exv99w1

REPORT OF INDEPENDENT REGISTERED ACCOUNTING FIRM

Board of Directors
Inland Resources Inc.
Denver, Colorado

We have audited the accompanying balance sheet of Inland Resources Inc. as of December 31, 2003, and the related statements of income, stockholders’ equity, and cash flows for the year then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Inland Resources Inc. as of December 31, 2003 and the results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ HEIN & ASSOCIATES LLP

Hein & Associates LLP
Denver, Colorado

March 3, 2004

INLAND RESOURCES INC.

CONSOLIDATED BALANCE SHEET
DECEMBER 31, 2003
(In thousands)


ASSETS
Current Assets:
Cash and cash equivalents	$	1,165
Accounts receivable and accrued sales		5,500
Inventory		1,236
Other current assets		714

Total current assets		8,615

Property and Equipment, at cost:
Oil and gas properties (successful efforts method)		254,320
Accumulated depletion, depreciation and amortization		(62,299	)

		192,021
Other property and equipment, net		3,434

Total property and equipment, net		195,455

Other long-term assets, net		1,284

Total assets	$	205,354

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable	$	11,063
Accrued expenses		5,318
Fair market value of derivative instruments		7,407
Current portion of long term debt		800

Total current liabilities		24,588

Senior secured debt		83,000
Other notes payable		930
Senior subordinated unsecured debt including accrued interest		6,496
Asset retirement obligation		3,240

Total long term liabilities		93,666

Commitments and Contingencies (Notes 3 and 8)
Stockholders’ Equity:
Common stock, par value $.001; 20,000 shares authorized, 10,000 issued and outstanding as of December 31, 2003		–
Additional paid-in capital		168,007
Accumulated other comprehensive loss		(7,407	)
Accumulated deficit		(73,500	)

Total stockholders’ equity		87,100

Total Liabilities and Stockholders’ Equity	$	205,354

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

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INLAND RESOURCES INC.

CONSOLIDATED INCOME STATEMENT
FOR THE YEAR ENDED DECEMBER 31, 2003
(In thousands)


Revenues:
Oil and gas sales	$	38,918
Gain on lease sales		4,227
Drilling and other service revenues		541

Total revenues		43,686

Operating Expenses:
Lease operating expenses		10,253
Production taxes		520
Exploration		126
Drilling and other service expenses		302
Depletion, depreciation and amortization		11,142
Accretion of asset retirement obligation		264
General and administrative		1,579

Total operating expenses		24,186

Operating Income		19,500
Unrealized gain on derivatives		231
Interest expense		(11,108	)
Interest and other income		34

Income Before Cumulative Effect of Change in Accounting Principle		8,657
Cumulative effect of change in accounting principle, net of income taxes		992

Net Income	$	9,649

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 YEAR ENDED DECEMBER 31, 2003
(In thousands)


																			Accumulated
	Common Stock						Preferred Stock						Additional Paid-In			Accumulated			Other Comprehensive			Stockholders’
	Shares			Amount			Shares			Amount			Capital			Deficit			Income (Loss)			Equity
Balance, January 1, 2003		2,898		$	3			–		$	–		$	41,431		$	(83,149	)	$	(1,324	)	$	(43,039	)
Debt exchange for stock (Note 2)		22,053			22			1,048			1			126,832			–			–			126,855
Recapitalization of Company (Note 2)		(24,941	)		(25	)		(1,048	)		(1	)		(256	)		–			–			(282	)
Comprehensive income (loss):
Net income		–			–			–			–			–			9,649			–			9,649
Changes in fair value of derivative contracts		–			–			–			–			–			–			(10,515	)		(10,515	)
Derivative contract settlements reclassified to income		–			–			–			–			–			–			4,432			4,432

Total comprehensive income		–			–			–			–			–			–			–			3,566

Balance, December 31, 2003		10		$	–			–		$	–		$	168,007		$	(73,500	)	$	(7,407	)	$	87,100

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

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INLAND RESOURCES INC.

CONSOLIDATED STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2003
(In thousands)


Cash Flows from Operating Activities:
Net income	$	9,649
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation and amortization		11,142
Amortization of debt issue costs		714
Unrealized gain on derivatives		(231	)
Gain on lease sales		(4,227	)
Accretion of asset retirement obligation		264
Cumulative effect of change in accounting principle		(992	)
Effect of changes in current assets and liabilities:
Accounts receivable		(2,149	)
Inventory		(148	)
Other assets		(204	)
Accounts payable and accrued expenses		15,628

Net cash provided by operating activities		29,446

Cash Flows from Investing Activities:
Development expenditures and equipment purchases		(33,087	)
Long term deposits		(180	)
Proceeds from lease sales		5,000

Net cash used in investing activities		(28,267	)

Cash Flows from Financing Activities:
Payments of senior and other long-term debt		(1,103	)
Debt issuance cost		(154	)
Purchase of minority stockholders		(282	)

Net cash used in financing activities		(1,539	)

Net Decrease in Cash and Cash Equivalents		(360	)
Cash and Cash Equivalents, at beginning of period		1,525

Cash and Cash Equivalents, at end of period	$	1,165

Interest Paid for by Cash	$	4,060

Other Non-Cash:
Purchase of equipment with issuance of long-term debt	$	487

Exchange of debt and accrued interest for equity	$	126,855

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

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 and Eagle Drilling Services Inc., both of which are wholly owned directly or indirectly by the Company. Inland Production Company 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. All significant inter-company accounts and transactions have been eliminated in consolidation.

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.

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 value 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.

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INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 during 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 provision for depletion, depreciation and amortization of developed oil and gas properties is based on the units of production method. This method utilizes proved oil and gas reserves determined using market prices at the end of each reporting period.

Impairment Review – Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (see Note 4). The Company reviews and evaluates its long-lived assets for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. An impairment loss is measured as the amount by which asset carrying value exceeds fair value. A calculation of the aggregate before-tax undiscounted future net revenues is performed for the Company’s oil and gas properties. The Company utilizes an estimated price scenario based on its budget and future estimates of oil and gas prices from industry projections and quoted futures prices.

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.

Income Taxes – The Company uses the liability method of accounting for income taxes. Under the liability 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 Company management is reached, based on available evidence, that the tax benefits are not expected to be realized.

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INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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).

Stock-Based Compensation – The Company has elected to follow Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), and related interpretations in accounting for its employee stock options because, as discussed below, the alternative fair value accounting provided for under FASB Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (SFAS 123), requires use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, if the exercise price of the Company’s employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recognized. The Company did not recognize any stock based compensation expense during the year.

Pro forma recognition regarding net loss and loss per share is required by SFAS 123, which also requires that the information be determined as if the Company has accounted for its employee stock options under the fair value method of SFAS 123. The fair value for options was estimated at the date of grant using a Black-Scholes option valuation model with the following assumptions used for all options granted in 2003: risk-free interest rate of 4.7%, a dividend yield of 0%, expected volatility of 0% and an expected life of five years.


	Year Ended
	December 31,
	2003
Net income attributable to common stockholders:
As reported	$	9,649
Pro forma FAS 123 expense		(1,760	)

Pro forma net income	$	7,889

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INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

2. Restructuring Transactions:

On January 30, 2003, Trust Company of the West, as Sub-Custodian for Mellon Bank for the benefit of Account No. CPFF 873-3032 (“Fund V”), TCW Portfolio No. 1555 DR V Sub-Custody Partnership, L.P. (“Portfolio”) (Portfolio and Fund V collectively being referred to as “TCW”) agreed to exchange its subordinated note in the principal amount of $98,969,000, plus all accrued and unpaid interest, for 22,053,000 shares of the Company’s common stock and that number of shares of Series F Preferred Stock equal to 911,588 shares, plus 338 shares for each day after November 30, 2002. Smith Management LLC (“Smith”) and its affiliates also agreed to exchange its Junior Subordinated Note in the principal amount of $5,000,000, plus all accrued and unpaid interest, for that number of shares of Series F Preferred Stock equal to 68,854 shares, plus 27 shares for each day after November 30, 2002. The Company authorized 1,100,000 shares of Series F Preferred Stock (the “TCW and Smith Exchange”).

TCW and two Smith Affiliated Parties formed a new Delaware corporation to be known as Inland Resources Inc. (“Newco”). TCW contributed to Newco all of TCW’s holdings in the Company’s common stock and Series F Preferred Stock in exchange for 92.5% of the common stock of Newco, and each of the Smith Affiliated Parties contributed to Newco all of their holdings in the Company’s common stock and Series F Preferred Stock in exchange for an aggregate of 7.5% of the common stock of Newco. Newco owned 99.7% of the Company’s common stock and common stock equivalents.

On February 3, 2003, the Company filed a Schedule 13E-3 with the Securities and Exchange Commission in order to complete the TCW and Smith Exchange and merge the Company with Newco. On May 5, 2003, the Company mailed the Transaction Statement for the merger to its stockholders. On June 2, 2003, the Board of Directors of Newco passed a resolution for Inland to merge with and into Newco, with Newco surviving as a Delaware corporation (the “Merger”). No action was required by the Company’s stockholders or Board of Directors under the relevant provisions of Washington and Delaware law with respect to a merger of a subsidiary owned more than 90% by its parent corporation. Stockholders unaffiliated with Newco received cash equal to $1.00 per share as a result of the Merger totaling approximately $282,000. The Merger resulted in Inland terminating its status as a reporting company under the Securities Exchange Act of 1934 and on June 4, 2003 its stock ceased to be traded on the over-the-counter bulletin board.

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INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. 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	$	91,226	$	800	$	766	$	89,660	$	–
Operating leases		623		461		162		–		–

Total contractual obligations	$	91,849	$	1,261	$	928	$	89,660	$	–

4. 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.

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INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, we will recognize a gain or loss on settlement.

The Company identified all required asset retirement obligations and determined the fair value of these obligations on the date of adoption. The determination of fair value was based upon regional market and specific well information. In conjunction with the initial application of SFAS No. 143, the Company recorded a cumulative effect of change in accounting principle, net of taxes, of $992,000 as additional income for the year ended December 31, 2003. The Company recorded an initial asset retirement obligation of $2,688,000. The table below shows the changes in the aggregate carrying amount of the Company’s retirement obligations for the year ended December 31, 2003.


	Year Ended
	December 31, 2003
	(in thousands)
Beginning of the period, January 1, 2003	$	–
Initial adoption entry		2,688
Liabilities incurred in the current period		339
Liabilities settled in the current period		(51	)
Accretion expense		264

End of period, December 31, 2003	$	3,240

5. 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.

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INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In 2001 and prior years, the Company entered into certain commodity derivative contracts with Enron North America Corp. (“ENAC”), a subsidiary of Enron Corp. (“Enron”). On December 2, 2001, Enron and ENAC filed for Chapter 11 bankruptcy. Under the provisions of SFAS No. 133, the Company ceased accounting for the ENAC derivative contracts as hedges at a date corresponding to the deterioration in the credit of ENAC and Enron in mid-October 2001. At this date, changes in the fair value of the derivative contracts no longer were considered effective in offsetting changes in the cash flows of the hedged production. Consequently, the Company recorded a loss of $2.155 million for the year ended December 31, 2001 and deferred a corresponding amount in accumulated other comprehensive income (loss), based on the estimated fair value of the derivative contracts at that date.

Of the $2.155 million deferred in accumulated other comprehensive income, $231,000, $1,444,000 and $480,000 was reclassified out of accumulated other comprehensive income in 2003, 2002 and 2001, respectively, as an increase in crude oil sales revenues.

On various dates between March and August of 2002, the Company hedged a total of 60,000 net barrels per month for the January 2003 through August 2003 period with Shell Trading Company (“Shell”) using a swap with various settlement amounts that averaged $24.78 per barrel. On January 16, 2003, the Company hedged 60,000 net barrels per month with Shell for the September 2003 through December 2003 period using a swap with a settlement amount of $25.63 per barrel. On February 26, 2003, the Company hedged another 40,000 net barrels per month with Shell for the January 2004 through December 2004 period using various swaps with an average settlement amount of $25.25 per barrel.

On September 19, 2003, the Company hedged an additional 20,000 net barrels per month with Shell for October 2003 through December 2003 with an average settlement amount of $29.68. 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.

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INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 price of $26.78 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 of $4,432,000 for the twelve months ended December 31, 2003 under hedging contracts. Unrealized losses of $7,407,000 at December 31, 2003 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 $5,313,000 of the unrealized loss.

6. Long-Term Debt:

A summary of the Company’s debt (including accrued unpaid interest) follows (in thousands):


	December 31,
	2003
Fortis credit agreement	$	83,000
Senior subordinated unsecured debt including interest		6,496
Custom Energy note payable		758
Other		972
Less current portion of long-term debt		(800	)

Total long-term debt	$	90,426

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”).

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INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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). The amended borrowing base under the Tranche A facility is $80 million. 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.

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 (.5%) percent 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.

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INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The Fortis/Bank One Credit Agreement allows the Company to borrow up to $6 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. Although not required until March 31, 2004, the Company was in compliance with the amended senior bank covenants as of December 31, 2003. The Fortis/Bank One Credit Agreement is collateralized by a first lien on substantially all of the assets of the Company.

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 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. As of December 31, 2003, the outstanding aggregate balance on these notes was approximately $1,730,000.

7. Income Taxes:

In 2003, no income tax provision 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 December 31, 2003 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 are 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.

8. Commitments and Contingencies:

401(k) Plan – The Company provides a voluntary 401(k) employee savings plan which 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 $249,000 were made by the Company during the year ended December 31, 2003.

-15-

INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 and cash flows.

Employment Agreements – The Company has employment agreements with certain employees of the Company, which provide for payment to the employees upon termination following a change in control.

Lease Sale – On July 31, 2003, the Company entered into a Purchase, Sale and Exploration Agreement with Stone Energy Corporation (“Stone”) to sell 51% or 46,920 net acres of its undeveloped deep gas rights to Stone for $5 million cash. Effective September 1, 2003, the sale of the Company’s deep gas rights closed with Stone. At closing, the Company assigned 39,642 net acres of the total 46,920 net acres to Stone. The Company will have until January 9, 2004 (with an extension until March 31, 2004) to deliver the remaining 7,278 net acres. If the remaining 7,278 net acres are not delivered by January 9, 2004 (or the March 31, 2004 extension), the Company’s options are to pay $106.56 per net acre ($773,000) to Stone or to assign from its remaining 49% working interest additional interests up to 7,278 net acres to Stone. The Company recorded a gain from the sale of its deep rights of $4,227,000 in the third quarter of 2003 to reflect the 39,642 net acres sold to Stone.

9. Stock Options:

1988 Stock Option Plan – On August 25, 1988, the Company’s Board of Directors adopted an incentive stock option plan (the “1988 Plan”) for the benefit of key employees and directors of the Company. A total of 21,280 shares of common stock are reserved for issuance under the 1988 Plan.

1997 Stock Option Plan – On April 30, 1997, the Company’s Board of Directors adopted an incentive stock option plan (the “1997 Plan”) for the benefit of key employees and directors of the Company. The Company reserved 50,000 shares for grant under the 1997 Plan.

A summary of option grants, exercises and average exercise prices under both the 1988 Plan and the 1997 Plan is presented below:


				Weighted			Option
	Number of			Average			Exercise
	Options			Exercise Price			Price Range
Balance, December 31, 2002		7,980		$	49.49		$	10.00 - $110.00
Cancelled		(7,980	)		(49.49	)		(10.00 - 110.00	)

Balance, December 31, 2003		–			–		$	–

On June 2, 2003, as a result of the Company’s restructuring (Note 2), these two plans were cancelled.

-16-

INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Non-Plan Grants – From time to time the Company grants nonqualified (“Non-Plan”) options to purchase common stock to its key employees. The grants have vesting periods of three to five years. These grants were made at estimated market value. The fair value based on a Black-Scholes calculation would be $2,300 per share. The option lives are five to ten years. The table below summarizes the activities associated with these grants to key employees:


				Weighted			Option
	Number of			Average			Exercise
	Options			Exercise Price			Price Range
Balance, December 31, 2002		325,000		$	2.67		$	1.63 – 9.38
Cancelled		(325,000	)		(2.67	)		(1.63 – 9.38	)
Issued		753			11,280.00			11,280.00

Balance, December 31, 2003		753		$	11,280.00		$	11,280.00

The following table summarizes information for options outstanding as of December 31, 2003 for all Plan and Non-Plan options.

Options Outstanding

Options Exercisable

Weighted

Average

Remaining

Contractual

Weighted

Life

Average

Exercise Price

Number

(Years)

Exercise Price

Number

Exercise Price

$11,280

753

9.50

11,280

753

11,280

10. Oil and Gas Producing Activities:

Major Customers – Sales to the following companies represented 10% or more of the Company’s revenues, excluding effects of hedging, (in thousands):


	2003
Crude Oil:
Big West	$	36,650
Gas:
Wasatch	$	5,340

Costs Incurred– Cost incurred in oil and gas producing activities were as follows (in thousands):


	2003
Unproved property acquisition cost	$	67
Development cost		32,062
Exploration cost		–

	$	32,129

-17-

INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Net Capital Costs – Net capitalized costs related to the Company’s oil and gas producing activities are summarized as follows (in thousands):


	2003
Unproved properties	$	2,005
Proved properties		239,523
Gas and water transportation facilities		12,792

Total		254,320
Accumulated depletion, depreciation and amortization		(62,299	)

Total	$	192,021

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

SFAS No. 69, “Disclosures about Oil and Gas Producing Activities,” prescribes guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below. Future cash inflows and future production and development costs are determined by applying year end prices and costs to the estimated quantities of oil and gas to be produced. Estimated future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion. The resulting future net cash flows are reduced to present value amounts by applying a 10% (“PV10%”) annual discount factor.

The assumptions used to compute the standardized measure are those prescribed by the Financial Accounting Standards Board and, as such, do not necessarily reflect the Company’s expectations of actual revenues to be derived from those reserves nor their present value. The limitations inherent in the reserve quantity estimation process are equally applicable to the standardized measure computations since these estimates are the basis for the valuation process.

The following summary sets forth the Company’s future net cash flows relating to proved oil and gas reserves based on the standardized measure prescribed in SFAS No. 69 (in thousands):


	December 31,
	2003
Future cash inflows	$	1,923,536
Future production costs		(443,892	)
Future development costs		(207,299	)
Future income tax provision		(433,346	)

Future net cash flows		838,999
Less effect of 10% discount factor		(458,846	)

Standardized measure of discounted future net cash flows	$	380,153

-18-

INLAND RESOURCES INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The principal sources of changes in the standardized measure of discounted future net cash flows are as follows for the year ended December 31, 2003 (in thousands):


	2003
Standardized measure, beginning of year	$	295,625
Sales of reserves in place		—
Sales of oil and gas produced excluding effects of hedging, net of production costs		(31,298	)
Net change in sales prices and production costs		115,914
Extensions, discoveries and improved recovery, net		—
Revisions of previous quantity estimates		411
Change in future development costs		(30,911	)
Development costs incurred during the period		33,917
Net change in income taxes		(67,536	)
Accretion of discount		29,563
Changes in production rates and other		34,468

Standardized measure, end of year	$	380,153

Oil and Gas Reserve Quantities (Unaudited)

The reserve information presented below is based upon reports prepared by the Company’s in-house petroleum engineer. An independent engineering firm reviewed properties comprising 80% of the PV10% value of the reserves. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. As a result, revisions to previous estimates are expected to occur as additional production data becomes available or economic factors change.

Proved oil and gas reserves are estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and gas reserves are those expected to be recovered through existing wells with existing equipment and operating methods. The fluctuation of oil and gas prices has a significant impact on the standardized measure. Future increases or decreases in oil or gas prices increase or decrease the standardized measure accordingly. As of December 31, 2003, the Company used prices of $29.52 per Bbl and $5.52 per Mcf.

Presented below is a summary of the changes in estimated proved reserves of the Company, all of which are located in the United States, for the year ended December 31, 2003:


	2003
	Oil (MBbl)			Gas (MMcf)
Proved reserves, beginning of year		52,966			83,988
Sales of reserves in place		—			—
Extensions and discoveries		—			—
Production		(1,371	)		(1,827	)
Revisions of previous estimates		1,504			(7,630	)

Proved reserves, end of year		53,099			74,531

Proved developed reserves, end of year		19,591			18,475

-19-


	PAGE
Report of Independent Registered Accounting Firm		1
Consolidated Balance Sheet – December 31, 2003		2
Consolidated Income Statement – For the Year Ended December 31, 2003		3
Consolidated Statement of Stockholders’ Equity – For the Year Ended December 31, 2003		4
Consolidated Statement of Cash Flows – For the Year Ended December 31, 2003		5
Notes to the Consolidated Financial Statements		6

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 and Eagle Drilling Services Inc., both of which are wholly owned directly or indirectly by the Company. Inland Production Company 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. All significant inter-company accounts and transactions have been eliminated in consolidation.

		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.

		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 value 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 during 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 provision for depletion, depreciation and amortization of developed oil and gas properties is based on the units of production method. This method utilizes proved oil and gas reserves determined using market prices at the end of each reporting period.

		Impairment Review – Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (see Note 4). The Company reviews and evaluates its long-lived assets for impairment when events or changes in circumstances indicate that the related carrying amounts may not be recoverable. An impairment loss is measured as the amount by which asset carrying value exceeds fair value. A calculation of the aggregate before-tax undiscounted future net revenues is performed for the Company’s oil and gas properties. The Company utilizes an estimated price scenario based on its budget and future estimates of oil and gas prices from industry projections and quoted futures prices.

		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.

		Income Taxes – The Company uses the liability method of accounting for income taxes. Under the liability 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 Company management 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).

		Stock-Based Compensation – The Company has elected to follow Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25), and related interpretations in accounting for its employee stock options because, as discussed below, the alternative fair value accounting provided for under FASB Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation” (SFAS 123), requires use of option valuation models that were not developed for use in valuing employee stock options. Under APB 25, if the exercise price of the Company’s employee stock options equals the market price of the underlying stock on the date of grant, no compensation expense is recognized. The Company did not recognize any stock based compensation expense during the year.

		Pro forma recognition regarding net loss and loss per share is required by SFAS 123, which also requires that the information be determined as if the Company has accounted for its employee stock options under the fair value method of SFAS 123. The fair value for options was estimated at the date of grant using a Black-Scholes option valuation model with the following assumptions used for all options granted in 2003: risk-free interest rate of 4.7%, a dividend yield of 0%, expected volatility of 0% and an expected life of five years.

2.		Restructuring Transactions:

		On January 30, 2003, Trust Company of the West, as Sub-Custodian for Mellon Bank for the benefit of Account No. CPFF 873-3032 (“Fund V”), TCW Portfolio No. 1555 DR V Sub-Custody Partnership, L.P. (“Portfolio”) (Portfolio and Fund V collectively being referred to as “TCW”) agreed to exchange its subordinated note in the principal amount of $98,969,000, plus all accrued and unpaid interest, for 22,053,000 shares of the Company’s common stock and that number of shares of Series F Preferred Stock equal to 911,588 shares, plus 338 shares for each day after November 30, 2002. Smith Management LLC (“Smith”) and its affiliates also agreed to exchange its Junior Subordinated Note in the principal amount of $5,000,000, plus all accrued and unpaid interest, for that number of shares of Series F Preferred Stock equal to 68,854 shares, plus 27 shares for each day after November 30, 2002. The Company authorized 1,100,000 shares of Series F Preferred Stock (the “TCW and Smith Exchange”).

		TCW and two Smith Affiliated Parties formed a new Delaware corporation to be known as Inland Resources Inc. (“Newco”). TCW contributed to Newco all of TCW’s holdings in the Company’s common stock and Series F Preferred Stock in exchange for 92.5% of the common stock of Newco, and each of the Smith Affiliated Parties contributed to Newco all of their holdings in the Company’s common stock and Series F Preferred Stock in exchange for an aggregate of 7.5% of the common stock of Newco. Newco owned 99.7% of the Company’s common stock and common stock equivalents.

		On February 3, 2003, the Company filed a Schedule 13E-3 with the Securities and Exchange Commission in order to complete the TCW and Smith Exchange and merge the Company with Newco. On May 5, 2003, the Company mailed the Transaction Statement for the merger to its stockholders. On June 2, 2003, the Board of Directors of Newco passed a resolution for Inland to merge with and into Newco, with Newco surviving as a Delaware corporation (the “Merger”). No action was required by the Company’s stockholders or Board of Directors under the relevant provisions of Washington and Delaware law with respect to a merger of a subsidiary owned more than 90% by its parent corporation. Stockholders unaffiliated with Newco received cash equal to $1.00 per share as a result of the Merger totaling approximately $282,000. The Merger resulted in Inland terminating its status as a reporting company under the Securities Exchange Act of 1934 and on June 4, 2003 its stock ceased to be traded on the over-the-counter bulletin board.

3.		Contractual Obligations:

		The Company’s contractual obligations are listed in the following table (in thousands):

4.		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, we will recognize a gain or loss on settlement.

		The Company identified all required asset retirement obligations and determined the fair value of these obligations on the date of adoption. The determination of fair value was based upon regional market and specific well information. In conjunction with the initial application of SFAS No. 143, the Company recorded a cumulative effect of change in accounting principle, net of taxes, of $992,000 as additional income for the year ended December 31, 2003. The Company recorded an initial asset retirement obligation of $2,688,000. The table below shows the changes in the aggregate carrying amount of the Company’s retirement obligations for the year ended December 31, 2003.

5.		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.

		In 2001 and prior years, the Company entered into certain commodity derivative contracts with Enron North America Corp. (“ENAC”), a subsidiary of Enron Corp. (“Enron”). On December 2, 2001, Enron and ENAC filed for Chapter 11 bankruptcy. Under the provisions of SFAS No. 133, the Company ceased accounting for the ENAC derivative contracts as hedges at a date corresponding to the deterioration in the credit of ENAC and Enron in mid-October 2001. At this date, changes in the fair value of the derivative contracts no longer were considered effective in offsetting changes in the cash flows of the hedged production. Consequently, the Company recorded a loss of $2.155 million for the year ended December 31, 2001 and deferred a corresponding amount in accumulated other comprehensive income (loss), based on the estimated fair value of the derivative contracts at that date.

		Of the $2.155 million deferred in accumulated other comprehensive income, $231,000, $1,444,000 and $480,000 was reclassified out of accumulated other comprehensive income in 2003, 2002 and 2001, respectively, as an increase in crude oil sales revenues.

		On various dates between March and August of 2002, the Company hedged a total of 60,000 net barrels per month for the January 2003 through August 2003 period with Shell Trading Company (“Shell”) using a swap with various settlement amounts that averaged $24.78 per barrel. On January 16, 2003, the Company hedged 60,000 net barrels per month with Shell for the September 2003 through December 2003 period using a swap with a settlement amount of $25.63 per barrel. On February 26, 2003, the Company hedged another 40,000 net barrels per month with Shell for the January 2004 through December 2004 period using various swaps with an average settlement amount of $25.25 per barrel.

		On September 19, 2003, the Company hedged an additional 20,000 net barrels per month with Shell for October 2003 through December 2003 with an average settlement amount of $29.68. 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 price of $26.78 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 of $4,432,000 for the twelve months ended December 31, 2003 under hedging contracts. Unrealized losses of $7,407,000 at December 31, 2003 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 $5,313,000 of the unrealized loss.

6.		Long-Term Debt:

		A summary of the Company’s debt (including accrued unpaid interest) follows (in thousands):

		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). The amended borrowing base under the Tranche A facility is $80 million. 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.

		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 (.5%) percent 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 $6 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. Although not required until March 31, 2004, the Company was in compliance with the amended senior bank covenants as of December 31, 2003. The Fortis/Bank One Credit Agreement is collateralized by a first lien on substantially all of the assets of the Company.

		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 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. As of December 31, 2003, the outstanding aggregate balance on these notes was approximately $1,730,000.

7.		Income Taxes:

		In 2003, no income tax provision 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 December 31, 2003 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 are 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.

8.		Commitments and Contingencies:

		401(k) Plan – The Company provides a voluntary 401(k) employee savings plan which 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 $249,000 were made by the Company during the year ended December 31, 2003.

		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 and cash flows.

		Employment Agreements – The Company has employment agreements with certain employees of the Company, which provide for payment to the employees upon termination following a change in control.

		Lease Sale – On July 31, 2003, the Company entered into a Purchase, Sale and Exploration Agreement with Stone Energy Corporation (“Stone”) to sell 51% or 46,920 net acres of its undeveloped deep gas rights to Stone for $5 million cash. Effective September 1, 2003, the sale of the Company’s deep gas rights closed with Stone. At closing, the Company assigned 39,642 net acres of the total 46,920 net acres to Stone. The Company will have until January 9, 2004 (with an extension until March 31, 2004) to deliver the remaining 7,278 net acres. If the remaining 7,278 net acres are not delivered by January 9, 2004 (or the March 31, 2004 extension), the Company’s options are to pay $106.56 per net acre ($773,000) to Stone or to assign from its remaining 49% working interest additional interests up to 7,278 net acres to Stone. The Company recorded a gain from the sale of its deep rights of $4,227,000 in the third quarter of 2003 to reflect the 39,642 net acres sold to Stone.

9.		Stock Options:

		1988 Stock Option Plan – On August 25, 1988, the Company’s Board of Directors adopted an incentive stock option plan (the “1988 Plan”) for the benefit of key employees and directors of the Company. A total of 21,280 shares of common stock are reserved for issuance under the 1988 Plan.

		1997 Stock Option Plan – On April 30, 1997, the Company’s Board of Directors adopted an incentive stock option plan (the “1997 Plan”) for the benefit of key employees and directors of the Company. The Company reserved 50,000 shares for grant under the 1997 Plan.

		A summary of option grants, exercises and average exercise prices under both the 1988 Plan and the 1997 Plan is presented below:

10.		Oil and Gas Producing Activities:

		Major Customers – Sales to the following companies represented 10% or more of the Company’s revenues, excluding effects of hedging, (in thousands):