30,
	2004			2003
Revenues:
Oil and gas sales	$	32,450		$	17,730
Gain on lease sales		310			—
Drilling and other service revenues		809			465
Total revenues		33,569			18,195
Operating Expenses:
Lease operating expenses		6,255			4,748
Production taxes		570			239
Exploration		48			56
Drilling and other service expenses		611			242
Depletion, depreciation and amortization		8,395			4,748
Accretion of asset retirement obligation		162			—
General and administrative, net		17,800			376
Total operating expenses		33,841			10,409
Operating Income (Loss)		(272	)		7,786
Interest expense		(3,064	)		(8,829	)
Interest and other income		39			47
Loss Before Cumulative Effect of Change in Accounting Principle		(3,297	)		(996	)
Cumulative effect of change in accounting principle		—			992
Loss Before Income Taxes		(3,297	)		(4	)
Income taxes, current, net of net operating loss carryforward		—			—
Net Loss	$	(3,297	)	$	(4	)

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

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INLAND RESOURCES INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
FOR THE SIX MONTHS ENDED JUNE 30, 2004
(In thousands)
Unaudited

										Accumulated
	Common Stock				Additional Paid-In		Accumulated			Other Comprehensive			Stockholders’
	Shares		Amount		Capital		Deficit			Income (Loss)			Equity
Balance, January 1, 2004		10	$	–	$	168,007	$	(73,500	)	$	(7,407	)	$	87,100
Stock options		–		–		17,300		–			–			17,300
Comprehensive income (loss):
Net loss		–		–		–		(3,297	)		–			(3,297	)
Changes in fair value of derivative contracts		–		–		–		–			(19,382	)		(19,382	)
Derivative contract settlements reclassified to income		–		–		–		–			6,045			6,045
Total comprehensive loss		–		–		–		–			–			(16,634	)
Balance, June 30, 2004		10	$	–	$	185,307	$	(76,797	)	$	(20,744	)	$	87,766

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

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INLAND RESOURCES INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Unaudited

	Six Months Ended
	June 30,
	2004			2003
Cash Flows from Operating Activities:
Net loss	$	(3,297	)	$	(4	)
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		8,397			4,748
Stock compensation		17,300			—
Non-cash loss, disposal of assets		—			6
Amortization of debt issue costs		229			533
Non cash changes related to derivatives		—			(175	)
Gain on lease sales		(318	)		—
Accretion of asset retirement obligation		162			133
Interest expense converted to equity		—			5,991
Cumulative effect of change in accounting principle		—			(992	)
Effect of changes in current assets and liabilities:
Accounts receivable		(3,423	)		(812	)
Inventory		(419	)		265
Other assets		(63	)		243
Accounts payable and accrued expenses		(995	)		1,406
Net cash provided by operating activities		17,573			11,342
Cash Flows from Investing Activities:
Development expenditures and equipment purchases		(48,112	)		(10,994	)
Net cash used in investing activities		(48,112	)		(10,994	)
Cash Flows from Financing Activities:
Payments of senior and other long-term debt		(7,595	)		—
Debt issuance cost		(2,113	)		—
Proceeds of issuance of long-term debt		43,439			—
Payments from issuance of other long-term debt		—			(358	)
Purchase of minority stockholders		—			(282	)
Net cash provided by (used in) financing activities		33,731			(640	)
Net Increase (Decrease) in Cash and Cash Equivalents		3,192			(292	)
Cash and Cash Equivalents, at beginning of period		1,165			1,525
Cash and Cash Equivalents, at end of period	$	4,357		$	1,233
Interest Paid for by Cash	$	2,868		$	2,575
Other Non-Cash:
Exchange of debt and accrued interest for equity				$	126,856
Conversion of preferred stock for common stock				$	1

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

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INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

1.	Business Summary of Significant Accounting Policies:
	Business– Inland Resources Inc. (“Inland” or the “Company”) is an independent energy company with substantially all of its producing oil and gas property interests located in the Monument Butte Field (the “Field”) within the Uinta Basin of Northeastern Utah.
	Consolidation– The accompanying consolidated financial statements include the accounts of the Company and its subsidiaries, Inland Production Company, Wildrose Resources Corporation and Eagle Drilling Services Inc., all of which are wholly owned directly or indirectly by the Company. Inland Production Company and its wholly owned subsidiary, Wildrose Resources Corporation, owns, develops and operates all of the oil and gas properties of the Company. Eagle Drilling Services Inc. is an oil field services company providing well drilling and other services exclusively to Inland Production Company and Wildrose Resources Corporation. All significant inter-company accounts and transactions have been eliminated in consolidation.
	Interim Financial Statements– Management has included these notes to the interim financial statements to assist the reader’s understanding of the financial position and results of operations of the Company as of and for the indicated dates. These interim financial statements are unaudited, but in the opinion of management, include all of the adjustments (consisting only of normal recurring accruals) necessary for a fair presentation in accordance with generally accepted accounting principles. Operating results presented for the six months ended June 30, 2004, are not necessarily indicative of those to be expected for the year.
	Use of Estimates in the Preparation of Financial Statements– The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America, 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 financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Oil and gas prices have a significant influence on estimates made by management. Changes in oil and gas prices and production rates directly affect the economics of estimated oil and gas reserves. These economics have significant effects upon predicted reserve quantities and valuations. These estimates are the basis for the calculation of depletion, depreciation and amortization of the Company’s oil and gas properties and whether an assessment of impairment is required. Forecasted oil and gas pricing estimates factor into estimated future cash flow projections used in assessing impairment for the oil and gas properties.
	Cash and Cash Equivalents– Cash and cash equivalents include cash on hand and amounts due from banks and other investments with original maturities of less than three months.
	Concentrations of Credit Risk– The Company regularly has cash held by a single financial institution that exceeds depository insurance limits. The Company places such deposits with institutions that management believes are of high credit quality. The Company has not experienced any credit losses. Substantially all of the Company’s receivables are within the oil and gas industry, primarily from its oil and gas purchasers and joint interest owners. Although diversified with many companies, collectibility is dependent upon the general economic conditions of the industry.

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INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

Fair Value of Financial Instruments– The Company’s financial instruments consist of cash, trade receivables, trade payables, accrued liabilities, long-term debt and derivative instruments. The carrying values of cash and cash equivalents, trade receivables and trade payables are considered to be representative of their fair market value, due to the short maturity of these instruments. The fair value of variable interest rate long-term debt approximates fair value. Because the fixed rate debt is unique to the Company, the fair value is not readily determinable. The estimated fair values of derivative contracts are estimated based on market conditions in effect at the end of each reporting period.

Inventories– Inventories consist of tubular goods valued at the lower of average cost or market. Materials and supplies inventories are stated at cost and are charged to capital or expense, as appropriate, when used.

Accounting for Oil and Gas Operations– The Company follows the successful efforts method of accounting for oil and gas operations. The use of this method results in the capitalization of those costs associated with the acquisition, exploration and development of properties that produce revenue or are anticipated to produce future revenue. The Company does not capitalize general and administrative expenses directly identifiable with such activities or lease operating expenses associated with secondary recovery startup projects. The costs of unsuccessful exploration efforts are expensed in the period in which it is determined that such costs are not recoverable through future revenues. Geological and geophysical costs are expensed as incurred. The costs of development wells are capitalized whether productive or nonproductive. Upon the sale of proved properties, the cost and accumulated depletion are removed from the accounts. Any gain or loss is recorded in the results of operations. Interest is capitalized during the drilling and completion period of wells and on other major projects.

The Company also periodically assesses unproved oil and gas properties for impairment. Impairment represents management’s estimate of the decline in realizable value experienced during the period for leases not expected to be utilized by the Company.

Property and Equipment– Property and equipment is recorded at cost. Replacements and major improvements are capitalized and the assets replaced are retired. Upon sale or retirement, the asset cost and accumulated depreciation are removed from the accounts and any resulting gain or loss is reflected in operations. Depreciation is calculated using the straight-line method over the estimated useful lives of the related assets, generally ranging from three to thirty years. Maintenance and repairs are charged to expense as incurred.

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INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

	Income Taxes– The Company uses the liability method of accounting for income taxes. Under this method, deferred income taxes are recorded for differences between the book and tax basis of assets and liabilities at tax rates in effect when the balances are expected to reverse. A valuation allowance against deferred tax assets is recorded when the conclusion by management of the Company is reached, based on available evidence, that the tax benefits are not expected to be realized.
	Revenue Recognition– Sales of crude oil and natural gas are recorded upon delivery to purchasers. The Company accounts for oil and gas sales using the entitlements method. Under the entitlements method, revenue is recorded based upon the Company’s share of volumes sold, regardless of whether the Company has taken its proportionate share of volumes produced. The Company records a receivable or payable to the extent it receives less or more than its proportionate share of the related revenue.
	Comprehensive Income (Loss)– In addition to net income (loss), comprehensive income (loss) includes all changes in equity during a period, except those resulting from investments by and distributions to owners. The portion of changes in fair value of derivative instruments that qualify for cash flow hedges is included in accumulated comprehensive income (loss).
2.	Contractual Obligations:
	The Company’s contractual obligations are listed in the following table (in thousands):

Contractual			Less Than		1-3		4-5		After
Obligations	Total		1 Year		Years		Years		5 Years
Long-term debt	$	127,070	$	2,591	$	34,422	$	90,057	$	–
Operating leases		252		139		113		–		–
Total contractual obligations	$	127,322	$	2,730	$	34,535	$	90,057	$	–

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INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

3.	Change in Accounting Principle:
	Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses accounting and reporting associated with the retirement of tangible long-lived assets.
	The fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is also added to the carrying amount of the associated asset and is depreciated over the life of the asset. The liability is accreted at the end of each period through charges to accretion expense, which is recorded as additional depreciation, depletion and amortization. If the obligation is settled for other than the carrying amount of the liability, a gain or loss is recognized on settlement.
	The table below shows the changes in the aggregate carrying amount of the Company’s retirement obligations for the six months ended June 30, 2004.

	Six Months Ended
	June 30, 2004
	(in thousands)
Beginning of the period, January 1, 2004	$	3,240
Liabilities incurred in the current period		435
Liabilities settled in the current period		(32	)
Accretion expense		162
End of period, June 30, 2004	$	3,805

4.	Financial Instruments:
	Periodically, the Company enters into commodity contracts to hedge or otherwise reduce the impact of oil price fluctuations or as required under its senior bank agreements. The amortized cost and the monthly settlement gains or losses are reported as adjustments to revenue in the period in which the related oil is sold. Hedging activities do not affect the actual sales price for the Company’s crude oil. The Company recognizes the fair market value of its open hedges as either assets or liabilities at the balance sheet date. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. Gains and losses on derivative hedging instruments must be recorded in either other comprehensive income (loss) or current earnings, depending on the nature and designation of the instrument.
	On February 26, 2003, the Company hedged 40,000 net barrels per month with Shell Trading Company (Shell) for the January 2004 through December 2004 period using various swaps with an average settlement amount of $25.25 per barrel.

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INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

On September 19, 2003 the Company hedged an additional 25,000 net barrels per month with Shell for January 2005 through December 2005 with an average settlement amount of $24.85 per barrel. On September 22, 2003 the Company hedged an additional 25,000 net barrels per month with Shell for January 2005 through December 2005 with an average settlement amount of $24.96 per barrel. On September 23, 2003 the Company hedged an additional 22,000 net barrels per month with Shell for January 2005 through December 2005 with an average settlement amount of $25.03 per barrel. On October 10, 2003 the Company hedged an additional 15,000 net barrels per month with Shell for January 2004 and February 2004 with a settlement amount of $30.30 and $30.20 per barrel, respectively. On November 19, 2003 the Company hedged an additional 15,000 net barrels per month with Shell for March 2004 and April 2004 with a settlement amount of $30.50 and $30.02 per barrel, respectively. On December 12, 2003 the Company hedged an additional 15,000 net barrels per month with Shell for May 2004 and June 2004 with a settlement amount of $30.15 and $30.02 per barrel, respectively.

Shell has the right to require the Company to post collateral for the difference between the mid-market estimate of the cost of liquidating and terminating the hedging positions and a “credit margin.” On August 22, 2003, Shell increased the Company’s credit margin from $1,500,000 to $1,750,000. On September 23 and December 12, 2003, Fortis Capital Corp. issued letters of credit totaling $1 million and $1.5 million, respectively, to cover any deficiencies between the $1,750,000 credit margin and the mid-market estimate from Shell.

As part of the amended senior bank covenant requirements, on January 8, 2004, the Company hedged an additional 67,000 net barrels per month with Bank One for January 2006 through December 2006 with an average settlement amount of $26.78 per barrel. On February 26, 2004, the Company hedged 40,000 net barrels per month with Bank One for January 2007 through June 2007 with a settlement amount of $27.00 per barrel.

On February 20, 2004, Shell assigned its total position with the Company (described in the above paragraphs) starting with February 2004 through December 2005 hedging contracts to Bank One (member of the senior bank group). Shell released the $1.5 million and $1.0 million letters of credit on February 23 and 24, 2004, respectively.

On January 27, 2003, the Company hedged 30,000 net barrels per month with Big West Oil Company (“Big West”) for the January 2004 through December 2004 period using various swaps with an average settlement amount of $23.95 per barrel. On February 18, 2003, the Company hedged another 10,000 net barrels per month with Big West for the January 2004 through December 2004 period using a swap with an average settlement amount of $24.90 per barrel.

Big West has the right to require the Company to post collateral for the difference between the mid-market estimate of the cost of liquidating and terminating the above mentioned hedging position and $1,000,000. There are no current requirements from Big West to issue collateral on the above-mentioned Big West swap positions.

The Company recognized a reduction in revenues under hedging contracts of $6,045,000 for the six months ended June 30, 2004, compared to reductions of $2,390,000 for the six months ended June 30, 2003. Unrealized losses of $20,743,000 at June 30, 2004 have been deferred as a component of accumulated other comprehensive income (loss). The Company anticipates that production sales in the next 12 months with the related hedging contracts will account for approximately $11,112,000 of the unrealized loss.

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INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

5.	Long-Term Debt:
	A summary of the Company’s debt follows (in thousands):

	June 30,
	2004
Fortis credit agreement	$	120,000
U.S. Bancorp Equipment Finance agreement		5,654
Custom Energy note payable		668
Other		748
Less current portion of long-term debt		(2,591	)
Total long-term debt	$	124,479

Fortis/Bank One Credit Agreement– On January 14, 2004, the Company entered into an amended credit agreement (the “Fortis/Bank One Credit Agreement”) with Fortis Capital Corp. as Administrative Agent and Co- Lead Arranger and Banc One Capital Markets, Inc. as Syndication Agent and Co-Lead Arranger (the “Agents”). The current bank participants are Fortis Capital Corp., Bank One, N.A., U.S. Bank National Association, Union Bank of California, N.A. and The Frost National Bank (the “Senior Lenders”).

The total amended loan commitment is for $110 million, which is segregated into two tranches. The Tranche A and B loans are committed up to $80 million and $30 million, respectively. On January 14, 2004, the Company used the Tranche B loan proceeds of $30 million to retire the $6.5 million unsecured senior subordinated note to Pengo (including accrued interest of $1.5 million) and to reduce the Tranche A loan from $83 million to $64.5 million. The remainder of the proceeds ($5 million) was used for general corporate purposes (including working capital and the payment of fees associated with the amended credit facility).

On May 26, 2004, the credit agreement was further amended to increase the total loan commitment to $130 million with the Tranche A and B loans being increased to $95 million and $35 million, respectively. Since the January 14, 2004 amendment and use of proceeds, the Company has drawn $20.5 million from the Tranche A loan and $5 million from the Tranche B loan to fund the $13.6 million acquisition of producing acreage and $11.9 for working capital to further develop the field.

The borrowing base is calculated as the collateral value of proved reserves and is subject to redetermination each October 1 and April 1. If the borrowing base is lower than the outstanding principal balance then drawn, the Company must immediately repay the difference.

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INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

The revolving termination date for both the Tranche A and B loans is January 1, 2007, at which time the Tranche A and B loans convert into a term loan payable in 8 equal quarterly installments of principal, with accrued interest, beginning March 31, 2007 with the last payment on December 31, 2008, or potentially earlier if the borrowing base is determined to be insufficient. Interest accrues for the Tranche A facility, at the Company’s option, at either (i) various prime rates (“Base Rate”) or (ii) at various rates above the LIBOR rate (“Adjusted Eurodollar Rate”). The Base Rate means the higher of (a) the reference rate and the federal funds rate plus one–half percent (.5%) per annum. The reference rate means the rate of interest publicly announced by the Agent, as its prime commercial lending rate. If such bank ceases to announce publicly its prime commercial rate, the Agent can determine the reference rate based upon prime commercial lending announced by other banks. The base rate margins determined will be adjusted by the Borrowing Base utilization if (1) the Borrowing Base utilization is less than 40%, the base rate margin is .000%, (2) if the Borrowing Base utilization is less than 70% but equal to or greater than 40%, the base rate margin is .250%, (3) if the Borrowing Base utilization is less than 95% but equal to or greater than 70%, the base rate margin is .500% and (4) if the Borrowing Base utilization is equal to or greater than 95%, the base rate margin is 1.000%. The Adjusted Eurodollar Rate margins determined will be adjusted by the Borrowing Base utilization if (1) the Borrowing Base utilization is less than 40%, the Eurodollar margin is 1.75%, (2) if the Borrowing Base utilization is less than 70% but equal to or greater than 40%, the Eurodollar margin is 2.00%, (3) if the Borrowing Base utilization is less than 95% but equal to or greater than 70%, the Eurodollar margin is 2.250% and (4) if the Borrowing Base utilization is equal to or greater than 95%, the Eurodollar margin is 2.750%. Interest accrues for the Tranche B facility prior to January 1, 2006 at the greater of ten percent (10%) per annum or the Adjusted Eurodollar rate in effect. After January 1, 2006, the interest rate for the Tranche B Facility will be at the greater of fifteen percent (15%) per annum or the Adjusted Eurodollar rate in effect.

The Fortis/Bank One Credit Agreement provides for a commitment of $5 million for letters of credit to support commodity price hedging and other obligations to be secured by letters of credit. As part of the agreement, the Company agreed to hedge 60% of its net projected oil and gas production for 2004 and 50% of its net projected oil and gas production for 2005 and 2006. For 2007 and each successive three year period, commencing on June 30, 2004 and each December 31 and June 30 thereafter, the Company must have hedged 50% of its net projected oil and gas production for each such three year period.

The Fortis/Bank One Credit Agreement has covenants that restrict the payment of cash dividends, certain borrowings, sales of assets, loans to others, investments, merger activity and hedging contracts without the prior consent of the lenders. The Fortis/Bank One Credit Agreement allows the Company to borrow up to $7 million from other financing sources for field equipment and inventory. The Company is required by the Credit Agreement to maintain certain operational levels and financial ratios including net daily production minimums, working capital ratios, and debt to profitability ratios, as defined in the Credit Agreement. The Company was in compliance with the amended senior bank covenants as of June 30, 2004. The Fortis/Bank One Credit Agreement is collateralized by a first lien on substantially all of the assets of the Company.

Secured Equipment Note– On January 26, 2004, the Company entered into a master loan agreement with U.S. Bancorp Equipment Finance, Inc. with a loan commitment of $6 million to acquire major oilfield service equipment. Payments are determined based on a 36-month amortization from the date of each scheduled equipment advance with the interest rate in effect, based on U.S. Bank’s 3-year cost of funds, on the date of such advance. As of June 30, 2004, the Company had drawn $5,654,000 of the available line with interest rates of 4.95% to 6.107% and monthly payments including interest of approximately $188,000.

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INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

	Unsecured Subordinated Note– The Company issued a $5 million unsecured senior subordinated note to Pengo Securities Corp., an affiliate of Smith Management LLC (“Pengo”), on August 2, 2001. The interest rate is 11% per annum compounded quarterly. The maturity date is the earlier of (i) 180 days after payment in full of the Fortis Credit Agreement or (ii) March 31, 2010. Interest is payable in arrears in cash subject to the approval of the Senior Lenders and accumulates if not paid in cash. The Company is not required to make any principal payments prior to the March 31, 2010 maturity date. Prior to the March 31, 2010 maturity date, subject to both bank and subordination agreements, the Company may prepay the senior subordinated note in whole or in part with no penalty. As mentioned above, on January 14, 2004, the Company retired the $5 million unsecured senior subordinated note plus $1.5 million in accrued interest.
	Other Secured Notes–Other notes payable consist of financing agreements with various lenders for the acquisition of gas processing and other operating equipment utilized in the field. These agreements are for terms of 3 to 5 years at interest rates from 5% to 7%, with monthly principal and interest payments of approximately $90,000. The notes are secured by the respective equipment. As of June 30, 2004, the outstanding aggregate balance on these notes was approximately $1,416,000.
6.	Income Taxes:
	No regular income tax expense or benefit was recognized due to the effect of net operating losses and the recording of a valuation allowance against portions of the deferred tax assets that did not meet the utilization criteria of more likely than not. Deferred income taxes reflect the impact of temporary differences between amounts of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws. The temporary differences and carryforwards giving rise to the Company’s deferred tax assets and liabilities at June 30, 2004 are primarily the net operating loss carryforwards and depletion, depreciation and amortization of property and equipment, which have been offset by a valuation allowance.
	Income tax (benefit) expense differed from amounts computed by applying the statutory federal income tax rate primarily due to the change in the valuation allowance.
	At December 31, 2003, the Company had tax basis net operating loss carryforwards available to offset future regular and alternative taxable income of $103 million that expire from 2004 to 2022. Utilization of the net operating loss carryforwards is limited under the change of ownership tax rules. The Company has fully provided for a valuation allowance for net operating loss carryforwards. The change in valuation allowance for 2003 was approximately $10,555,000.
7.	Commitments and Contingencies:
	401(k) Plan– The Company provides a voluntary 401(k) employee savings plan that covers all full-time employees who meet certain eligibility requirements. Voluntary contributions are made to the 401(k) plan by participants. In addition, the Company matches 100% of the first 6% of salary contributed by each employee. Matching contributions of approximately $174,000 were made by the Company during the six months ended June 30, 2004.
	At December 31, 2003, the Company had recorded deferred revenues of approximately $775,000 related to pending acreage assignments with the sale of its undeveloped deep gas rights to Stone Energy Corporation. The Company settled this commitment in April, 2004 by transferring an additional 3,354 net acres with a value of $353,000 and a cash payment of $422,000 to Stone.

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INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

	Legal Proceedings– The Company is from time to time involved in various legal proceedings characterized as normally incidental to the business.
	Management believes its defenses to any existing litigation will be meritorious and any adverse decisions in any pending or threatened proceedings or any amounts which it may be required to pay by reason thereof will not have a material adverse effect on its financial condition or results of operations or cash flows.
	Employment Agreements– The Company has employment agreements with certain key employees of the Company, which provide for payment to the employees for profitability and upon termination following a change in control.
	Key Employee Incentive Bonus Plan – On May 3, 2004, the Company adopted an incentive bonus plan (“Bonus Plan”) for its key eligible employees. The amount realized in the Bonus Plan is to be calculated based on an occurrence of a Determination Event defined generally as a sale of the Company. If there is a change of control as defined by the Bonus Plan, the Award Pool is established by formula. Any participant’s bonus will be determined by their percentage of the Bonus Pool. The participant’s payment date means the date which is the one year anniversary of the Determination Date unless an earlier date is determined by the Plan administrator.
8.	Stock Options:
	The Company granted certain key employees nonqualified (“Non-Plan”) options to purchase common stock on June 2, 2003, and amended on April 13, 2004. As a result, all options outstanding at June 30, 2004, were subject to variable option accounting, resulting in compensation expense of $17,300,000, which was recorded in June 2004. These grants were made at estimated market value and have a ten year life. The following table summarizes information for options outstanding at June 30, 2004 for all Non-Plan options.

Options outstanding						Options exercisable
				Weighted
				Average
				Remaining		Weighted
				Contractual Life		Average				Option Exercise
	Exercise Price	Number		(Years)		Exercise Price		Number		Price Range
$	7,700		512		9.0	$	7,700		512	$	7,700

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INLAND RESOURCES INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Unaudited

9.	Property acquisitions:
	On April 15, 2004, the Company acquired, by means of a stock purchase, 100% of Wildrose Resources Corporation (Wildrose). The primary assets of Wildrose are developed and proved undeveloped oil and gas properties in the Monument Butte Field. The Company paid $3.2 million for the common stock.
	The Company has allocated the purchase price as follows (in thousands):

Unproved properties	$	1,443
Proved properties		1,579
Cash		183
Other assets		42
Total assets	$	3,247
Additional paid-in capital	$	3,247
Net income from date of acquisition	$	220

On June 1, 2004 the Company acquired all of the oil and gas properties of Smith Energy Partnership located in the Monument Butte Field. The Company paid $10.6 million for the properties and allocated the total cost to producing properties.

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