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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 2004

For the transition period from              to             

Commission file number 0-16203

Delta Petroleum Corporation

(Exact name of registrant as specified in its charter)

(303) 293-9133

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

39,349,000 shares of common stock $.01 par value were outstanding as of November 5, 2004.

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INDEX

The terms “Delta,” “Company,” “we,” “our,” and “us” refer to Delta Petroleum Corporation unless the context suggests otherwise.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

See accompanying notes to consolidated financial statements.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

See accompanying notes to consolidated financial statements.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Consolidated Statement of Stockholders’ Equity and Comprehensive Income

(Unaudited)

See accompanying notes to consolidated financial statements.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

See accompanying notes to consolidated financial statements.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three Months Ended September 30, 2004 and 2003

(Unaudited)

(1) Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to Form 10-Q and, in accordance with those rules, do not include all the information and notes required by generally accepted accounting principles for complete financial statements. As a result, these unaudited consolidated financial statements should be read in conjunction with the Company’s audited consolidated financial statements and notes thereto filed with the Company’s most recent annual report on Form 10-K. In the opinion of management, all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the financial position of the Company and the results of its operations have been included. Operating results for interim periods are not necessarily indicative of the results that may be expected for the complete fiscal year. For a more complete understanding of the Company’s operations and financial position, reference is made to the consolidated financial statements of the Company, and related notes thereto, filed with the Company’s annual report on Form 10-K for the year ended June 30, 2004, previously filed with the Securities and Exchange Commission.

(2) Nature of Organization

Delta Petroleum Corporation (“Delta”) was organized December 21, 1984 and is principally engaged in acquiring, exploring, developing and producing oil and gas properties. The Company owns interests in developed and undeveloped oil and gas properties in federal units offshore California, near Santa Barbara, and developed and undeveloped oil and gas properties in the continental United States.

At June 30, 2004 the Company owned 4,277,977 shares of the common stock of Amber Resources Company (“Amber”), representing 91.68% of the outstanding common stock of Amber. Amber is a public company that owns undeveloped oil and gas properties in federal units offshore California, near Santa Barbara.

On February 19, 2002, the Company acquired 100% of the outstanding shares of Piper Petroleum Company (“Piper”), a privately owned oil and gas company headquartered in Fort Worth, Texas. Piper was merged into a subsidiary wholly owned by Delta.

The Company’s results of operations are substantially dependent on the price received for its crude oil and natural gas products and the results of our exploration and development activities. Prices for these products are subject to fluctuations in response to changes in supply, market uncertainty and political instability.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three Months Ended September 30, 2004 and 2003

(Unaudited)

(3) Summary of Significant Accounting Policies

Principles of Consolidation and Basis of Presentation

The consolidated financial statements include the accounts of Delta, Amber and Piper (collectively, the Company). All intercompany balances and transactions have been eliminated in consolidation. As Amber is in a net shareholders’ deficit position for the periods presented, the Company has recognized 100% of Amber’s earnings/losses for all periods. Certain reclassifications have been made to amounts reported in previous years to conform to the 2004 presentation.

In March 2004, the Company acquired a 50% interest in Big Dog Drilling, LLC (“BDDC”) and a 50% interest in Shark Trucking Company, LLC (“STC”). Delta controls both entities and has consolidated the activities of both BDDC and STC in fiscal 2005.

Cash Equivalents

Cash equivalents consist of money market funds. The Company considers all highly liquid investments with maturities at date of acquisition of three months or less to be cash equivalents.

Marketable Securities

The Company classifies its investment securities as available-for-sale securities. Pursuant to Statement of Financial Accounting Standards No. 115 (SFAS 115), such securities are measured at fair market value in the financial statements with unrealized gains or losses recorded in other comprehensive income. At the time securities are sold or otherwise disposed of, gains or losses are included in earnings.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three Months Ended September 30, 2004 and 2003

(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

Inventories

Inventories consist of pipe and other production equipment. Inventories are stated at the lower of cost (principally first-in, first-out) or estimated net realizable value.

Revenue Recognition

Revenues are recognized when title to the products transfer to the purchaser. The Company follows the “sales method” of accounting for its natural gas and crude oil revenue, so that the Company recognizes sales revenue on all natural gas or crude oil sold to its purchasers, regardless of whether the sales are proportionate to the Company’s ownership in the property. A receivable or liability is recognized only to the extent that the Company has an imbalance on a specific property greater than the expected remaining proved reserves. As of September 30, 2004 and 2003, the Company’s aggregate natural gas and crude oil imbalances were not material to its consolidated financial statements.

Property and Equipment

The Company accounts for its natural gas and crude oil exploration and development activities under the successful efforts method of accounting. Under such method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the units-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis and any impairment in value is charged to expense. If the unproved properties are determined to be productive, the related costs are transferred to proved gas and oil properties. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain or loss.

Depreciation and depletion of capitalized acquisition, exploration and development costs is computed on the units-of-production method by individual fields as the related proved reserves are produced.

Other property and equipment are recorded at cost or estimated fair value upon acquisition and depreciated using the straight-line method over their estimated useful lives.

Certain of the Company’s oil and gas activities are conducted through partnerships and joint ventures. The Company includes its proportionate share of assets, liabilities, revenues and expenses from these entities in its consolidated financial statements. Partnership net assets represent the Company’s share of net working capital in such entities.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three Months Ended September 30, 2004 and 2003

(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

Impairment of Long-Lived Assets

Statement of Financial Accounting Standards No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144) requires that long-lived assets be reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable.

Estimates of expected future cash flows represent management’s best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions recognized in accordance with SFAS No. 144 are permanent and may not be restored in the future.

The Company assesses developed properties on an individual field basis for impairment on at least an annual basis. For developed properties, the review consists of a comparison of the carrying value of the asset with the asset’s expected future undiscounted cash flows without interest costs. As a result of such assessment, the Company recorded no impairment provision attributable to certain producing properties for the three months ended September 30, 2004 and 2003.

For undeveloped properties, the need for an impairment reserve is based on the Company’s plans for future development and other activities impacting the life of the property and the ability of the Company to recover its investment. When the Company believes the costs of the undeveloped property are no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property. As a result of such assessment, the Company recorded no impairment provision attributable to certain undeveloped properties for the three months ended September 30, 2004 and 2003.

Asset Retirement Obligations

In July 2001, the Financial Accounting Standards Board approved for issuance SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of a liability for retirement obligations of acquired assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on July 1, 2002 and recorded a cumulative effect of a change in accounting principle on prior years of $20,000, net of tax effects, related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligations, and corresponding increase in the carrying amount of the related long-lived assets, been recorded when incurred. The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells. The Company has no obligation to provide for the retirement of most of its offshore properties as the obligations remained with the seller. The following is a reconciliation of the change in the Company’s asset retirement obligations from June 30, 2004 to September 30, 2004 (amounts in thousands).

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three Months Ended September 30, 2004 and 2003

(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

Asset Retirement Obligations, Continued

Comprehensive Income

Comprehensive income includes all changes in equity during a period. The components of comprehensive income for the three months ended September 30, 2004 and 2003 are as follows:

Derivative Financial Instruments

The Company periodically enters into commodity derivative contracts and fixed-price physical contracts to manage its exposure to oil and natural gas price volatility. The Company primarily utilizes future contracts, swaps or options which are generally placed with major financial institutions or with counterparties of high credit quality that the Company believes are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural futures which have a high degree of historical correlation with actual prices received by the Company.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three Months Ended September 30, 2004 and 2003

(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

In June 1998, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities.” SFAS 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. It also requires that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of Other Comprehensive Income and be reclassified into earnings in the same period or periods during which the hedged forecasted transaction affects earnings.

During September, the Company entered into a costless collar West Texas Intermediate crude oil derivative contract for the period that begins October 1, 2004 and ends June 30, 2005. The derivative contract covers 40,000 barrels of oil per month, with a minimum price of $35.00 per barrel and a maximum price of $50.80 per barrel. In addition, the Company entered into a costless collar Henry Hub natural gas derivative contract for the period that begins January 1, 2005 and ends June 30, 2005. This derivative contract covers 10,000 million BTU’s (mmBtu) of gas per day, with a price range of $5.00 to $9.25 per mmBtu. Together, these derivative contracts cover approximately 40% of the Company’s total daily production. The fair value of the derivative contracts at September 30, 2004 was a liability to the Company of $587,000.

The realized net losses from hedging activities were zero and $312,000 for the three months ended September 30, 2004 and 2003, respectively.

Stock Option Plans

The Company accounts for its stock option plans in accordance with the provisions of Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. As such, compensation expense was recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. In December, 2002 the FASB issued SFAS No. 148, “Accounting for Stock-based Compensation-Transition and Disclosure.” SFAS 148 amends FASB Statement No. 123, “Accounting for Stock-Based Compensation” to provide alternative methods of transition for a voluntary change to the fair-value based method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on the reported results. The provisions of SFAS 148 has no material impact on the Company, as we do not plan to adopt the fair-value method of accounting for stock options at the current time. Accordingly, no compensation cost is recognized for options granted at a price equal to or greater than the fair market value of the common stock.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three Months Ended September 30, 2004 and 2003

(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

Had compensation cost for the Company’s stock-based compensation plan been determined using the fair value of the options at the grant date, the Company’s net income (loss) for the three months ended September 30, 2004 and 2003 would have been as follows:

Income Taxes

The Company uses the asset and liability method of accounting for income taxes as set forth in Statement of Financial Accounting Standards No. 109 (SFAS No. 109), Accounting for Income Taxes. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis and net operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted income tax rates expected to apply to taxable income in the years in which those differences are expected to be recovered or settled. Under SFAS No. 109, the effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three Months Ended September 30, 2004 and 2003

(Unaudited)

(3) Summary of Significant Accounting Policies, Continued

Earnings (Loss) per Share

Basic earnings (loss) per share is computed by dividing net earnings (loss) attributed to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares. Diluted earnings (loss) per share is computed by adjusting the average number of common shares outstanding for the dilutive effect, if any, of convertible preferred stock, stock options and warrants. See footnote disclosure 8.

Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles 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. Significant estimates made by management impact oil and gas reserves, bad debts, oil and gas properties, depletion and impairment, drilling and lease operating expense accruals, income taxes, derivatives, asset retirement obligations, contingencies and litigation. Actual results could differ from these estimates.

(4) Oil and Gas Properties

Unproved Undeveloped Offshore California Properties

The Company has ownership interests ranging from 2.49% to 75% in five unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $10.9 million, at September 30, 2004. These property interests are located in proximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. Preliminary exploration efforts on these properties have occurred and the existence of substantial quantities of hydrocarbons has been indicated. The recovery of the Company’s investment in these properties will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three Months Ended September 30, 2004 and 2003

(Unaudited)

(4) Oil and Gas Properties, Continued

Based on indications of levels of hydrocarbons present from drilling operations conducted in the past, the Company believes the fair values of its property interests are in excess of their carrying values at September 30, 2004 and that no impairment in the carrying values has occurred. Pursuant to a ruling in California v. Norton, later affirmed by the 9th Circuit Court of Appeals, the U.S. Government is required to make a consistency determination relating to our 1999 lease suspension requests under a 1990 amendment to the Coastal Zone Management Act. In the event that there is some future adverse ruling under the Coastal Zone Management Act that we decide not to appeal or that we appeal without success, it is likely that some or all of our interests in these leases would become impaired and written off at that time. It is also possible that other events could occur during the Coastal Zone Management Act review or appellate process that would cause our interests in the leases to become impaired, and we will continuously evaluate those factors as they occur. On January 9, 2002, the Company and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of forty undeveloped federal leases, some of which are part of our Offshore California properties. See disclosure in Item 1 of Part II.

Fiscal 2005 - Acquisition

On July 1, 2004, the Company acquired certain interests in California’s Sacramento Basin and 7.5% reversionary working interest in the South Tongue interests in Washington County, Colorado from Edward Mike Davis, LLC (“Davis”) for 760,000 shares of the Company’s common stock valued at $10.4 million using the five-day closing price before and after the terms of the agreement were agreed and closed. The Company recorded a downward purchase price adjustment of approximately $500,000 related to the net profit earned between the effective date and the closing date.

On September 15, 2004, the Company acquired seven wells in Karnes County, Texas from an unrelated entity and unrelated individual for $5.0 million in cash.

Fiscal 2005 – Disposition

On August 19, 2004, the Company completed the sale of certain interests in five fields in Louisiana and South Texas previously acquired in the Alpine acquisition, which closed on June 29, 2004, to Whiting Petroleum Corporation for $18.7 million, net of certain commissions. The Company paid $8.8 million toward its credit facility from the proceeds of the sale of these properties. There was no gain or loss on this sale transaction and the net profit earned on these assets during the quarter, since the acquisition, of $729,000 has been shown in discontinued operations.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three Months Ended September 30, 2004 and 2003

(Unaudited)

(5) Long Term Debt

Bank Debt

During the quarter ended September 30, 2004, the Company had a $100 million facility with Bank of Oklahoma, U.S. Bank National Association and Hibernia National Bank (the “Banks”) which has subsequently been replaced with a new facility. At September 30, 2004, the Company had an available borrowing base of $60.9 million and was fully funded. The facility has a variable interest rate of LIBOR +1.75% to 2.85% and/or prime +.5% / -.5% based on the total debt outstanding and no current monthly commitment reduction. The loan was collateralized by substantially all of Delta’s oil and gas properties. At September 30, 2004, the Company was in compliance with its quarterly debt covenants and restrictions. See Subsequent Events footnote for information on the new credit facility established on November 5, 2004.

Maturities of long-term debt, in thousands of dollars based on contractual terms are as follows:

(6) Stockholders’ Equity

On July 12, 2004, the Company acquired its third drilling rig from an unrelated individual for 31,000 shares of the Company’s common stock valued at $461,000. The Company contributed this drilling rig to BDDC at its cost.

(7) Income Taxes

For income tax purposes, the Company has net operating loss carryforwards expiring at various dates through 2023. As a result of the acquisitions and other issuances of stock, the utilization of the net operating loss carryforwards is subject to an annual limitation by the provisions of Section 382 of the Internal Revenue Code.

The Company recognized no tax expense in the first quarter of fiscal 2005 primarily due to recognition of deferred tax assets for which a valuation allowance had previously been provided and recognized no tax benefit in fiscal 2004 because realization was not more likely than not. The remaining deferred tax asset at September 30, 2004, for which a valuation allowance has been recorded, will be recognized in the financial statements when its realization is determined to be more likely than not.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three Months Ended September 30, 2004 and 2003

(Unaudited)

(8) Earnings Per Share

The following table sets forth the computation of basic and diluted earnings per share:

(9) Reclassifications

Certain amounts in the fiscal 2004 financial statements have been reclassified to conform to the fiscal 2005 financial statement presentation.

(10) Subsequent Events

Office Lease

On November 3, 2004, the Company signed a new ten year office lease. The Company intends to move into its new office space in the Republic Plaza which is located at 370 17^th Street, 43^rd Floor, Denver, Colorado 80202 sometime in December 2004. The Company intends to sublet its existing space.

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DELTA PETROLEUM CORPORATION

AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Three Months Ended September 30, 2004 and 2003

(Unaudited)

(10) Subsequent Events, Continued

Washington County Transaction

On November 4, 2004, the Company entered into an agreement with Davis to acquire the balance of his back-in working interest and his overriding royalty interest in all of his ownership to the base of the Niobrara formation in the South Tongue interests in Washington County, Colorado. This agreement eliminates all future drilling commitments in Washington County. This includes approximately 260,000 acres of leasehold. In addition, we acquired a 100% working interest with a 70% net revenue interest in the Magers 1-9 well which is a newly drilled well in Colusa County, California. Total consideration will be 650,000 shares of the Company’s common stock valued at approximately $9.4 million.

Credit Facility

On November 5, 2004, the Company entered into a new $200 million credit facility with Bank One, NA; Bank of Oklahoma, N.A.; U.S. Bank National Association and Hibernia National Bank. The new credit facility replaces our previous $100 million credit facility with Bank of Oklahoma, U.S. Bank and Hibernia Bank. In order to obtain this facility, the Company granted first and prior liens to the lending banks on most of its oil and gas properties and the related equipment, inventory, accounts and proceeds. The credit facility has a variable interest rates of the prime rate and/or an adjusted LIBOR rate, plus 0.25% to 1.0% based on the total debt outstanding. The loan matures on November 5, 2008.

The borrowing base, which determines the amounts that the Company is allowed to borrow or have outstanding under the new credit facility has been initially set at $75 million. Subsequent determinations of the borrowing base will be made by the lending banks at least semi-annually on February 15 and August 31 of each year or as special redeterminations. If, as a result of any such reduction in the amount of the borrowing base, the total amount of the outstanding debt exceeds the amount of the borrowing base in effect, then, within 30 days after notification of the borrowing base deficiency, the Company would be required to make a mandatory payment of principal to reduce the outstanding indebtedness so that it would not exceed the borrowing base. If for any reason Delta was unable to pay the full amount of the mandatory prepayment within the requisite 30-day period, Delta would be in default of its obligations under the credit agreement.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Forward Looking Statements

The statements contained in this report which are not historical fact are “forward looking statements” that involve various important risks, uncertainties and other factors which could cause our actual results to differ materially from those expressed in such forward looking statements reported in our quarterly report on Form 10-Q. These factors include, without limitation, the risks and factors included in the following text.

Critical Accounting Policies and Estimates

The discussion and analysis of the Company’s financial condition and results of operations were based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1 to our consolidated financial statements included in our annual report on Form 10-K. In response to SEC Release No. 33-8040, “Cautionary Advice Regarding Disclosure About Critical Accounting Policies,” we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas reserves, bad debts, oil and gas properties, drilling and lease operating expense accrual, income taxes, derivatives, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of the Company’s financial statements.

Successful Efforts Method of Accounting

We account for our natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Gas and oil lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.

The application of the successful efforts method of accounting requires managerial judgment to determine proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred.

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The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of gas and oil leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when the Company is entering a new exploratory area in hopes of finding a gas and oil field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

Reserve Estimates

Estimates of gas and oil reserves, by necessity, are projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of gas and oil that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable gas and oil reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations by governmental agencies and assumptions governing future gas and oil prices, future operating costs, severance taxes, development costs and workover gas costs, all of which may in fact vary considerably from actual results. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to an extent that these reserves may be later determined to be uneconomic. For these reasons, estimates of the economically recoverable quantities of gas and oil attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows expected therefrom may vary substantially. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our gas and oil properties and/or the rate of depletion of the gas and oil properties. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. We reevaluate our reserves quarterly.

Impairment of Gas and Oil Properties

We review our oil and gas properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. We estimate the expected future cash flows of our proved properties and compare such future cash flows to the carrying amount of the proved properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and gas properties to their fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.

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Given the complexities associated with gas and oil reserve estimates and the history of price volatility in the gas and oil markets, events may arise that would require the Company to record an impairment of the recorded book values associated with gas and oil properties. The Company did not record an impairment during the three months ended September 30, 2004 and 2003.

Commodity Derivative Instruments and Hedging Activities

We periodically enter into commodity derivative contracts and fixed-price physical contracts to manage our exposure to oil and natural gas price volatility. We primarily utilize future contracts, swaps or options, which are generally placed with major financial institutions or with counterparties of high credit quality that we believe are minimal credit risks. The oil and natural gas reference prices of these commodity derivatives contracts are based upon crude oil and natural gas futures, which have a high degree of historical correlation with actual prices we receive.

On January 1, 2001, we adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” Under SFAS No. 133 all derivative instruments are recorded on the balance sheet at fair value. Changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying cash flow hedges, the gain or loss on the derivative is deferred in accumulated other comprehensive income (loss) to the extent the hedge is effective. For qualifying fair value hedges, the gain or loss on the derivative is offset by related results of the hedged item in the income statement. Gains and losses on hedging instruments included in accumulated other comprehensive income (loss) are reclassified to oil and natural gas sales revenue in the period that the related production is delivered. Derivative contracts that do not qualify for hedge accounting treatment are recorded as derivative assets and liabilities at market value in the consolidated balance sheet, and the associated unrealized gains and losses are recorded as current expense or income in the consolidated statements of income. While such derivative contracts do not qualify for hedge accounting, management believes these contracts can be utilized as an effective component of commodity price risk management activities.

Asset Retirement Obligation

We account for our asset retirement obligations under SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record the fair value of a liability for retirement obligations of acquired assets. SFAS No. 143 is effective for fiscal years beginning after June 15, 2002. The Company adopted SFAS No. 143 on July 1, 2002 and recorded a cumulative effect of a change in accounting principle on prior years related to the depreciation and accretion expense that would have been reported had the fair value of the asset retirement obligations, and corresponding increase in the carrying amount of the related long-lived assets, been recorded when incurred. The Company’s asset retirement obligations arise from the plugging and abandonment liabilities for its oil and gas wells.

Liquidity and Capital Resources

Liquidity is a measure of a company’s ability to access cash. We have historically addressed our long-term liquidity requirements through the issuance of debt and equity securities when market conditions permit, and through cash provided by operating activities and sale of oil and gas properties. During fiscal 2004, we raised approximately $98 million in additional capital through the sale of our common stock and subsequent to quarter end, established a new $200 million credit facility with an available borrowing base of $75 million. The prices we receive for future oil and natural gas production and the level of production have significant impacts on operating cash flows. We are unable to predict with any degree of certainty the prices we will receive for our future oil and gas production.

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We continue to examine alternative sources of long-term capital, including bank borrowings, the issuance of debt instruments, the sale of common stock, the sales of non-strategic assets, and joint venture financing. Availability of these sources of capital and, therefore, our ability to execute our operating strategy will depend upon a number of factors, some of which are beyond our control.

We believe that borrowings under the Revolving Credit Facility, projected operating cash flows and cash on hand will be sufficient to meet the requirements of our business. However, future cash flows are subject to a number of variables including the level of production and oil and natural gas prices. We cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures or that increased capital expenditures will not be undertaken. Actual levels of capital expenditures may vary significantly due to a variety of factors, including but not limited to, drilling results, product pricing and future acquisition and divestitures of properties.

Company Acquisitions and Growth

On July 1, 2004, we acquired certain interests in California’s Sacramento Basin and a 7.5% reversionary working interest in the South Tongue interests in Washington County, Colorado from Edward Mike Davis, LLC (“Davis”) for 760,000 shares of our common stock valued at $10.4 million. We recorded a downward purchase price adjustment of approximately $500,000 related to the net profit earned between the effective date and the closing date.

On September 15, 2004, we acquired seven wells in Karnes County, Texas from an unrelated entity and an unrelated individual for $5.0 million in cash.

Cashflow Provided by Operations

Our cashflow from operating activities decreased 34% to $3.3 million for the three months ended September 30, 2004 compared to $5.0 million for the same period a year earlier. This decrease is primarily the result of payments made to establish an inventory of drilling equipment and reductions in accounts payable and accrued liabilities related to a significant increase in drilling activity.

Capital and Exploration Expenditures and Financing

Our capital and exploration expenditures and sources of financing for the three months ended September 30, 2004 and 2003 are as follows:

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We anticipate our capital and exploration expenditures to range between $60 and $80 million for fiscal 2005. The timing of most of our capital expenditures is discretionary.

Sale of Oil and Gas Properties - Discontinued Operations

On August 19, 2004, we completed the sale of our interests in five fields in Louisiana and South Texas previously acquired in the Alpine acquisition, which closed on June 29, 2004, to Whiting Petroleum Corporation for $18.7 million, net of commission. We paid $8.8 million on our credit facility balance from the sale of these properties. No gain or loss was recognized on this transaction.

Contractual and Long Term Debt Obligations

Credit Facility

On November 5, 2004, we entered into a new $200 million credit facility with Bank One, NA; Bank of Oklahoma, N.A.; U.S. Bank National Association and Hibernia National Bank. The new credit facility replaces our previous $100 million credit facility with Bank of Oklahoma, U.S. Bank and Hibernia Bank. In order to obtain this facility, we granted first and prior liens to the lending banks on most of our oil and gas properties and the related equipment, inventory, accounts and proceeds. The credit facility has variable interest rate of the prime rate and/or an adjusted LIBOR rate, plus 0.25% to 1.0% based on the total debt outstanding. The loan matures on November 5, 2008.

Our borrowing base, which determines the amounts that we are allowed to borrow or have outstanding under the new credit facility, has been initially set at $75 million. Subsequent determinations of our borrowing base will be made by the lending banks at least semi-annually on February 15 and August 31 of each year or as special redeterminations. If, as a result of any reduction in the amount of our borrowing base, the total amount of our outstanding debt were to exceed the amount of the borrowing base in effect, then, within 30 days after we are notified of the borrowing base deficiency, we would be required to make a mandatory payment of principal to reduce our outstanding indebtedness so that it would not exceed our borrowing base. If for any reason we were unable to pay the full amount of the mandatory prepayment within the requisite 30-day period, we would be in default of our obligations under our credit agreement.

The credit facility includes terms and covenants that place limitations on certain types of activities, including restrictions or requirements with respect to additional debt, liens, asset sales, hedging activities, investments, dividends, mergers and acquisitions, and includes financial covenants.

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Under certain conditions amounts outstanding under the credit facility may be accelerated. Bankruptcy and insolvency events with respect to us or certain of its subsidiaries will result in an automatic acceleration of the indebtedness under the credit facility. Subject to notice and cure periods in certain cases, other events of default under the credit facility will result in acceleration of the indebtedness at the option of the lending banks. Such other events of default include non-payment, breach of warranty, non-performance of obligations under the credit facility (including financial covenants), default on other indebtedness, certain pension plan events, certain adverse judgments, change of control, and a failure of the liens securing the credit facility.

Our credit facility in effect as of September 30, 2004 with Bank of Oklahoma, U.S. Bank and Hibernia Bank allowed us to borrow, repay and re-borrow amounts, up to a maximum amount of $100 million. This facility was secured by a first and prior lien to the lending banks on most of our oil and gas properties, certain related equipment, oil and gas inventory, and certain bank accounts and proceeds. Our borrowing base, which determined the amount that we were allowed to borrow or have outstanding under our credit facility, was $60.5 million as of September 30, 2004.

Other Contractual Obligations

Our abandonment retirement obligation arises from the plugging and abandonment liabilities for our oil and gas wells. The majority of this obligation will not occur over the next five years.

Our corporate office in Denver, Colorado is under an operating lease which will expire in fiscal 2009. Our average yearly payments approximate $310,000. We have additional operating lease commitments which represent office equipment leases and short term debt obligations primarily relating to field vehicles and equipment. Subsequent to year end, we entered into a new office lease and will be moving our corporate office in December 2004.

Results of Operations

The following discussion and analysis relates to items that have affected our results of operations for the three months ended September 30, 2004 and 2003. This analysis should be read in conjunction with our consolidated financial statements and accompanying notes included in this Form 10-Q.

Fiscal 2004 Compared to Fiscal 2003

Net income. Net income increased $2.5 million to $3.9 million for the three months ended September 30, 2004, an increase of 189% as compared to $1.4 million for the same period a year earlier. This increase was primarily due to an 81% increase in production from the same period a year ago relating to acquisitions completed during fiscal 2004, the development of undeveloped properties associated with these acquisitions and an increase in average oil and natural gas prices received by Delta.

Revenue. During three months ended September 30, 2004, oil and natural gas revenue from continuing operations increased 172% to $19.2 million, as compared to $7.1 million for the same period a year earlier. The increase was the result of (i) average onshore gas prices received during the quarter of $5.45 per thousand cubic feet (Mcf )compared to $4.19 per Mcf for the same period a year ago, (ii) an increase in average onshore oil price received during the quarter of $42.27 per barrel compared to $27.26 per barrel for the same period a year earlier and (iii) an 81% increase in average daily production during the quarter compared to the same period a year earlier previously discussed above.

Cash payments required on our hedging activities impacted revenues during the three months ended September 30, 2003 in the amount of $312,000.

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Production volumes, average prices received and cost per equivalent Mcf for the three months ended September 30, 2004 and 2003 are as follows: