S-1/A 1 s1amend3.txt DELTA PETROLEUM CORPORATION S-1 AMEND 3 As Filed With the Securities and Exchange Commission on November 30, 2001 Registration Statement No.333-59898 ============================================================================= UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 -------- FORM S-1/A AMENDMENT NO. 3 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 DELTA PETROLEUM CORPORATION (Name of small business issuer in its charter) Colorado 1311 84-1060803 (State or jurisdiction (Primary Standard (I.R.S. Employer of incorporation or Industrial Code Number) Identification Number) organization) 555 17th Street, Suite 3310 Denver, Colorado 80202 (303) 293-9133 (Address and telephone number of issuer's principal executive offices) Roger A. Parker, President/CEO 555 17th Street, Suite 3310 Denver, Colorado 80202 (303) 293-9133 (Name, address and telephone number of agent for service) Approximate date of proposed sale to public: As soon as the registration statement is effective. If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. [x] If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. [ ] The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine. CALCULATION OF REGISTRATION FEE ============================================================================= Proposed Estimated Maximum Title of Each offering Aggregate Amount of Class of Securities Amount to be Price Offering Registration to be Registered Registered(1) Per Unit(2) Price Fee ----------------------------------------------------------------------------- Common Stock, $.01 par value 6,000,000 $4.575 $27,450,000 $6,862.50 Common Stock 500,000 $4.575 $ 2,287,500 $ 571.88 underlying Selling Shareholder Warrants TOTAL $7,434.38(3) ============================================================================= (1) In the event of a stock split, stock dividend or similar transaction involving our common stock, in order to prevent dilution, the number of shares registered shall automatically be increased to cover the additional shares in accordance with Rule 416(a) under the Securities Act of 1933, as amended (the "Securities Act"). (2) In accordance with Rule 457(c), the aggregate offering price of our stock is estimated solely for calculating the registration fees due for this filing. This estimate is based on the average of the high and low sales price of our stock reported by the Nasdaq Small-Cap Market on April 27, 2001, which was $4.575 per share. In accordance with Rule 457(g), the shares issuable upon the exercise of outstanding warrants are determined by the higher of (I) the exercise price of the warrants and options, (ii) the offering price of the common stock in the registration statement, or (iii) the average sales price of the common stock as determined by 457 (c). (3) Filing fees of $17,819.45 were paid by Delta Petroleum Corporation in connection with a Form S-1 Registration Statement, file number 333-47414, which was amended on March 20, 2001, to become a Form S-3 Registration Statement and to remove the securities included in this Registration Statement. Pursuant to Rule 457(p), the filing fee is being paid by applying a portion of the $17,819.45 paid in connection with the prior Form S-1 Registration Statement. PROSPECTUS SUBJECT TO COMPLETION DATED NOVEMBER __, 2001 ---------------------------------------------------------------------------- Up to 6,500,000 Shares Delta Petroleum Corporation Common Stock ---------------------------- Swartz Private Equity LLC may use this prospectus in connection with sales of up to 6,500,000 shares of the common stock of Delta Petroleum ("we," "us" or "our") under our investment agreement with Swartz. Trading Symbol NASDAQ Small Cap Market "DPTR" ----------------------------------------------------------------------------- Consider carefully the risk factors beginning on page 5 in this prospectus. ----------------------------------------------------------------------------- Swartz may sell the common stock at prices and on terms determined by the market, in negotiated transactions or through underwriters. Swartz, in addition to being a selling shareholder, is also considered an "underwriter" within the meaning of the Securities Act in connection with its sales of our common stock. We will receive proceeds from Swartz under our investment agreement with Swartz. The information in this prospectus is not complete and may be changed. Neither we nor Swartz may sell these securities until the registration statement filed with the Securities and Exchange Commission is declared effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted. Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense. This prospectus includes certain forward-looking statements with respect to our anticipated future performance. Actual results could differ materially from those in such forward-looking statements. Therefore, no assurances can be given that the results in such forward-looking statements will be achieved. Important factors that could cause our actual results to differ from those contained in such forward-looking statements include, among others, those factors set forth under the section entitled "Risk Factors" contained herein. The date of this prospectus is November___, 2001 Table of Contents Part I Table of Contents...................................................... i Prospectus Summary .................................................... 1 Risk Factors........................................................... 2 Use of Proceeds ....................................................... 8 Determination of Offering Price ....................................... 8 Information with Respect to Delta ..................................... 9 Description of Business ......................................... 10 Description of Property ......................................... 15 Legal Proceedings ............................................... 35 Common Equity Securities ........................................ 35 Financial Data .................................................. 36 Management's Discussion and Analysis or Plan of Operation ....... 37 Directors, Executive Officers, Promoters and Control Persons .... 56 Executive Compensation .......................................... 59 Security Ownership of Certain Beneficial Owners and Management .. 63 Certain Relationships and Related Party Transactions ............ 66 Selling Security Holder ............................................... 70 Plan of Distribution .................................................. 77 Description of Securities ............................................. 79 Interests of Named Experts and Counsel ................................ 79 Commission Position on Indemnification for Securities Act Liabilities ........................................... 80 Financial Statements .................................................. F-1 -i- PROSPECTUS SUMMARY The following is a summary of the pertinent information regarding this offering. This summary is qualified in its entirety by the more detailed information and financial statements and related notes appearing elsewhere in this prospectus. This prospectus should be read in its entirety, as this summary does not constitute a complete recitation of facts necessary to make an investment decision. Delta ----- We are a Colorado corporation organized on December 21, 1984. We maintain our principal executive offices at Suite 3310, 555 Seventeenth Street, Denver, Colorado 80202, and our telephone number is (303) 293-9133. Our common stock is listed on Nasdaq Small-Cap Market under the symbol DPTR. We are engaged in the acquisition, exploration, development and production of oil and gas properties. During the three months ended September 30, 2001, we had total revenue of $2,443,000, operating expenses of $2,338,000 and a net loss for the three months of $244,000. During the year ended June 30, 2001 we had total revenue of $12,877,000, operating expenses of $11,199,000 and net income of $345,000. During the year ended June 30, 2000, we had total revenues of $3,576,000, operating expenses of $5,655,000 and a net loss for fiscal 2000 of $3,367,000. During the year ended June 30, 1999, we had total revenue of $1,695,000, operating expenses of $4,599,000 and a net loss for fiscal 1999 of $2,998,000. As of June 30, 2001, we had varying interests in 138 gross (22.86 net) productive wells located in eight states. We have undeveloped properties in six states, and interests in five federal units and one lease offshore California near Santa Barbara. We operate 25 of the wells and the remaining wells are operated by independent operators. The Offering ------------ Selling Security Holder Swartz Private Equity, LLC. Securities Offered A total of 6,500,000 including the following: 6,000,000 shares of common stock, plus an additional 500,000 shares issuable upon exercise of commitment warrants. Offering Price The shares being offered by this prospectus are being offered by Swartz from time to time at the then current market price. Common Stock to be 17,408,600 shares; including all of the shares Outstanding after issuable upon the exercise of warrants Offering Offering held by Swartz. We currently only have a total of 11,165,000 shares issued and outstanding, so if all of the shares that may be offered are actually sold, they would constitute about 37%. Under the terms of the Investment Agreement with Swartz, we are not obligated to sell Swartz all of the Put Shares 1 nor do we intend to sell Put Shares to Swartz unless it is beneficial to us. NASDAQ rules require shareholder approval in connection with a transaction other than a public offering involving the sale by the issuer of common stock at a price less than the greater of book or market value which, together with sales by officers, directors or substantial shareholders of the issuer, equals 20% or more of common stock. We plan to call a meeting of our shareholders within 90 days of the date of this prospectus to consider the approval of these issuances. We currently do not intend to issue any shares to Swartz under the Investment Agreement until we obtain shareholder approval. Dividend Policy We do not anticipate paying dividends on our common stock in the foreseeable future. Use of Proceeds The shares offered by this prospectus are being sold by Swartz and we will receive proceeds from Swartz under the Investment Agreement. We intend to use all such proceeds for working capital, property and equipment, capital expenditures and general corporate purposes. (See "Use of Proceeds"). RISK FACTORS Prospective investors should consider carefully, in addition to the other information in this prospectus, the following: 1. We have substantial debt obligations and shortages of funding could hurt our future operations. As the result of debt obligations that we have incurred in connection with purchases of oil and gas properties, we are obligated to make substantial monthly payments to our lenders on loans which encumber the production revenue from our oil and gas properties. Although we intend to seek outside capital to either refinance the debt or provide a cushion, at the present time we are almost totally dependent upon the revenues that we receive from our oil and gas properties to service the debt. In the event that oil and gas prices and/or production rates drop to a level that we are unable to pay the minimum principal and interest payments that are required by our debt agreements, it is likely that we would lose our interest in some or all of our properties. In addition, our level of oil and gas activities, including exploration and development of existing properties, and additional property acquisitions, will be significantly dependent on our ability to successfully conclude funding transactions. 2. We have a history of losses and we may not achieve profitability. We have incurred substantial losses from our operations over the past several years except fiscal 2001, and at September 30, 2001 we had an accumulated deficit of $22,844,000. During fiscal 2001 we had total revenues 2 of $12,877,000, operating expenses of $11,199,000 and had net income of $345,000. During the year ended June 30, 2000, we had total revenues of $3,576,000, operating expenses of $5,655,000 and a net loss for fiscal 2000 of $3,367,000. During the year ended June 30, 1999, we had total revenue of $1,695,000, operating expenses of $4,599,000 and a net loss for fiscal 1999 of $2,998,000. 3. The substantial cost to develop certain of our offshore California properties could result in a reduction in our interest in these properties or penalize us. Certain of our offshore California undeveloped properties, in which we have ownership interests ranging from 2.49% to 75%, are attributable to our interests in four of our five federal units (plus one additional lease) located offshore California near Santa Barbara. The cost to develop these properties will be very substantial. The cost to develop all of these offshore California properties in which we own a minority interest, including delineation wells, environmental mitigation, development wells, fixed platforms, fixed platform facilities, pipelines and power cables, onshore facilities and platform removal over the life of the properties (assumed to be 38 years), is estimated to be in excess of $3 billion. Our share of such costs, based on our current ownership interest, is estimated to be over $200 million. Operating expenses for the same properties over the same period of time, including platform operating costs, well maintenance and repair costs, oil, gas and water treating costs, lifting costs and pipeline transportation costs, are estimated to be approximately $3.5 billion, with our share, based on our current ownership interest, estimated to be approximately $300 million. There will be additional costs of a currently undetermined amount to develop the Rocky Point Unit. Each working interest owner will be required to pay its proportionate share of these costs based upon the amount of the interest that it owns. If we are unable to fund our share of these costs or otherwise cover them through farmouts or other arrangements then we could either forfeit our interest in certain wells or properties or suffer other penalties in the form of delayed or reduced revenues under our various unit operating agreements. 4. The development of the offshore units could be delayed or halted. The California offshore federal units have been formally approved and are regulated by the Minerals Management Service of the federal government ("MMS"). While the federal government has recently attempted to expedite the process of obtaining permits and authorizations necessary to develop the properties, there can be no assurance that it will be successful in doing so. The MMS initiated the California Offshore Oil and Gas Energy Resources (COOGER) study at the request of the local regulatory agencies of the affected Tri-Counties. The COOGER study was completed in January of 2000 and seeks to present a long-term regional perspective of potential onshore constraints that should be considered when developing existing undeveloped offshore leases. COOGER will project the economically recoverable oil and gas production from offshore leases which have not yet been developed. These projections will be utilized to assist in identifying a potential range of scenarios for developing these leases. The "worst" case scenario is that no new development of existing offshore leases would occur. If this scenario were ultimately to be adopted by governmental decision makers and the industry as the proper course of action for development, our offshore California properties would in all likelihood have little or no value. We would seek to cause the Federal 3 government to reimburse us for all money spent by us and our predecessors for leasing and other costs and/or for the value of the oil and gas reserves found on the leases through our exploration activities and those of our predecessors. Moreover, on June 22, 2001 a Federal Court ordered the MMS to set aside its approval of the suspensions of our offshore leases that were granted while the COOGER Study was being completed, and to direct suspensions, including all milestone activities, for a time sufficient for the MMS to provide the State of California with a consistency determination under federal law. On July 2, 2001 these milestones were suspended by the MMS. The ultimate outcome and effects of this litigation are not certain at the present time. 5. We will have to incur substantial costs in order to develop our reserves and we may not be able to secure funding. Relative to our financial resources, we have significant undeveloped properties in addition to those in offshore California discussed above that will require substantial costs to develop. During the year ended June 30, 2001, we participated in the drilling and completion or recompletion of seven gas wells and six non-productive wells. As of September 30, 2001, we had participated in the drilling of three offshore wells at a cost to us of approximately $450,000, and thirteen onshore wells at a cost to us of approximately $680,000. The cost of these wells either has been or will be paid out of our cash flow. All of the wells that we have drilled so far this year have been successfully completed except for two of the onshore wells which were dry holes. Although it is possible that we will participate in the drilling of additional wells during the remainder of our current fiscal year and we believe that we will participate in the drilling of additional wells during our next fiscal year, our level of oil and gas activity, including exploration and development and property acquisitions, will be to a significant extent dependent upon our ability to successfully conclude funding transactions. We expect to continue incurring costs to acquire, explore and develop oil and gas properties, and management predicts that these costs (together with general and administrative expenses) will be in excess of funds available from revenues from properties owned by us and existing cash on hand. It is anticipated that the source of funds to carry out such exploration and development will come from a combination of our sale of working interests in oil and gas leases, production revenues, sales of our securities, and funds from any funding transactions in which we might engage. 6. Current and future governmental regulations will affect our operations. Our activities are subject to extensive federal, state, and local laws and regulations controlling not only the exploration for and sale of oil, but also the possible effects of such activities on the environment. Present as well as future legislation and regulations could cause additional expenditures, restrictions and delays in our business, the extent of which cannot be predicted, and may require us to cease operations in some circumstances. In addition, the production and sale of oil and gas are subject to various governmental controls. Because federal energy policies are still uncertain and are subject to constant revisions, no prediction can be made as to the ultimate effect on us of such governmental policies and controls. 4 7. We hold only a minority interest in certain properties and, therefore, generally will not control the timing of development. We currently operate only a small portion of the wells in which we own an interest and we are dependent upon the operator of the wells that we do not operate to make most decisions concerning such things as whether or not to drill additional wells, how much production to take from such wells, or whether or not to cease operation of certain wells. Further, we do not act as operator of and, with the exception of Rocky Point, we do not own a controlling interest in any of our offshore California properties. While we, as a working interest owner, may have some voice in the decisions concerning the wells, we are not the primary decision maker concerning them. As a result, we will generally not control the timing of either the development of most of our properties or the expenditures for development. Because we are not in control, we may not be able to cause wells to be drilled even though we may have the funds with which to pay our proportionate share of the expenses of such drilling, or, alternatively, we may incur development expenses at a time when funds are not available to us. We hold only a minority interest in and do not operate many of our properties and, therefore, generally will not control the timing of development. 8. We are subject to the general risks inherent in oil and gas exploration and operations. Our business is subject to risks inherent in the exploration, development and operation of oil and gas properties, including but not limited to environmental damage, personal injury, and other occurrences that could result in our incurring substantial losses and liabilities to third parties. In our own activities, we purchase insurance against risks customarily insured against by others conducting similar activities. Nevertheless, we are not insured against all losses or liabilities which may arise from all hazards because such insurance is not available at economic rates, because the operator has not purchased such insurance, or because of other factors. Any uninsured loss could have a material adverse effect on us. 9. We have no long-term contracts to sell oil and gas. We do not have any long-term supply or similar agreements with governments or authorities for which we act as a producer. We are therefore dependent upon our ability to sell oil and gas at the prevailing well head market price. There can be no assurance that purchasers will be available or that the prices they are willing to pay will remain stable. 10. Our business is not diversified. Since all of our resources are devoted to one industry, purchasers of our common stock will be risking essentially their entire investment in a company that is focused only on oil and gas activities. 5 11. Our shareholders do not have cumulative voting rights. Holders of our common stock are not entitled to accumulate their votes for the election of directors or otherwise. Accordingly, the present shareholders will be able to elect all of our directors, and holders of the common stock offered by this prospectus will not be able to elect a representative to our Board of Directors. See "DESCRIPTION OF COMMON STOCK." 12. We do not expect to pay dividends. There can be no assurance that our proposed operations will result in sufficient revenues to enable us to operate at profitable levels or to generate a positive cash flow. For the foreseeable future, it is anticipated that any earnings which may be generated from our operations will be used to finance our growth and that dividends will not be paid to holders of common stock. See "DESCRIPTION OF COMMON STOCK." 13. We may be unable to obtain sufficient funds from the Investment Agreement with Swartz to meet our liquidity needs. Because of our current debt structure, there may be circumstances when we might need to obtain sufficient funds from the Investment Agreement with Swartz. However, the future market price and volume of trading of our common stock limits the rate at which we can obtain money under the equity line agreement with Swartz. Further, we may be unable to satisfy the conditions contained in the Investment Agreement, which would result in our inability to draw down money on a timely basis, or at all. If the price of our common stock declines, or trading volume in our common stock is low, we may be unable to obtain sufficient funds from Swartz to meet our liquidity needs. 14. The exercise of our put rights may substantially dilute the interests of other security holders. We will issue shares to Swartz upon exercise of our Put rights at a price equal to the lesser of: - the market price for each share of our common stock minus $.25; or - 91% of the market price for each share of our common stock. Accordingly, the repeated exercise of our rights to sell shares to Swartz under the Investment Agreement may result in substantial dilution to the interests of the other holders of our common stock. Depending on the price per share of our common stock during the three year period of the Investment Agreement, we may need to register additional shares for resale to access the full amount of financing available. Registering additional shares could have a further dilutive effect on the value of our common stock. If we are unable to register the additional shares of common stock, we may experience delays in, or be unable to, access some of the $20 million available under our agreement with Swartz. 6 15. The sale of material amounts of our common stock could reduce the price of our common stock and encourage short sales. If and when we exercise our rights under the Investment Agreement and sell shares of our common stock to Swartz, if and to the extent that Swartz sells the common stock, our common stock price may decrease due to the additional shares in the market. If the price of our common stock decreases, and if we decide to exercise our right to put shares to Swartz, we must issue more shares of our common stock for any given dollar amount invested by Swartz, subject to a designated minimum put price that we specify. This may encourage short sales, which could place further downward pressure on the price of our common stock. 16. We depend on key personnel. We currently only have three employees that serve in management roles, and the loss of any one of them could severely harm our business. In particular, Roger Parker is responsible for the operation of our oil and gas business, Aleron H. Larson, Jr. is responsible for other business and corporate matters, and Kevin Nanke is our chief financial officer. We don't have key man insurance on the lives of any of these individuals. 17. We allow our key personnel to purchase working interests on the same terms as us. In the past we have occasionally allowed our key employees to purchase working interests in our oil and gas properties on the same terms as us in order to provide a meaningful incentive to the employees and to align their own personal financial interests with ours in making decisions affecting the properties in which they own an interest. Specifically, - On February 12, 2001, our Board of Directors permitted Aleron H. Larson, Jr., our Chairman, Roger A. Parker, our President, and Kevin Nanke, our CFO, to purchase working interests of 5% each for Messrs. Larson and Parker and 2-1/2% for Mr. Nanke in our Cedar State gas property located in Eddy County, New Mexico and in our Ponderosa Prospect consisting of approximately 52,000 gross acres in Harding and Butte Counties, South Dakota held for exploration. These officers were authorized to purchase these interests on or before March 1, 2001 at a purchase price equivalent to the amounts paid by us for each property as reflected upon our books by delivering to us shares of Delta common stock at the February 12, 2001 closing price of $5.125 per share. Messrs. Larson and Parker each delivered 31,310 shares and Mr. Nanke delivered 15,655 shares in exchange for their interests in these properties. - Also on February 12, 2001, we granted to Messrs. Larson and Parker and Mr. Nanke the right to participate in the drilling of the Austin State #1 well in Eddy County, New Mexico by having them commit to us on February 12, 2001 (prior to any bore hole knowledge or information relating to the objective zone or zones) to pay 5% each by Messrs. Larson and Parker and 2-1/2% by Mr. Nanke of our working interest costs of drilling and completion or abandonment costs, which costs may be paid in either cash or in Delta common stock at $5.125 per share. All of these officers 7 committed to participate in the well and will be assigned their respective working interests in the well and associated spacing unit after they have been billed and paid for the interests as required. To the extent that key employees are permitted to purchase working interests in wells that are successful, they will receive benefits of ownership that might otherwise have been available to us. Conversely, to the extent that key employees purchase working interests in wells that are ultimately not successful, such purchases may result in personal financial losses for our key employees that could potentially divert their attention from our business. 18. We may choose not to exercise our put rights under the investment agreement with Swartz. If we do not Put at least $2,000,000 worth of common stock to Swartz during each one year period following the effective date of the Investment Agreement, we must pay Swartz an annual non-usage fee. This fee equals the difference between $200,000 and 10% of the value of the shares of common stock we Put to Swartz during the one year period. The fee is due and payable on the last business day of each one year period. Each annual non-usage fee is payable to Swartz, in cash, within five (5) business days of the date it accrued. We are not required to pay the annual non-usage fee to Swartz in years we have met the Put requirements. We are also not required to deliver the non-usage fee payment until Swartz has paid us for all Puts that are due. If the investment agreement is terminated, we must pay Swartz the greater of (i) the non-usage fee described above, or (ii) the difference between $200,000 and 10% of the value of the shares of common stock Put to Swartz during all Puts to date. We may terminate our right to initiate further Puts or terminate the investment agreement at any time by providing Swartz with written notice of our intention to terminate. However, any termination will not affect any other rights or obligations we have concerning the investment agreement or any related agreement. USE OF PROCEEDS The proceeds from the sale of the shares of common stock offered by this prospectus will be received directly by Swartz and we will not receive any proceeds from the sale of these shares. We will, however, receive proceeds from the sale of our common stock to Swartz. We intend to use the proceeds from the sale of common stock to Swartz and from the exercise of warrants by Swartz for working capital, property and equipment, capital expenditures and general corporate purposes. DETERMINATION OF OFFERING PRICE The shares being registered herein are being sold by Swartz, and not by us, and are therefore being sold at the market price as of the date of sale. Our common stock is traded on the Nasdaq Small-Cap Market under the symbol "DPTR." On November 13, 2001, the reported closing price for our common stock on the Nasdaq Small-Cap Market was $2.65. 8 INFORMATION WITH RESPECT TO DELTA CAUTIONARY STATEMENT FOR PURPOSES OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995 AND OTHER FEDERAL SECURITIES LAWS GENERAL. We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect us and to take advantage of the "safe harbor" protection for forward-looking statements afforded under federal securities laws. From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about us. These statements may include projections and estimates concerning the timing and success of specific projects and our future (1) income, (2) oil and gas production, (3) oil and gas reserves and reserve replacement and (4) capital spending. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "plan," "goal" or other words that convey the uncertainty of future events or outcomes. Sometimes we will specifically describe a statement as being a forward-looking statement. In addition, except for the historical information contained in this prospectus, the matters discussed in this prospectus are forward-looking statements. These statements by their nature are subject to certain risks, uncertainties and assumptions and will be influenced by various factors. Should any of the assumptions underlying a forward-looking statement prove incorrect, actual results could vary materially. We believe the factors discussed below are important factors that could cause actual results to differ materially from those expressed in a forward- looking statement made herein or elsewhere by us or on our behalf. The factors listed below are not necessarily all of the important factors. Unpredictable or unknown factors not discussed herein could also have material adverse effects on actual results of matters that are the subject of forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises. We advise our shareholders that they should (1) be aware that important factors not described below could affect the accuracy of our forward-looking statements and (2) use caution and common sense when analyzing our forward-looking statements in this document or elsewhere, and all of such forward-looking statements are qualified by this cautionary statement. - Historically, natural gas and crude oil prices have been volatile. These prices rise and fall based on changes in market demand and changes in the political, regulatory and economic climate and other factors that affect commodities markets generally and are outside of our control. - Projecting future rates of oil and gas production is inherently imprecise. Producing oil and gas reservoirs generally have declining production rates. - All of our reserve information is based on estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. There are numerous uncertainties inherent in estimating quantities of proved natural gas and oil reserves. 9 - Changes in the legal and/or regulatory environment could have a material adverse effect on our future results of operations and financial condition. Our ability to economically produce and sell our oil and gas production is affected and could possibly be restrained by a number of legal and regulatory factors, particularly with respect to our offshore California properties. - Our drilling operations are subject to various risks common in the industry, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids. OUR BUSINESS We are a Colorado corporation and were organized on December 21, 1984. We maintain our principal executive offices at Suite 3310, 555 Seventeenth Street, Denver, Colorado 80202, and our telephone number is (303) 293-9133. Our common stock is listed on NASDAQ under the symbol DPTR. We are engaged in the acquisition, exploration, development and production of oil and gas properties. As of June 30, 2001, we had varying interests in approximately 138 gross (22.86 net) productive wells located in eight states and offshore California. We have undeveloped properties in six states, and interests in five federal units and one lease offshore California near Santa Barbara. We operate 27 of the wells and the remaining wells are operated by independent operators. All wells are operated under contracts that are standard in the industry. At June 30, 2001, we estimated onshore proved reserves to be approximately 344,000 Bbls of oil and 4.68 Bcf of gas, of which approximately 342,000 Bbls of oil and 4.47 Bcf of gas were proved developed reserves. At June 30, 2001, we estimated offshore proved reserves to be approximately 1,213,000 million Bbls of oil, of which approximately 906,000 Bbls were proved developed reserves. (See "Description of Property, Item 2 herein.) At November 13, 2001, we had an authorized capital of 3,000,000 shares of $.10 par value preferred stock, of which no shares were issued, and 300,000,000 shares of $.01 par value common stock, of which 11,165,000 shares were issued and outstanding. We have outstanding warrants and options to non- employees to purchase 2,140,000 shares of common stock at prices ranging from $2.00 per share to $6.00 per share at November 13, 2001. Additionally, we have outstanding options which were granted to our officers, employees and directors under our 1993 and 2001 Incentive Plans, as amended, to purchase up to 3,429,115 shares of common stock at prices ranging from $0.05 to $9.75 per share at November 13, 2001. At November 13, 2001, we owned 4,277,977 shares of common stock of Amber Resources Company, representing 91.68% of the outstanding common stock of Amber. Amber is a public company (registered under the Securities Exchange Act of 1934) whose activities include oil and gas exploration, development, and production operations. Amber owns a portion of the interests referenced above in the producing oil and gas properties in Oklahoma and the non-producing oil and gas properties offshore California near Santa Barbara. We entered into an agreement with Amber effective October 1, 1998 which provides, in part, for the sharing of the management between the two companies and allocation of expenses related thereto. 10 During the year ended June 30, 2001, we were engaged in only one industry, namely the acquisition, exploration, development, and production of oil and gas properties and related business activities. Our oil and gas operations have been comprised primarily of production of oil and gas, drilling exploratory and development wells and related operations and acquiring and selling oil and gas properties. We, directly and through Amber, currently own producing and non-producing oil and gas interests, undeveloped leasehold interests and related assets in Arkansas, California, Colorado, Oklahoma, New Mexico, North Dakota, South Dakota, Texas and Wyoming; and interests in a producing Federal unit offshore California and undeveloped offshore Federal leases near Santa Barbara, California. We intend to continue our emphasis on the drilling of exploratory and development wells primarily in Colorado, California, New Mexico, North Dakota, Oklahoma, South Dakota, Texas, Wyoming and offshore California. We intend to drill on some of our leases (presently owned or subsequently acquired); may farm out or sell all or part of some of the leases to others; and/or we may participate in joint venture arrangements to develop certain other leases. Such transactions may be structured in any number of different manners which are in use in the oil and gas industry. Each such transaction is likely to be individually negotiated and no standard terms may be predicted. (1) Principal Products or Services and Their Markets. The principal products produced by us are crude oil and natural gas. The products are generally sold at the wellhead to purchasers in the immediate area where the product is produced. The principal markets for oil and gas are refineries and transmission companies which have facilities near our producing properties. (2) Distribution Methods of the Products or Services. Oil and natural gas produced from our wells are normally sold to purchasers as referenced in (6) below. Oil is picked up and transported by the purchaser from the wellhead. In some instances we are charged a fee for the cost of transporting the oil, which fee is deducted from or accounted for in the price paid for the oil. Natural gas wells are connected to pipelines generally owned by the natural gas purchasers. A variety of pipeline transportation charges are usually included in the calculation of the price paid for the natural gas. (3) Status of Any Publicly Announced New Product or Service. We have not made a public announcement of, and no information has otherwise become public about, a new product or industry segment requiring the investment of a material amount of our total assets. (4) Competitive Business Conditions. Oil and gas exploration and acquisition of undeveloped properties is a highly competitive and speculative business. We compete with a number of other companies, including major oil companies and other independent operators which are more experienced and which have greater financial resources. We do not hold a significant competitive position in the oil and gas industry. (5) Sources and Availability of Raw Materials and Names of Principal Suppliers. Oil and gas may be considered raw materials essential to our business. The acquisition, exploration, development, production, and sale of oil and gas are subject to many factors which are outside of our control. 11 These factors include national and international economic conditions, availability of drilling rigs, casing, pipe, and other equipment and supplies, proximity to pipelines, the supply and price of other fuels, and the regulation of prices, production, transportation, and marketing by the Department of Energy and other federal and state governmental authorities. (6) Dependence on One or a Few Major Customers. During our fiscal year ended June 30, 2001, we sold 59% of our oil to Gulf Mark Energy, Inc., an unaffiliated oil and gas company located in Houston, Texas and 19% to Eighty Eight Oil Company. We believe that there are numerous purchasers available for our oil and the loss of either Gulf Mark Energy, Inc. or Eighty Eight Oil COmpany as customers would not have a material adverse effect on our business. We do not depend upon one or a few major customers for the sale of oil and gas as of the date of this report. The loss of any one or several customers would not have a material adverse effect on our business. (7) Patents, Trademarks, Licenses, Franchises, Concessions, Royalty Agreements or Labor Contracts. We do not own any patents, trademarks, licenses, franchises, concessions, or royalty agreements except oil and gas interests acquired from industry participants, private landowners and state and federal governments. We are not a party to any labor contracts. (8) Need for Any Governmental Approval of Principal Products or Services. Except that we must obtain certain permits and other approvals from various governmental agencies prior to drilling wells and producing oil and/or natural gas, we do not need to obtain governmental approval of our principal products or services. (9) Government Regulation of the Oil and Gas Industry. General. ------- Our business is affected by numerous governmental laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the energy industry. Changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations. We believe that our operations comply in all material respects with all applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry. The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing. Environmental Regulation. ------------------------ Together with other companies in the industries in which we operate, our operations are subject to numerous federal, state, and local 12 environmental laws and regulations concerning our oil and gas operations, products and other activities. In particular, these laws and regulations require the acquisition of permits, restrict the type, quantities, and concentration of various substances that can be released into the environment, limit or prohibit activities on certain lands lying within wilderness, wetlands and other protected areas, regulate the generation, handling, storage, transportation, disposal and treatment of waste materials and impose criminal or civil liabilities for pollution resulting from oil, natural gas and petrochemical operations. Governmental approvals and permits are currently, and may in the future be, required in connection with our operations. The duration and success of obtaining such approvals are contingent upon a significant number of variables, many of which are not within our control. To the extent such approvals are required and not obtained, operations may be delayed or curtailed, or we may be prohibited from proceeding with planned exploration or operation of facilities. Environmental laws and regulations are expected to have an increasing impact on our operations, although it is impossible to predict accurately the effect of future developments in such laws and regulations on our future earnings and operations. Some risk of environmental costs and liabilities is inherent in our operations and products, as it is with other companies engaged in similar businesses, and there can be no assurance that material costs and liabilities will not be incurred. However, we do not currently expect any material adverse effect upon our results of operations or financial position as a result of compliance with such laws and regulations. Although future environmental obligations are not expected to have a material adverse effect on our results of operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur substantial environmental liabilities or costs. Hazardous Substances and Waste Disposal. --------------------------------------- We currently own or lease interests in numerous properties that have been used for many years for natural gas and crude oil production. Although the operator of such properties may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us. In addition, some of these properties have been operated by third parties over whom we had no control. The U.S. Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the management and disposal of wastes. Although CERCLA currently excludes petroleum from cleanup liability, many state laws affecting our operations impose clean-up liability regarding petroleum and petroleum related products. In addition, although RCRA currently classifies certain exploration and production wastes as "non-hazardous," such wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling 13 and disposal requirements. If such a change in legislation were to be enacted, it could have a significant impact on our operating costs, as well as the gas and oil industry in general. Oil Spills. ---------- Under the Federal Oil Pollution Act of 1990, as amended ("OPA"), (i) owners and operators of onshore facilities and pipelines, (ii) lessees or permittees of an area in which an offshore facility is located and (iii) owners and operators of tank vessels ("Responsible Parties") are strictly liable on a joint and several basis for removal costs and damages that result from a discharge of oil into the navigable waters of the United States. These damages include, for example, natural resource damages, real and personal property damages and economic losses. OPA limits the strict liability of Responsible Parties for removal costs and damages that result from a discharge of oil to $350 million in the case of onshore facilities, $75 million plus removal costs in the case of offshore facilities, and in the case of tank vessels, an amount based on gross tonnage of the vessel. However, these limits do not apply if the discharge was caused by gross negligence or willful misconduct, or by the violation of an applicable Federal safety, construction or operating regulation by the Responsible Party, its agent or subcontractor or in certain other circumstances. In addition, with respect to certain offshore facilities, OPA requires evidence of financial responsibility in an amount of up to $150 million. Tank vessels must provide such evidence in an amount based on the gross tonnage of the vessel. Failure to comply with these requirements or failure to cooperate during a spill event may subject a Responsible Party to civil or criminal enforcement actions and penalties. Under our various agreements, we have primary liability for oil spills that occur on properties for which we act as operator. With respect to properties for which we do not act as operator, we are generally liable for oil spills as a non-operating working interest owner. We do not act as operator for any of our offshore California properties. The operators of our offshore California properties are primarily liable for oil spills and are required by the Minerals Management Service of the United States Department of the Interior ("MMS") to carry certain types of insurance and to post bonds in that regard. In addition, we also carry insurance as a non-operator in the amount of $5 million onshore and $10 million offshore. There is no assurance that our insurance coverage is adequate to protect us. Offshore Production. ------------------- Offshore oil and gas operations in U.S. waters are subject to regulations of the United States Department of the Interior which currently impose strict liability upon the lessee under a Federal lease for the cost of clean-up of pollution resulting from the lessee's operations, and such lessee could be subject to possible liability for pollution damages. In the event of a serious incident of pollution, the Department of the Interior may require a lessee under Federal leases to suspend or cease operations in the affected areas. 14 (10) Research and Development. We do not engage in any research and development activities. Since our inception, we have not had any customer or government-sponsored material research activities relating to the development of any new products, services or techniques, or the improvement of existing products. (11) Environmental Protection. Because we are engaged in acquiring, operating, exploring for and developing natural resources, we are subject to various state and local provisions regarding environmental and ecological matters. Therefore, compliance with environmental laws may necessitate significant capital outlays, may materially affect our earnings potential, and could cause material changes in our proposed business. At the present time, however, these laws do not materially hinder nor adversely affect our business. Capital expenditures relating to environmental control facilities have not been material to our operation since our inception. In addition, we do not anticipate that such expenditures will be material during the fiscal year ending June 30, 2002. (12) Employees. We have five full time employees. Operators, engineers, geologists, geophysicists, landmen, pumpers, draftsmen, title attorneys and others necessary for our operations are retained on a contract or fee basis as their services are required. DESCRIPTION OF PROPERTY (a) Office Facilities. ----------------- Our offices are located at 555 Seventeenth Street, Suite 3310, Denver, Colorado 80202. We lease approximately 4,800 square feet of office space for $7,000 per month and the lease will expire in April of 2002. We subleased approximately 2,500 square feet of our space to Bion Environmental Technologies, Inc. for $4,000 per month until May 1, 2000. (b) Oil and Gas Properties. ---------------------- We own interests in oil and gas properties located primarily in Arkansas, California, Colorado, Oklahoma, New Mexico, North Dakota, South Dakota, Texas and Wyoming. Most wells from which we receive revenues are owned only partially by us. For information concerning our oil and gas production, average prices and costs, estimated oil and gas reserves and estimated future cash flows, see the tables set forth below in this section and "Notes to Financial Statements" included in this report. We did not file oil and gas reserve estimates with any federal authority or agency other than the Securities and Exchange Commission during the past three years. Principal Properties. -------------------- The following is a brief description of our principal properties: 15 Onshore: ------- California: Sacramento Basin Area --------------------------------- We have participated in three 3-D seismic survey programs located in Colusa and Yolo counties in the Sacramento Basin in California with interests ranging from 12% to 15%. These programs are operated by Slawson Exploration Company, Inc. The program areas contain approximately 90 square miles in the aggregate, upon which we have participated in the costs of collecting and processing 3-D seismic data, acquiring leases and drilling wells upon these leases. Interpretation of the 90 square miles of seismic information revealed approximately 25 drillable prospects. As of November 13, 2001, 20 wells have been drilled of which ten are now producing and one is awaiting completion. We expect to participate in the drilling of two additional wells during the remainder of calendar 2001. The area has adequate markets for the volumes of natural gas that are projected from the drilling activity in the area. Colorado. -------- Denver-Julesburg Basin. We own leasehold interests in approximately 480 gross (47 net) acres and have interests in eight gross (.77 net) wells in the Denver-Julesburg Basin producing primarily from the D-Sand and J-Sand formations. No new activity is planned for this area for the next fiscal year. Piceance Basin. We own working interests in 5 gas wells (4 net), and oil and gas leases covering approximately 3,300 net acres in the Piceance Basin in Mesa and Rio Blanco counties, Colorado. During the past fiscal year we sold eight wells and approximately 4,700 acres to another company. We are evaluating the economics and feasibility of recompleting additional zones in several of our wells. The acreage is located in the Vega Unit. Oklahoma. -------- Anadarko Basin. Directly (15 wells) and through Amber (20 wells) we own non-operating working interests in 32 natural gas wells in Oklahoma. The wells range in depth from 4,500 to 15,000 feet and produce from the Red Fork, Atoka, Morrow and Springer formations. Most of our reserves are in the Red Fork/Atoka formation. The working interests range from less than 1% to 23% and average about 7% per well. Many of the wells have estimated remaining productive lives of 10 to 20 years. Wyoming. ------- Moneta Hills. In 1997 we sold an 80% interest in our Moneta Hills project to KCS Energy ("KCS"), a subsidiary of KCS Mountain Resources, Inc. The Moneta Hills project presently consists of approximately 9,696 acres, six wells and a 13 mile gas gathering pipeline. Under the terms of the sale, KCS paid us $450,000 for the interests acquired and agreed to drill two wells to the Fort Union formation at approximately 10,000 feet. KCS will carry Delta 16 for a 20% back-in after payout interest in each of the two wells. The first well was drilled and is producing; however, KCS did not drill the second well before filing for Chapter 11 bankruptcy protection in 1999. As a result, the properties, including the plugging and abandonment obligation, were returned to Delta. Recently, Delta agreed to sell all but one well and well spacing unit to Samedan Oil Corporation with a reserved overriding royalty interest of 1% on the properties that were sold. Texas. ----- Austin Chalk Trend. We own leasehold interests in approximately 1,558 gross acres (1,111 net acres) and own substantially all of the working interests in three horizontal wells in the area encompassing the Austin Chalk Trend in Gonzales County and a small minority interest in one additional horizontal well in Zavala County, Texas. We are evaluating the economics and feasibility of re-entering one or more of these wells and drilling additional horizontal bores in other untapped zones. Duncan Slough Prospect-Matagorda County. We own an interest in three producing wells, two of which were drilled during the past fiscal year under a farmout agreement among numerous parties and operated by an unaffiliated party. The two newly drilled wells produce approximately 30,000 Mcf per day and 500 Bbls per day of condensate, respectively, as of November 13, 2001. Delta's interests in these wells are small and new drilling activity is continuing. New Mexico. ---------- East Carlsbad Field. We own interests in 13 producing wells and associated acreage in New Mexico. Current production net to the interests owned by Delta is approximately 750 Mcf per day and 25 Bbls of oil per day as of June 30, 2001. During the course of the year we participated in the drilling of three new wells on the property. Two are productive and results are not yet available on the third. We also own an additional property in Eddy County, New Mexico which currently contains one gas well which we purchased on January 22, 2001 from SAGA Petroleum Corporation for $2,700,000 in cash and common stock. North Dakota. ------------ On September 28, 2000, we completed our acquisition of a working interest in Eland, Stadium, Subdivision and Livestock fields in Stark County, North Dakota. There are a total of 20 producing wells and 5 injection wells. Current production net to the interests being acquired by Delta is approximately 300 barrels of oil equivalent per day as of September 30, 2001. South Dakota. ------------ We own a 50% interest in approximately 58,000 oil and gas leasehold acres in Harding and Butte Counties, South Dakota. We are the operator of a 17 drilling program. The first of four wells were drilled in May 2001 and do not appear to be successful. However, we are currently evaluating the geologic information to determine whether to go forward with more drilling or to attempt to sell the acreage position. Offshore: -------- Offshore Federal Waters: Santa Barbara, California Area ------------------------------------------------------- Unproved Undeveloped Properties: ------------------------------- Directly and through our subsidiary, Amber Resources Company, we own interests in five undeveloped federal units (plus one additional lease) located in federal waters offshore California near Santa Barbara. The Santa Barbara Channel and the offshore Santa Maria Basin are the seaward portions of geologically well-known onshore basins with over 90 years of production history. These offshore areas were first explored in the Santa Barbara Channel along the near shore three mile strip controlled by the state. New field discoveries in Pliocene and Miocene age reservoir sands led to exploration into the federally controlled waters of the Pacific Outer Continental Shelf ("POCS"). Eight POCS lease sales and subsequent drilling conducted between 1966 and 1989 have resulted in the discovery of an estimated two billion Bbls of oil and three trillion cubic feet of gas. Of these totals, some 869 million Bbls of oil and 819 billion cubic feet of gas have been produced and sold. However, except for our small interest in the Point Arguello Unit discussed below, we do not own any interest in any offshore California production and there no assurance that any of our undeveloped properties will ever achieve production. Most of the early offshore production was from Pliocene age sandstone reservoirs. The more recent developments are from the highly fractured zones of the Miocene age Monterey Formation. The Monterey is productive in both the Santa Barbara Channel and the offshore Santa Maria Basin. It is the principal producing horizon in the Point Arguello field, the Point Pedernales field, and the Hondo and Pescado fields in the Santa Ynez Unit. Because the Monterey is capable of relatively high productive rates, the Hondo field, which has been on production since late 1981, has already surpassed 224 million Bbls of oil production and 411 Bcf of gas production. All told, offshore fields producing from the Monterey as of the end of calendar 2000, have produced 526 million Bbls of oil and 544 Bcf of gas. California's active tectonic history over the last few million years has formed the large linear anticlinal features which trap the oil and gas. Marine seismic surveys have been used to locate and define these structures offshore. Recent seismic surveying utilizing modern 3-D seismic technology, coupled with exploratory well data, has greatly improved knowledge of the size of reserves in fields under development and in fields for which development is planned. Currently, 11 fields are producing from 18 platforms in the Santa Barbara Channel and offshore Santa Maria Basin. Implementation of extended high-angle to horizontal drilling methods is reducing the number of platforms and wells needed to develop reserves in the area. Use of these new drilling 18 methods and seismic technologies is expected to continue to improve development economics. Leasing, lease administration, development and production within the Federal POCS all fall under the Code of Federal Regulations administered by the MMS. The EPA controls disposal of effluents, such as drilling fluids and produced waters. Other Federal agencies, including the Coast Guard and the Army Corps of Engineers, also have oversight on offshore construction and operations. The first three miles seaward of the coastline are administered by each state and are known as "State Tidelands" in California. Within the State Tidelands off Santa Barbara County, the State of California, through the State Lands Commission, regulates oil and gas leases and the installation of permanent and temporary producing facilities. Because the four units in which we own interests are located in the POCS seaward of the three mile limit, leasing, drilling, and development of these units are not directly regulated by the State of California. However, to the extent that any production is transported to an on-shore facility through the state waters, our pipelines (or other transportation facilities) would be subject to California state regulations. Construction and operation of any such pipelines would require permits from the state. Additionally, all development plans must be consistent with the Federal Coastal Zone Management Act ("CZMA"). In California the decision of CZMA consistency is made by the California Coastal Commission. The Santa Barbara County Energy Division and the Board of Supervisors will have a significant impact on the method and timing of any offshore field development through its permitting and regulatory authority over the construction and operation of on-shore facilities. In addition, the Santa Barbara County Air Pollution Control District has authority in the federal waters off Santa Barbara County through the Federal Clean Air Act as amended in 1990. Each working interest owner will be required to pay its proportionate share of these costs based upon the amount of the interest that it owns. The size of our working interest in the units, other than the Rocky Point Unit, varies from 2.492% to 15.60%. Whiting Petroleum Corporation holds a working interest for us as our nominee of approximately 70% in the Rocky Point Unit. This interest is expected to be reduced if the Rocky Point Unit is included in the Point Arguello Unit and developed from existing Point Arguello platforms. We may be required to farm out all or a portion of our interests in these properties to a third party if we cannot fund our share of the development costs. There can be no assurance that we can farm out our interests on acceptable terms. These units have been formally approved and are regulated by the MMS. While the Federal Government has recently attempted to expedite the process of obtaining permits and authorizations necessary to develop the properties, there can be no assurance that it will be successful in doing so. We do not act as operator of any offshore California properties and consequently will not generally control the timing of either the development of the properties or the expenditures for development unless we choose to unilaterally propose the drilling of wells under the relevant operating agreements. 19 The MMS initiated the California Offshore Oil and Gas Energy Resources (COOGER) Study at the request of the local regulatory agencies of the three counties (Ventura, Santa Barbara and San Luis Obispo) affected by offshore oil and gas development. A private consulting firm completed the study under a contract with the MMS. The COOGER Study presents a long-term regional perspective of potential onshore constraints that should be considered when developing existing undeveloped offshore leases. The COOGER Study projects the economically recoverable oil and gas production from offshore leases which have not yet been developed. These projections are utilized to assist in identifying a potential range of scenarios for developing these leases. These scenarios are compared to the projected infrastructural, environmental and socioeconomic baselines between 1995 and 2015. No specific decisions regarding levels of offshore oil and gas development or individual projects will occur in connection with the COOGER Study. Information presented in the study is intended to be utilized as a reference document to provide the public, decision makers and industry with a broad overview of cumulative industry activities and key issues associated with a range of development scenarios. We have attempted to evaluate the scenarios that were studied with respect to properties located in the eastern and central subregions (which include the Sword Unit and the Gato Canyon Unit) and the results of such evaluation are set forth below: Scenario 1 No new development of existing offshore leases. If this scenario were ultimately to be adopted by governmental decision makers as the proper course of action for development, our offshore California properties would in all likelihood have little or no value. In this scenario we would seek to cause the Federal government to reimburse us for all money spent by us and our predecessors for leasing and other costs and for the value of the oil and gas reserves found on the leases through our exploration activities and those of our predecessors. Scenario 2 Development of existing leases, using existing onshore facilities as currently permitted, constructed and operated (whichever is less) without additional capacity. This scenario includes modifications to allow processing and transportation of oil and natural gas with different qualities. It is likely that the adoption of this scenario by the industry as the proper course of action for development would result in lower than anticipated costs, but would cause the subject properties to be developed over a significantly extended period of time. Scenario 3 Development of existing leases, using existing onshore facilities by constructing additional capacity at existing sites to handle expanded production. This scenario is currently anticipated by our management to be the most reasonable course of action although there is no assurance that this scenario will be adopted. Scenario 4 Development of existing leases after decommissioning and removal of some or all existing onshore facilities. This scenario includes new facilities, and perhaps new sites, to handle anticipated future production. Under this 20 scenario we would incur increased costs but revenues would be received more quickly. We have also evaluated our position with regard to the scenarios with respect to properties located in the northern sub-region (which includes the Lion Rock Unit and the Point Sal Unit), the results of which are as follows: Scenario 1 No new development of existing offshore leases. If this scenario were ultimately to be adopted by governmental decision makers as the proper course of action for development, our offshore California properties would in all likelihood have little or no value. In this scenario we would seek to cause the Federal government to reimburse us for all money spent by us and our predecessors for leasing and other costs and for the value of the oil and gas reserves found on the leases through our exploration activities and those of our predecessors. Scenario 2 Development of existing leases, using existing onshore facilities as currently permitted, constructed and operated (whichever is less) without additional capacity. This scenario includes modifications to allow processing and transportation of oil and natural gas with different qualities. It is likely that the adoption of this scenario by the industry as the proper course of action for development would result in lower than anticipated costs, but would cause the subject properties to be developed over a significantly extended period of time. Scenario 3 Development of existing leases, using existing onshore facilities by constructing additional capacity at existing sites to handle expanded production. This scenario is currently anticipated by our management to be the most reasonable course of action although there is no assurance that this scenario will be adopted. Scenario 4 Development of existing offshore leases, using existing onshore facilities with additional capacity or adding new facilities to handle a relatively low rate of expanded development. This scenario is similar to #3 above, but would entail increased costs for any new facilities. Scenario 5 Development of existing offshore leases, using existing onshore facilities with additional capacity or adding new facilities to handle a relatively higher rate of expanded development. Under this scenario we would incur increased costs but revenues would be received more quickly. The development plans for the various units (which have been submitted to the MMS for review) currently provide for 22 wells from one platform set in a water depth of approximately 300 feet for the Gato Canyon Unit; 63 wells from one platform set in a water depth of approximately 1,100 feet for the Sword Unit; 60 wells from one platform set in a water depth of approximately 336 feet for the Point Sal Unit; and 183 wells from two platforms for the Lion Rock Unit. On the Lion Rock Unit, platform A would be 21 set in a water depth of approximately 507 feet, and Platform B would be set in a water depth of approximately 484 feet. The reach of the deviated wells from each platform required to drain each unit falls within the reach limits now considered to be "state-of-the-art." The development plans for the Rocky Point Unit provide for the inclusion of the Rocky Point leases in the Point Arguello Unit upon which the Rocky Point leases would be drilled from existing Point Arguello platforms with extended reach drilling technology. Current Status. On October 15, 1992 the MMS directed a Suspension of Operations (SOO), effective January 1, 1993, for the POCS undeveloped leases and units. The SOO was directed for the purpose of preparing what became known as the COOGER Study. Two-thirds of the cost of the Study was funded by the participating companies in lieu of the payment of rentals on the leases. Additionally, all operations were suspended on the leases during this period. On November 12, 1999, as the COOGER Study drew to a conclusion, the MMS approved requests made by the operating companies for a Suspension of Production (SOP) status for the POCS leases and units. During the period of an SOP, the lease rentals resume and each operator is generally required to perform exploration and development activities in order to meet certain milestones set out by the MMS. The milestones that were established by the MMS for the properties in which we own an interest were established through negotiations by the MMS on behalf of the United States government and the operators on behalf of the working interest owners. We did not directly participate in these negotiations. Until recently, progress toward the milestones was monitored by the operator in quarterly reports submitted to the MMS. In February 2000 all operators completed and timely submitted to the MMS a preliminary "Description of the Proposed Project". This was the first milestone required under the SOP. Quarterly reports were also prepared and submitted for all subsequent quarters. On June 22, 2001, however, a Federal Court in the case of California v. Norton, et al. (discussed below - see "Management's Discussion and Analysis or Plan of Operation-Offshore Undeveloped Properties") ordered the MMS to set aside its approval of the suspensions of our offshore leases and to direct suspensions, including all milestone activities, for a time sufficient for the MMS to provide the State of California with a consistency determination under federal law. As a result of this order, on July 2, 2001 the MMS directed suspensions of operations for all of our offshore California leases for an indefinite period of time and suspended all of the related milestones. The ultimate outcome and effects of this litigation are not certain at the present time. In order to continue to carry out the requirements of the MMS, all operators of the units in which we own non-operating interests are prepared to meet the next milestone leading to development of the leases, but the status of the milestones is presently uncertain in light of the recent court ruling. The United States government has filed a notice of its intent to appeal the court's order in the Norton case. On May 18, 2001 (prior to the Norton decision), a revised Development and Production Plan for the Point Arguello Unit was submitted to the MMS and the California Coastal Commission ("CCC") for approval. If approved by the CCC, this plan would enable development of the Rocky Point Unit from the Point Arguello platforms that are already in existence. Under law, the CCC is typically required to make a determination as to whether or not the Plan is "consistent" with California's Coastal Plan within three months of submission, with a maximum of three months' extension (a total of 22 six months). By correspondence dated August 7, 2001, however, the Unit operator requested that the CCC suspend the consistency review for the revised Development and Production Plan since the MMS had temporarily stopped work on the processing of the plan as the result of the Norton decision. Although it currently appears likely that the CCC may require some additional supplemental information to be provided with respect to some aspects of air and water quality when its review continues, we believe that the Rocky Point Development and Production Plan that was submitted meets the requirements established by applicable federal regulations. In accordance with these regulations, the Plan includes very specific information regarding the planned activities, including a description of and schedule for the development and production activities to be performed, including plan commencement date, date of first production, total time to complete all development and production activities, and dates and sequences for drilling wells and installing facilities and equipment, and a description of the drilling vessels, platforms, pipelines and other facilities and operations located offshore which are proposed or known by the lessee (whether or not owned or operated by the lessee) to be directly related to the proposed development, including the location, size, design, and important safety, pollution prevention, and environmental monitoring features of the facilities and operations. The current Development and Production Plan calls for drilling activities to be conducted from the existing Point Arguello platforms using extended reach drilling techniques with oil and gas production to be transported through existing pipelines to existing onshore production facilities. The plan does not require the construction of new platforms, pipelines or production facilities. In accordance with applicable federal regulations, the following supporting information accompanies the Development and Production Plan: (1) geological and geophysical data and information, including: (i) a plat showing the surface location of any proposed fixed structure or well; (ii) a plat showing the surface and bottomhole locations and giving the measured and true vertical depths for each proposed well; (iii) current interpretations of relevant geological and geophysical data; (iv) current structure maps showing the surface and bottomhole location of each proposed well and the depths of expected productive formations; (v) interpreted structure sections showing the depths of expected productive formations; (vi) a bathymetric map showing surface locations of fixed structures and wells or a table of water depths at each proposed site; and (vii) a discussion of seafloor conditions including a shallow hazards analysis for proposed drilling and platform sites and pipeline routes. As required by federal regulations, the information contained in the Plan contains proposed precautionary measures, including a classification of the lease area, a contingency plan, a description of the environmental safeguards to be implemented, including an updated oil-spill response plan; and a discussion of the steps that have been or will be taken to satisfy the conditions of lease stipulations, a description of technology and reservoir engineering practices intended to increase the ultimate recovery of oil and gas, i.e., secondary, tertiary, or other enhanced recovery practices; a description of technology and recovery practices and procedures intended to assure optimum recovery of oil and gas; a discussion of the proposed drilling and completion programs; a detailed description of new or unusual technology 23 to be employed; and a brief description of the location, description, and size of any offshore and land-based operations to be conducted or contracted for as a result of the proposed activity; including the acreage required in California for facilities, rights-of-way, and easements, the means proposed for transportation of oil and gas to shore; the routes to be followed by each mode of transportation; and the estimated quantities of oil and gas to be moved along such routes; an estimate of the frequency of boat and aircraft departures and arrivals, the onshore location of terminals, and the normal routes for each mode of transportation. As required, the Plan also provides a list of the proposed drilling fluids, including components and their chemical compositions, information on the projected amounts and rates of drilling fluid and cuttings discharges, and methods of disposal, and specifies the quantities, types, and plans for disposal of other solid and liquid wastes and pollutants likely to be generated by offshore, onshore, and transport operations and, regarding any wastes which may require onshore disposal, the means of transportation to be used to bring the wastes to shore, disposal methods to be utilized, and the location of onshore waste disposal or treatment facilities. In order to comply with federal regulations, the Plan also addresses the approximate number of people and families to be added to the population of local nearshore areas as a result of the planned development, provides an estimate of significant quantities of energy and resources to be used or consumed including electricity, water, oil and gas, diesel fuel, aggregate, or other supplies which may be purchased within California, and specifies the types of contractors or vendors which will be needed, although not specifically identified, and which may place a demand on local goods and services. The Plan also identifies the source, composition, frequency, and duration of emissions of air pollutants and provides a narrative description of the existing environment with an emphasis placed on those environmental values that may be affected by the proposed action. This section of the Plan contains a description of the physical environment of the area covered by the Plan and includes data and information obtained or developed by the lessee together with other pertinent information and data available to the lessee from other sources. The environmental information and data includes a description of the aquatic biota, including fishery and marine mammal use of the lease, the significance of the lease and identifies the threatened and endangered species and their critical habitat. The Plan also addresses environmentally sensitive areas (e.g., refuges, preserves, sanctuaries, rookeries, calving grounds, coastal habitats, beaches, and areas of particular environmental concern) which may be affected by the proposed activities, the predevelopment, ambient water-column quality and temperature data for incremental depths for the areas encompassed by the plan, the physical oceanography, including ocean currents described as to prevailing direction, seasonal variations, and variations at different water depths in the lease, and describes historic weather patterns and other meteorological conditions, including storm frequency and magnitude, wave height and direction, wind direction and velocity, air temperature, visibility, freezing and icing conditions, and ambient air quality listing, where possible, the means and extremes of each. 24 The Plan further identifies other uses of the area, including military use for national security or defense, subsistence hunting and fishing, commercial fishing, recreation, shipping, and other mineral exploration or development and describes the existing and planned monitoring systems that are measuring or will measure impacts of activities on the environment in the planning area. As required, the Plan provides an assessment of the effects on the environment expected to occur as a result of implementation of the Plan, and identifies specific and cumulative impacts that may occur both onshore and offshore, and describes the measures proposed to mitigate these impacts. These impacts are quantified to the fullest extent possible including magnitude and duration and are accumulated for all activities for each of the major elements of the environment (e.g., water and biota). The Plan also provides a discussion of alternatives to the activities proposed that were considered during the development of the Plan, including a comparison of the environmental effects. As required, the Plan provides certain supporting information with respect to the projected emissions from each proposed or modified facility for each year of operation and the bases for all calculations, including, for each source, the amount of the emission by air pollutant expressed in tons per year and frequency and duration of emissions; for each proposed facility, the total amount of emissions by air pollutant expressed in tons per year, the frequency distribution of total emissions by air pollutant expressed in pounds per day and, in addition for a modified facility only, the incremental amount of total emissions by air pollutant resulting from the new or modified source(s); and a detailed description of all processes, processing equipment and storage units, including information on fuels to be burned; and a schematic drawing which identifies the location and elevation of each source. In order to continue to carry out the requirements of the MMS when they resume, all operators of the units in which we own non-operating interests are prepared to complete any studies and project planning necessary to commence development of the leases. Where additional drilling is needed, the operators will bring a mobile drilling unit to the POCS to further delineate the undeveloped oil and gas fields. In the event that the continuing delays are not acceptable to the working interest owners of the subject properties, it is possible that at least some of them will commence litigation against the federal government seeking, among other things, damages in the form of reimbursement of all amounts spent for leasing and other costs and/or for the value of any known hydrocarbons on the affected leases. Cost to Develop Offshore California Properties. The cost to develop four of the five undeveloped units (plus one lease) located offshore California, including delineation wells, environmental mitigation, development wells, fixed platforms, fixed platform facilities, pipelines and power cables, onshore facilities and platform removal over the life of the properties (assumed to be 38 years), is estimated by the partners to be in excess of $3 billion. Our share based on our current working interest of such costs over the life of the properties is estimated to be over $200 million. There will be additional costs of a currently undetermined amount to develop the Rocky Point Unit which is the fifth undeveloped unit in which we own an interest. To the extent that we do not have sufficient cash available to pay our share of expenses when they become payable under the respective operating 25 agreements, it will be necessary for us to seek funding from outside sources. Likely potential sources for such funding are currently anticipated to include (a) public and private sales of our common stock (which may result in substantial ownership dilution to existing shareholders), (b) bank debt from one or more commercial oil and gas lenders, (c) the sale of debt instruments to investors, (d) entering into farm-out arrangements with respect to one or more of our interests in the properties whereby the recipient of the farm-out would pay the full amount of our share of expenses and we would retain a carried ownership interest (which would result in a substantial diminution of our ownership interest in the farmed-out properties), (e) entering into one or more joint venture relationships with industry partners, (f) entering into financing relationships with one or more industry partners, and (g) the sale of some or all of our interests in the properties. It is unlikely that any one potential source of funding would be utilized exclusively. Rather, it is more likely that we will pursue a combination of different funding sources when the need arises. Regardless of the type of financing techniques that are ultimately utilized, however, it currently appears likely that because of our small size in relation to the magnitude of the capital requirements that will be associated with the development of the subject properties, we will be forced in the future to issue significant amounts of additional shares, pay significant amounts of interest on debt that presumably would be collateralized by all of our assets (including our offshore California properties), reduce our ownership interest in the properties through sales of interests in the properties or as the result of farmouts, industry financing arrangements or other partnership or joint venture relationships, or to enter into various transactions which will result in some combination of the foregoing. In the event that we are not able to pay our share of expenses as a working interest owner as required by the respective operating agreements, it is possible that we might lose some portion of our ownership interest in the properties under some circumstances, or that we might be subject to penalties which would result in the forfeiture of substantial revenues from the properties. While the costs to develop the offshore California properties in which we own an interest are anticipated to be substantial in relation to our small size, management believes that the opportunities for us to increase our asset base and ultimately improve our cash flow are also substantial in relation to our size. Although there are several factors to be considered in connection with our plans to obtain funding from outside sources as necessary to pay our proportionate share of the costs associated with developing our offshore properties (not the least of which is the possibility that prices for petroleum products could decline in the future to a point at which development of the properties is no longer economically feasible), we believe that the timing and rate of development in the future will in large part be motivated by the prices paid for petroleum products. To the extent that prices for petroleum products were to decline below their recent levels, it is likely that development efforts will proceed at a slower pace such that costs will be incurred over a more extended period of time. If petroleum prices remain at current levels, however, we believe that development efforts will intensify. Our ability to successfully negotiate financing to pay our share of development costs on favorable terms will be inextricably linked to the prices that are paid for petroleum products 26 during the time period in which development is actually occurring on each of the subject properties. Gato Canyon Unit. We hold a 15.60% working interest (directly 8.63% and through Amber 6.97%) in the Gato Canyon Unit. This 10,100 acre unit is operated by Samedan Oil Corporation. Seven test wells have been drilled on the Gato Canyon structure. Five of these were drilled within the boundaries of the Unit and two were drilled outside the Unit boundaries in the adjacent State Tidelands. The test wells were drilled as follows: within the boundaries of the Unit, three wells were drilled by Exxon, two in 1968 and one in 1969; one well was drilled by Arco in 1985 and one well was drilled by Samedan in 1989. Outside the boundaries of the Unit, in the State Tidelands but still on the Gato Canyon Structure, one well was drilled by Mobil in 1966 and one well was drilled by Union Oil in 1967. In April 1989, Samedan tested the P-0460 #2 which yielded a combined test flow rate of 5,160 Bbls of oil per day from six intervals in the Monterey Formation between 5,880 and 6,700 feet of drilled depth. The Monterey Formation is a highly fractured shale formation. The Monterey (which ranges from 500 feet to 2,900 feet in thickness) is the main productive and target zone in many offshore California oil fields (including our federal leases and/or units). The Gato Canyon field is located in the Santa Barbara Channel approximately three to five miles offshore (see Map). Water depths range from 280 feet to 600 feet in the area of the field. Oil and gas produced from the field is anticipated to be processed onshore at the existing Las Flores Canyon facility (see Map). Las Flores Canyon has been designated a "consolidated site" by Santa Barbara County and is available for use by offshore operators. Any processed oil is expected to be transported out of Santa Barbara County in the All American Pipeline (see Map). Offshore pipeline distance to access the Las Flores site is approximately six miles. Delta's share of the estimated capital costs to develop the Gato Canyon field is approximately $45 million. As a result of the Norton case, the Gato Canyon Unit leases are held under directed suspensions of operations with no specified end date. An updated Exploration Plan is expected to include plans to drill an additional delineation well when activities are resumed. This well will be used to determine the final location of the development platform. Following the platform decision, a Development Plan will be prepared for submittal to the MMS and the other involved agencies. Two to three years will likely be required to process the Development Plan and receive the necessary approvals. Point Sal Unit. We hold a 6.83% working interest in the Point Sal Unit. This 22,772 acre unit is operated by Aera Energy LLC, a limited liability company jointly owned by Shell Oil Company and ExxonMobil Company. Four test wells were drilled within this unit. These test wells were drilled as follows: two wells were drilled by Sun Oil (now Oryx Energy), one in 1984 and one in 1985; and the other two wells were drilled by Reading & Bates, both in 1984. All four wells drilled on this unit have indicated the presence of oil and gas in the Monterey Formation. The largest of these, the Sun P-0422 #1, yielded a combined test flow rate of 3,750 Bbls of oil per day from the Monterey. The oil in the upper block has an average estimated gravity of 10E API and the oil in the subthrust block has an average estimated gravity of 15E API. 27 The Point Sal field is located in the Offshore Santa Maria Basin approximately six miles seaward of the coastline (see Map). Water depths range from 300 feet to 500 feet in the area of the field. It is anticipated that oil and gas produced from the field will be processed in a new facility at an onshore site or in the existing Lompoc facility (see Map). Any processed oil would then be transported out of Santa Barbara County in either the All American Pipeline or the Tosco-Unocal Pipeline (see Map). Offshore pipeline distance is approximately six to eight miles depending on the final choice of the point of landfall. Delta's share of the estimated capital costs to develop the Point Sal Unit is approximately $38 million. As a result of the Norton case, the Point Sal Unit leases are held under directed suspensions of operations with no specified end date. An updated Exploration Plan is expected to include plans to drill an additional delineation well when activities are resumed prior to preparing the Development Plan. Lion Rock Unit and Federal OCS Lease P-0409. We hold a 1% net profits interest (through Amber) in the Lion Rock Unit and a 24.21692% working interest (directly) in 5,693 acres in Federal OCS Lease P-0409 which is immediately adjacent to the Lion Rock Unit and contains a portion of the San Miguel Field reservoir. The Lion Rock Unit is operated by Aera Energy LLC. An aggregate of 13 test wells have been drilled on the Lion Rock Unit and OCS Lease P-0409. Nine of these wells were completed and tested and indicated the presence of oil and gas in the Monterey Formation. The test wells were drilled as follows: one well was drilled by Socal (now Chevron) in 1965; six wells were drilled by Phillips Petroleum, one in 1982, two in 1983, two in 1984 and one in 1985; and six wells were drilled by Occidental Petroleum in Lease P-0409, three in 1983 and three in 1984. The oil has an average estimated gravity of 10.7E API. The Lion Rock Unit and Lease P-0409 are located in the Offshore Santa Maria Basin eight to ten miles from the coastline (see Map). Water depths range from 300 feet to 600 feet in the area of the field. It is anticipated that any oil and gas produced at Lion Rock and P-0409 would be processed at a new facility in the onshore Santa Maria Basin or at the existing Lompoc facility (see Map), and would be transported out of Santa Barbara County in the All American Pipeline or the Tosco-Unocal Pipeline (see Map). Offshore pipeline distance will be eight to ten miles, depending on the point of landfall. Delta's share of the estimated capital costs to develop the Lion Rock/San Miguel field is approximately $113 million. As a result of the Norton case, the Lion Rock Unit and Lease P-0409 are held under directed suspensions of operations with no specified end date. It is anticipated that upon the resumption of activities there will be an interpretation of the 3D seismic survey and the preparation of an updated Plan of Development leading to production. Additional delineation wells may or may not be drilled depending on the outcome of the interpretation of the 3D survey. Sword Unit. We hold a 2.492% working interest (directly 1.6189% and through Amber .8731%) in the Sword Unit. This 12,240 acre unit is operated by Conoco, Inc. In aggregate, three wells have been drilled on this unit, of which two wells were completed and tested in the Monterey formation with calculated flow rates of from 4,000 to 5,000 Bbls per day with an estimated 28 average gravity of 10.6E API. The two completed test wells were drilled by Conoco, one in 1982 and the second in 1985. The Sword field is located in the western Santa Barbara Channel ten miles west of Point Conception and five miles south of Point Arguello's field Platform Hermosa (see Map). Water depths range from 1000 feet to 1800 feet in the area of the field. It is anticipated that the oil and gas produced from the Sword Field will likely be processed at the existing Gaviota consolidated facility and the oil would then be transported out of Santa Barbara County in the All American Pipeline (see Map). Access to the Gaviota plant is through Platform Hermosa and the existing Point Arguello Pipeline system. A pipeline proposed to be laid from a platform located in the northern area of the Sword field to Platform Hermosa would be approximately five miles in length. Delta's share of the estimated capital costs to develop the Sword field is approximately $19 million. As a result of the Norton case, the Sword Unit leases are held under directed suspensions of operations with no specified end date. An updated Exploration Plan is expected to include plans to drill an additional delineation well when activities are resumed. Rocky Point Unit. Whiting holds, as nominee for Delta, an 11.11% interest in OCS Block 451 (E/2) and 100% interest in OCS Block 452 and 453, which leases comprise the undeveloped Rocky Point Unit. The financial arrangement between Whiting and us is prescribed by a letter agreement between Whiting and Delta dated November 19, 1999 which, among other things, provides that Whiting "will continue as operator of the Rocky Point Unit" and "will also continue to hold title to the working/leasehold interest in the Rocky Point Unit leases for the sole benefit and account of . . . Delta". The letter agreement further provides that upon our written request, Whiting will immediately assign or cause to be assigned to us, all right, title and interest of Whiting in the Rocky Point Unit leases held by Whiting. Further, Whiting may not take any action or make any agreement relating to these Rocky Point leases without our consent. On November 2, 2000 we entered into an agreement with all of the other interest owners of Point Arguello, including Whiting, for the development of Rocky Point and agreed, among other things, that Arguello, Inc. would become the operator of Rocky Point. Six test wells have been drilled on these leases from mobile drilling units. Five were successful and one was a dry hole. OCS-P 0451 #1, drilled in 1982, was the discovery well for the Rocky Point Field. Five delineation wells were drilled on the Unit between 1982 and 1984. Rates up to 1,500 Bbls of oil per day were tested from the Monterey formation. Rates up to 3,500 Bbls of oil per day were tested from the lower Sisquoc formation which overlies the Monterey. Oil gravities at Rocky Point range from 24 degrees to 31 degrees API. Development of the Rocky Point Unit will be accomplished through extended-reach drilling from the platforms located within the adjacent Point Arguello Unit (see below). In 1987 an extended-reach well was successfully drilled to the southwestern edge of the Rocky Point field from Platform Hermosa located in the Point Arguello Unit. Since that time the technology of extended-reach drilling has dramatically advanced. The entire Rocky Point field is now within drilling distance from the Point Arguello Unit platforms. 29 As a result of the Norton case, the Rocky Point Unit leases are held under directed suspensions of operations with no specified end date. The Unit operator has prepared and timely submitted a Project Description for the development program to the MMS as the first milestone in the Schedule of Activities for the Unit. The operator, under the auspices of the MMS, has also made a presentation of the Project to the affected Federal, state and local agencies. On May 18, 2001 a revised Development and Production Plan and supporting information was submitted to the MMS and distributed to the CCC and the Office of the California Governor. The revised Development and Production Plan calls for development of the Rocky Point Unit using extended reach drilling from the existing Point Arguello platforms, and is deemed to be in final form as the MMS has acknowledged that all regulatory requirements necessary for such a Plan have been addressed. Under law, the CCC is typically required to make a determination as to whether or not the Plan is "consistent" with California's Coastal Plan within three months of submission, with a maximum of three months' extension (a total of six months). By correspondence dated August 7, 2001, however, the Unit operator requested that the CCC suspend the consistency review for the revised Development and Production Plan since the MMS had temporarily stopped work on the processing of the plan as the result of the court decision in the case of California v. Norton, et al which is discussed below (see "Management's Discussion and Analysis or Plan of Operation-Offshore Undeveloped Properties"). Developed Properties: -------------------- Point Arugello Unit. Whiting holds, as our nominee, the equivalent of a 6.07% working interest in the form of a financial arrangement termed a "net operating interest" in the Point Arguello Unit and related facilities. In layman's terms, the term "net operating interest" is defined in our agreement with Whiting as being the positive or negative cash flow resulting to the interest from a seven step calculation which in summary subtracts royalties, operating expenses, severance taxes, production taxes and ad valorem taxes, capital expenditures, Unit fees and certain other expenses from the oil and gas sales and certain other revenues that are attributable to the interest. Within this unit are three producing platforms (Hidalgo, Harvest and Hermosa) which are operated by Arguello, Inc., a subsidiary of Plains Petroleum. In an agreement between Whiting and Delta (see Form 8-K dated June 9, 1999) Whiting agreed to retain all of the abandonment costs associated with our interest in the Point Arguello Unit and the related facilities. We anticipate that we will drill four wells on the Point Arguello Unit during fiscal 2002. Each well will cost approximately $2.8 million ($170,000 to our interest). We anticipate the costs to be paid through current operations or additional financing. --------------- map page --------------- 30 Kazakhstan ---------- Acquisition of Exploration Licenses in Kazakhstan. During fiscal year 1999, we acquired Ambir Properties, Inc. ("Ambir"), the only assets of which consisted of two licenses for exploration of approximately 1.9 million acres in the Pavlodar region of Eastern Kazakhstan. A work plan prepared by Delta was approved by the Kazakhstan government which established minimum work and spending commitments. The acquisition is a high risk, frontier exploration project. Delta does not presently have the expertise nor the resources to meet all commitments that will be required in the later years of the work plan. We made a determination based on the political risk and lack of expertise in the area that it may not be economical to develop this prospect and therefore we may not proceed with it. We recorded an impairment of $624,000 on this property during fiscal 2001. (c) Production. ---------- During the years ended June 30, 2001 and 2000 we have not had, nor do we now have, any long-term supply or similar agreements with governments or authorities under which we acted as producer. Impairment of Long Lived Assets ------------------------------- Unproved Undeveloped Offshore California Properties --------------------------------------------------- We acquired many of our (including Amber's) offshore properties in a series of transactions from 1999 to the present. These properties are carried at our cost bases and have been subject to an impairment review on an annual basis. These properties will be expensive to develop and produce and have been subject to significant regulatory restrictions and delays. Substantial quantities of hydrocarbons are believed to exist based on estimates reported to us by the operator of the properties and the U.S. government's Mineral Management Services. The classification of these properties depends on many assumptions relating to commodity prices, development costs and timetables. We annually consider impairment of properties assuming that properties will be developed. Based on the range of possible development and production scenarios using current prices and costs, we have concluded that the cost bases of our offshore properties are not impaired at this time. There are no assurances, however, that when and if development occurs, we will recover the value of our investment in such properties. Other Undeveloped Properties ---------------------------- Other undeveloped properties are carried at historical cost and consist of the several onshore properties. These properties are carried at our cost bases and have been subject to an impairment review on an annual basis. There are no proven reserves associated with these properties. Based on our continued interest in these properties and the possibility for future 31 development, we have concluded that the cost bases of these other undeveloped properties are not impaired at this time. There are no assurances, however, that when and if development occurs, we will recover the value of our investments in such properties. Undeveloped Kazakhstan Property ------------------------------- Delta does not presently have the expertise nor the resources to meet all commitments that will be required in the later years of the work plan. Delta may seek other companies in the oil and gas industry to participate in the implementation of the work plan. We made a determination based on the political risk and lack of expertise in the area that it may not be economical to develop this prospect and therefore we may not proceed with this prospect and recorded an impairment of $624,000 on this property during fiscal 2001. Developed Oil and Gas Properties -------------------------------- We annually compare our historical cost basis of each developed oil and gas property to its expected future undiscounted cash flow from each property (on a field by field basis). 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 property, no impairment is recognized. If the carrying value of the property 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. We had an impairment provision attributed to producing properties during the year ended June 30, 2001 of $174,000 and had no impairment provision during the three months ended September 30, 2001 and 1999 and the years ended June 30, 2000 and 1999. Any impairment provisions recognized for developed and undeveloped properties are permanent and may not be restored in the future. The following table sets forth our average sales prices and average production costs during the periods indicated: 32

Three Months Ended Year Ended September 30, June 30, ----------------------------------------- --------------------------------------------------- 2001 2000 2001 2000 1999 ------------------- ------------------- ------------------- ------------------- ------- Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore Onshore ------- -------- ------- -------- ------- -------- ------- -------- ------- Average sales price: Net of forward contract sales Oil (per barrel) $26.03 $17.41 $29.05 $15.81 $27.10 $18.49 $25.95 $11.54 $10.24 Natural Gas (per Mcf) $ 3.37 $ - $ 4.40 $ - $ 6.27 - $ 2.62 - $ 1.97 Gross of forward contract sales Oil (per barrel) $26.15 $17.41 $29.05 $24.63 $27.30 $22.53 $25.95 $21.14 $10.24 Natural Gas (per Mcf) $ 3.37 $ - $ 4.40 $ - $ 6.27 - $ 2.62 - $ 1.97 Production costs (per Bbl equivalent) $ 3.84 $ 7.53 $ 3.85 $10.77 $ 3.88 $12.65 $ 4.94 $11.02 $ 4.37

The profitability of our oil and gas production activities is affected by the fluctuations in the sale prices of our oil and gas production. We sold 25,000 barrels per month from December 1999 to May 2000 at $8.25 per barrel and we sold 25,000 barrels per month from June 2000 to December 2000 at $14.65 under fixed price contracts with production purchases. We sold 6,000 barrels per month from March 1, 2001 through June 30, 2001 at $27.31 per barrel under fixed price contracts with production purchases. (See "Management's Discussion and Analysis or Plan of Operation.") (d) Productive Wells and Acreage. The table below shows, as of June 30, 2001, the approximate number of gross and net producing oil and gas wells by state and their related developed acres owned by us. Calculations include 100% of wells and acreage owned by us and by Amber. Productive wells are producing wells capable of production, including shut-in wells. Developed acreage consists of acres spaced or assignable to productive wells. Oil (1) Gas Developed Acres Gross (2) Net (3) Gross (2) Net (3) Gross (2) Net (3) --------- ------- --------- ------- --------- ------- North Dakota 20 1.00 0 .00 4,483 168 New Mexico 0 .00 13 8.25 4,480 2,553 Texas 4 1.82 3 .42 1,788 1,201 Colorado 8 .80 5 4.00 2,560 2,127 Oklahoma 0 .00 35 2.22 5,600 352 California: Onshore 0 .00 11 1.25 1,200 132 Offshore 38 2.30 0 .00 19,740 1,197 Wyoming 0 .00 12 .80 960 192 -- ---- -- ----- ------ ----- 70 5.92 68 16.94 40,811 7,922 (1) All of the wells classified as "oil" wells also produce various amounts of natural gas. 33 (2) A "gross well" or "gross acre" is a well or acre in which a working interest is held. The number of gross wells or acres is the total number of wells or acres in which a working interest is owned. (3) A "net well" or "net acre" is deemed to exist when the sum of fractional ownership interests in gross wells or acres equals one. The number of net wells or net acres is the sum of the fractional working interests owned in gross wells or gross acres expressed as whole numbers and fractions thereof. (e) Undeveloped Acreage. ------------------- At June 30, 2001, we held undeveloped acreage by state as set forth below: Undeveloped Acres (1) (2) ------------------------- Location Gross Net -------- ------- ------ South Dakota 58,400 29,200 California, offshore(3) 64,905 15,837 California, onshore 640 96 Colorado 6,060 4,554 Wyoming 960 768 Oklahoma 1,600 112 ------- ------ Total 132,565 50,567 (1) Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves. (2) Includes acreage owned by Amber. (3) Consists of Federal leases offshore California near Santa Barbara. (f) Drilling Activity ----------------- During the years indicated, we drilled or participated in the drilling of the following productive and nonproductive exploratory and development wells: 34 Year Ended Year Ended Year Ended June 30,2001 June 30, 2000 June 30, 1999 Gross Net Gross Net Gross Net ------------ ------------- ------------- Exploratory Wells(1): Productive: Oil 0 .00 0 .00 0 .00 Gas 0 .00 0 .00 4 .44 Nonproductive 6 2.24 0 .00 7 .77 -- ---- - --- -- ---- Total 6 2.24 0 .00 11 1.21 Development Wells(1): Productive: Oil 3 .18 3 .18 0 .00 Gas 7 .37 2 .25 0 .00 Nonproductive 0 .00 0 .00 0 .00 -- ---- - --- -- ---- Total 10 .55 5 .43 0 .00 Total Wells(1): Productive: Oil 3 .18 3 .18 0 .00 Gas 7 .37 2 .25 4 .44 Nonproductive 6 2.24 0 .00 7 .77 -- ---- - --- -- ---- Total Wells 16 2.79 5 .43 11 1.21 (1) Does not include wells in which the Company had only a royalty interest. (g) Present Drilling Activity ------------------------- We plan to participate in the drilling of four new wells before the end of calendar 2001. LEGAL PROCEEDINGS We are not directly engaged in any material pending legal proceedings to which we or our subsidiaries are a party or to which any of our property is subject. COMMON EQUITY SECURITIES Market Information. Delta's common stock currently trades under the symbol "DPTR" on NASDAQ. The following quotations reflect inter-dealer high and low sales prices, without retail mark-up, mark-down or commission and may not represent actual transactions. 35 Quarter Ended High Low ------------- ------ ----- September 30, 1998 $3.19 $1.63 December 31, 1998 2.50 1.50 March 31, 1999 3.00 1.75 June 30, 1999 2.75 1.75 September 30, 1999 3.50 2.63 December 31, 1999 2.94 1.78 March 31, 2000 3.88 2.19 June 30, 2000 4.06 3.00 September 30, 2000 6.19 3.75 December 31, 2000 5.13 3.13 March 31, 2001 5.22 3.31 June 30, 2001 5.75 4.19 September 30, 2001 4.65 2.38 On November 13, 2001, the reported closing price for our common stock on the Nasdaq Small-Cap Market was $2.65. Approximate number of holders of common stock. The number of holders of record of our common stock at November 1, 2001 was approximately 1,000 which does not include an estimated 2,600 additional holders whose stock is held in "street name." Dividends. We have not paid dividends on our stock and we do not expect to do so in the foreseeable future. FINANCIAL DATA SELECTED FINANCIAL INFORMATION The following selected financial information should be read in conjunction with our financial statements and the accompanying notes.

Three Months Ended September 30, Fiscal Years Ended June 30, ------------------------- -------------------------------------------------------------- 2001 2000 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- ---- ---- Total Revenues $ 2,443,000 2,401,000 12,877,000 3,576,000 1,695,000 2,164,000 1,812,000 Income/(Loss) from Operations $ 105,000 247,000 1,678,000 (2,080,000) (2,905,000) (1,010,000) (2,457,000) Income/(Loss) Per Share $ (.02) .03 .03 (0.46) (0.51) (0.18) (0.49) Total Assets $29,069,000 30,182,000 29,832,000 21,057,000 11,377,000 10,350,000 10,438,000 Total Liabilities $11,141,000 14,546,000 11,551,000 10,094,000 1,531,000 845,000 1,268,000 Stockholders' Equity $17,928,000 15,636,000 18,281,000 10,963,000 9,846,000 9,505,000 9,171,000 Total Long Term Debt $ 8,593,000 12,471,000 9,434,000 8,245,000 1,000,000 -0- -0-

36 MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION. General ------- At September 30, 2001, we had a working capital deficit of $1,940,000 compared to a working capital deficit of $1,560,000 at June 30, 2001. This increase in working capital deficit is primarily due to a decrease in oil and gas prices and the increase in accounts payable relating to additional drilling during the quarter. Offshore -------- Offshore Undeveloped Properties ------------------------------- The undeveloped leases in which we own interests were issued during the early 1980s (with the exception of the Sword Unit leases issued in 1979) and carried a primary term of five years. During those primary terms, oil and gas in commercial quantities were discovered in all of the unit areas in which we own interests. Applicable statutes and regulations require that a lease beyond its primary term must be maintained either by production or drilling operations (conducted under an approved Exploration Plan or Development and Production Plan, or under a suspension of production or suspension of operations). Applicable federal regulations set forth a number of reasons for which the MMS may either grant or direct a suspension of operations or suspension of production. It is common practice for lease suspensions of this nature to be issued by the MMS either to aid the operator in accommodating necessary activities or unavoidable delays or to accommodate environmental concerns or national security issues. These suspensions are issued when it is necessary to allow the proper development of unitized leases on which discoveries of commercial quantities of oil and gas have occurred. Our leases are currently held under suspensions issued on that basis. Although the issuance of future suspensions is subject to MMS discretion, the applicable statutes and regulations, as well as past practice in the Pacific Outer Continental Shelf region, support the issuance of future suspensions as necessary to facilitate development so long as the operators continue diligent efforts to achieve production. There are certain milestones that were previously established by the MMS for four of our five undeveloped offshore California units (the exception being Rocky Point). The specific milestones for each of the four units vary depending upon the operator of the unit. On July 2, 2001, however, these milestones were suspended by the MMS in compliance with an order entered by a Federal Court on June 22, 2001 in the case of California v. Norton. In that case, the CCC sued the United States government claiming, in essence, that the lease suspensions that were granted by the MMS while the COOGER Study was being completed violated the requirements of the Coastal Zone Management Act because, in granting those suspensions, the MMS did not make a determination that the suspensions were consistent with California's coastal management program. The Court agreed with California and ordered the MMS to set aside its approval of the subject suspensions and to direct suspensions of all of the subject leases, including all milestone activities, for a time sufficient 37 for the MMS to provide the State of California with a consistency determination under the Coastal Zone Management Act. The July 2, 2001 letters from the MMS which direct suspension of the milestones indicate that the MMS will review the previously submitted (and approved) suspension requests under the provisions of the Coastal Zone Management Act as directed by the court. The current suspensions of operations directed by the letters do not specify an end date. The MMS has issued letters to all of the operators of the affected leases offering the opportunity to modify the previously submitted suspension of production requests. The suspensions themselves authorize only preliminary activities, not operations, on the leases. The operations (i.e., drilling the next delineation wells) will be conducted under Exploration Plans ("EPs"). The operators intend to submit proposed Exploration Plans to the MMS for approval significantly before the expiration of the suspensions. Within 30 days of the date upon which the proposed EP is deemed "submitted" (usually after further revisions at the request of the MMS), the MMS is required to either: (1) approve the plan; (2) require the lessee to modify the plan, in which case the lessee may resubmit the modified plan; or (3) disapprove the plan if the MMS determines that the proposed activity would probably cause serious environmental harm which cannot be mitigated. Disapproval of an Exploration Plan does not, in and of itself, effect a cancellation of a lease. Under Federal Regulations (30 CFR Sec. 250.203(k)(2)), a lessee may resubmit a disapproved plan if there is a change in the circumstances which caused it to be disapproved. Further, the Federal Regulations contemplate that the lessee will work to modify the disapproved EP to accommodate the environmental concerns for a period of up to five years, during which time the lease would be held under a suspension. If the leases were ultimately cancelled on the basis of this Exploration Plan disapproval, the regulations contemplate that compensation would be required. If an Exploration Plan is approved, a delineation well would be spudded prior to the end of the applicable suspension. Once drilling is underway, the lease is held by operations. At the end of drilling operations, the lessee has a 180-day period to commence further operations (under an Exploration Plan or a Development and Production Plan) or to obtain a further suspension. In practice, the lessee would seek a suspension to allow for time to evaluate the results of delineation drilling and prepare a Development and Production Plan. Again, the applicable sections of the regulations accommodate suspensions for this purpose. During any such suspension, the operator would submit a proposed Development and Production Plan to the MMS. Within 60 days of the last day of the applicable comment periods, the MMS must: (1) approve the Development and Production Plan; (2) require modification of the Development and Production Plan; or (3) disapprove the Development and Production Plan, due to (i) the operator's failure to comply with applicable law, (ii) failure to obtain state consistency concurrence, (iii) national security or defense issues, or (iv) environmental concerns. As with the Exploration Plan, disapproval does not effect a lease cancellation. Again, the regulations contemplate that the lessee will work to modify the disapproved Development and Production Plan (or resolve the Coastal Zone Management Act issues) for a period of up to five 38 years, during which the lease would most likely be held under a granted suspension. All leases in which we hold an interest were originally issued for a primary term of five years. As discussed above, suspensions have the effect of extending the term of the lease for the period of the suspension. All of our leases must be maintained either through production, drilling operations or suspensions. Annual rentals under all leases equal $3/acre. Rentals were waived during the COOGER Study period (from January 1, 1993 through November 15, 1999). The MMS has also waived rentals during the current suspensions of operations beginning July 2, 2001. As these suspensions do not state a definite end date, the date through which rentals will be waived is not known. In January 2000, the two properties which are operated by Aera Energy, LLC, Lease OCS-P 0409 and the Point Sal Unit, had requirements to submit an interpretation of the merged 3-D survey of the Offshore Santa Maria Basin covering the properties. This milestone was accomplished in February 2000. The next milestone for these properties was to submit a Project Description for each property to the MMS in February 2000. The Project Description for each of the properties was submitted in February and after responding to an MMS request for additional information and clarification, revised Project Descriptions were submitted in September 2000. By letter dated July 21, 2000, Aera submitted a plan to the MMS for the voluntary re-unitization of the Offshore Santa Maria Basin, including the Lion Rock Unit and Lease OCS-P 0409, into one unit. This plan included a proposed time line for submitting the required unit agreement, initial plan of operations, and all geological, geophysical and engineering data supporting that request. Following that submission, MMS advised Aera that it now believes it would not support consolidating the Offshore Santa Maria Basin into one unit. Therefore, Aera is evaluating other unitization alternatives, which will then be reviewed with co-owners and the MMS. The previous suspensions of production on both the Lion Rock Unit and Lease OCS-P-0409 were scheduled to expire on November 1, 2002. Prior to the decision in the Norton case, the revised Exploration Plans and/or Development and Production Plans (DPP's) for the Aera properties were scheduled to be submitted to the MMS in September 2001. As the operator of the properties, Aera stated its intent to timely submit the EPs and DPPs. When the EPs and DPPs are submitted, it is currently estimated that it will cost $100,000, with Delta's share being $5,000. When and if milestones are reinstated by the MMS, it is anticipated that the next milestone for Aera would still be to show proof that a Request for Proposal (RFP) has been prepared and distributed to the appropriate drilling contractors as described in the revised Project Descriptions. At the time milestones were suspended by the MMS, the milestone date for the RFP was November 2001. The affected operating companies have formed a committee to cooperate in the process of mobilizing the mobile drilling unit. When necessary, it is anticipated that this committee will prepare the RFP for submission to the contractors and MMS. It is estimated that it will cost $210,000 to complete the RFPs, with Delta's share being $11,000. Unless delays are encountered as the result of the Norton case, drilling operations on the Point Sal Unit are still expected to begin in February 2003 with the drilling of a delineation well at an estimated cost of approximately $13,000,000. Delta's share is estimated at $650,000. 39 No delineation well is necessary for Lease OSC-P 0409 as six wells have been drilled on the lease and a DPP was previously approved. The Sword and Gato Canyon Units are operated by Samedan Oil Corporation. In May 2000, Samedan acquired Conoco, Inc.'s interest in the Sword Unit. Prior to such time, as operator Conoco timely submitted the Project Description for the Sword Unit in February 2000. However, since becoming the operator, Samedan has informed the MMS that it has plans to submit a revised Project Description for the Sword Unit. The new plan is to develop the field from Platform Hermosa, an existing platform, rather than drilling a delineation well on Sword and then abandoning it. Prior to the suspension of milestones in accordance with the Court's order in the Norton case, the next scheduled milestone for the Sword Unit was the DPP for Platform Hermosa, which was to be submitted to the MMS in September 2001. When the DPP is filed, it is estimated that the cost will be approximately $360,000, with Delta's share being $11,000. In February 2000, Samedan timely submitted the Project Description for the Gato Canyon Unit. In August 2000, after responding to an MMS request for additional information and clarification, Samedan filed the revised Project Description. Prior to the suspensions granted under the Norton decision, the updated Exploration Plan for the Gato Canyon Unit was to be submitted to the MMS in September 2001. It is estimated that the cost of the updated Exploration Plan will be approximately $300,000, with Delta's share being $50,000. If and when milestones are reinstated, it is anticipated that the next milestone for Gato Canyon would still be to show proof that a Request for Proposal has been prepared and distributed to the appropriate drilling contractors as described in the revised Project Descriptions. At the time milestones were suspended by the MMS, the milestone date for the RFP was November 2001. It is anticipated that the same committee that is preparing the RFPs for the Aera properties will prepare the RFP for Gato Canyon for submittal to the contractors and MMS. It is estimated that it will cost $450,000 to complete the RFP, with Delta's cost estimated at $75,000. Prior to its suspension, the last milestone was to begin drilling operations on the Gato Canyon Unit by May 1, 2003 using the committee's mobile drilling unit. The cost of the drilling operations is estimated to be $11,000,000, with Delta's share being $1,750,000. As a result of the Norton case, the Rocky Point Unit leases are held under directed suspensions of operations with no specified end date. The United States government has filed a notice of its intent to appeal the court's order in the Norton case. The Unit operator timely submitted a Project Description for the development program to the MMS as the first milestone in the Schedule of Activities for the Unit. The operator, under the auspices of the MMS, has also made a presentation of the Project to the affected Federal, state and local agencies. It is anticipated that the Rocky Point Unit will be developed from existing facilities within the Point Arguello Field, which is currently in production under previously approved Development and Production Plans. The existing Point Arguello Unit DPPs were found to be consistent with California's Coastal Zone Management Plan when originally approved. As the development of the Rocky Point Unit will require only revision of the existing Point Arguello Field DPPs, it is only the proposed revision to the existing 40 DPPs that must now be found to be consistent with the Coastal Zone Management Plan. The operator has determined that the proposed Rocky Point Unit development activities comply with the State of California's approved coastal management program and will be conducted in a manner consistent with such program. That conclusion is based on an extensive environmental evaluation set forth in supporting information submitted to the MMS with the proposed revisions to Point Arguello Field DPPs and the evaluation may be accessed on the internet at http://www.mms.gov/omm/pacific/lease/rpu-pdfs/RPU-Supporting-Information.pdf. By correspondence dated August 7, 2001, however, the Unit operator requested that the CCC suspend the consistency review for the revised Development and Production Plan since the MMS had temporarily stopped work on the processing of the plan as the result of the Norton decision. Our working interest share of the future estimated development costs based on estimates developed by the operating partners relating to four of our five undeveloped offshore California units is approximately $210 million. No significant amounts are expected to be incurred during fiscal 2002, and $1.0 million and $4.2 million are expected to be incurred during fiscal 2003 and 2004, respectively. Because the amounts required for development of these undeveloped properties are so substantial relative to our present financial resources, we may ultimately determine to farmout all or a portion of our interests. If we were to farmout our interests, our interest in the properties would be decreased substantially. In the event that we are not able to pay our share of expenses as a working interest owner as required by the respective operating agreements, it is possible that we might lose some portion of our ownership interest in the properties under some circumstances, or that we might be subject to penalties which would result in the forfeiture of substantial revenues from the properties. Alternatively, we may pursue other methods of financing, including selling equity or debt securities. There can be no assurance that we can obtain any such financing. If we were to sell additional equity securities to finance the development of the properties, the existing common shareholders' interest would be diluted significantly. There are additional, as yet undetermined, costs that we expect in connection with the development of the fifth undeveloped property in which we have an interest (Rocky Point Unit). At the present time we believe that all of the costs capitalized for our offshore California properties will be fully recovered through future development and production in spite of the factors discussed above, including, without limitation, the delays that have been encountered in preparing the Development and Production Plan for the Rocky Point Unit, the current uncertainty as to whether that plan will be found to be consistent with the California Coastal Zone Management Plan, our inability to submit exploration plans for the Point Sal, Lion Rock, Gato Canyon and Sword Units since their acquisition in 1992, the extensive development necessary to access reserves on those Units, the uncertainty created by the court ruling in June, 2001 in the Norton case, the current suspension of operations prohibiting exploratory activities on the properties and our inability to effect any development due to our status as an investor as opposed to being the operator of the properties. 41 Based on discussions with the MMS and operators of the properties, we currently believe that the MMS will appeal the decision entered in the Norton case and will await the outcome of its appeal prior to providing the State of California with a consistency determination under the Coastal Zone Management Act (see "Properties"). Furthermore, we believe that the MMS will seek to modify the previously submitted suspension of production requests to focus solely on "preliminary activities," and will approve new suspensions of production requests that do not contain any "milestones" per se, as the stated milestones in the previous suspensions of production appear to have been a significant factor in the court's decisions. We also believe that the end-date of any such new suspensions of production will likely be the anticipated spud date for the delineation wells set forth in the operators' respective requests for suspensions of production. Even though we are not the designated operator of the properties and regulatory approvals have not been obtained, we believe exploration and development activities on these properties will occur and we are committed to expend funds attributable to our interests in order to proceed with obtaining the approvals for the exploration and development activities. Based on the preliminary indicated levels of hydrocarbons present from drilling operations conducted in the past, we believe the fair value of our property interests are in excess of their carrying value at September 30, 2001 and June 30, 2001 and that no impairment in the carrying value has occurred. Should the required regulatory approvals not be obtained or plans for exploration and development of the properties not continue, the carrying value of the properties would likely be impaired and written off. Offshore Producing Properties ----------------------------- Point Arguello Unit. Pursuant to a financial arrangement between Whiting and us, we hold what is essentially the economic equivalent of a 6.07% working interest, which we call a "net operating interest", in the Point Arguello Unit and related facilities. In layman's terms, the term "net operating interest" is defined in our agreement with Whiting as being the positive or negative cash flow resulting to the interest from a seven step calculation which in summary subtracts royalties, operating expenses, severance taxes, production taxes and ad valorem taxes, capital expenditures, Unit fees and certain other expenses from the oil and gas sales and certain other revenues that are attributable to the interest. Within this unit are three producing platforms (Hidalgo, Harvest and Hermosa) which are operated by Arguello, Inc., a subsidiary of Plains Resources, Inc. In an agreement between Whiting and Delta (see Form 8-K dated June 9, 1999), Whiting agreed to retain all of the abandonment costs associated with our interest in the Point Arguello Unit and the related facilities. We have already participated in the drilling of three wells and anticipate that we will participate in the drilling of four wells in fiscal 2002. Each well will cost approximately $2.8 million ($170,000 to our interest). We anticipate the drilling costs to be paid through current operations or additional financing. On September 29, 2000 we acquired the West Delta Block 52 Unit ("West Delta") from two unrelated entities by paying $1,529,000 and issuing 509,719 42 shares of our restricted common stock valued at $3.38 per share. The Company borrowed $1,464,000 of the cash portion of the purchase price from an unrelated entity. Two of the Company's officers agreed to personally guarantee the loan. On April 13, 2001, we sold our proportionate share of the West Delta. We received proceeds of $3,500,000 resulting in a gain on sale of oil and gas properties of $459,000. Onshore Producing Properties ---------------------------- On July 10, 2000 we paid $3,745,000 and issued 90,000 shares of our common stock valued at approximately $280,000 and on September 28, 2000 we paid $1,845,000 to acquire interests in 20 producing wells, 5 injection wells and acreage located in the Eland and Stadium fields in Stark County, North Dakota ("North Dakota"). The July 10, 2000 and September 28, 2000 payments resulted in our acquisition of 67% and 33%, respectively, of the ownership interest in each property acquired. The $3,745,000 payment on July 10, 2000 was financed through borrowings from an unrelated entity and personally guaranteed by Roger A. Parker and Aleron H. Larson, Jr., two of the Company's officers, while the payment on September 28, 2000 was primarily paid out of our net revenues from the effective date of the acquisitions through closing. We also issued 100,000 shares of our restricted common stock, valued at $450,000, to an unaffiliated party for its consultation and assistance related to the transaction. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time the commission was earned and is recorded in oil and gas properties. On December 1, 2000, we elected to exercise our option to purchase interests in 680 producing wells and associated acreage in the Permian Basin located in eight counties in west Texas and southeastern New Mexico from Saga Petroleum Corporation ("Saga") and its affiliates. Previously, we paid Saga and its affiliates $500,000 in cash and issued 393,006 shares of our restricted common stock as a deposit required by the Purchase and Sale Agreement between the parties. On January 18, 2001, we acquired the Cedar State gas property ("Cedar State") in Eddy County, New Mexico from Saga Petroleum Corporation for $2,700,000. The consideration was $2,100,000 and 181,219 shares of our common stock, valued at $600,000. The shares were valued at $3.31 per share based on ninety percent of a thirty day average closing price prior to close as required by the purchase and sale agreement. As part of the acquisition, we terminated our December 1, 2000 agreement with Saga and Saga was required to return 393,006 shares of our common stock at closing valued at $1,848,000, which had been previously issued as a deposit for the acquisition of the 680 producing wells and associated acreage mentioned above. We estimate our capital expenditures for onshore properties to be approximately $1.1 million for the year ending June 30, 2002. However, we are not obligated to participate in future drilling programs and will not enter into future commitments to do so unless management believes we have the ability to fund such projects. 43 Equity Transactions ------------------- During the year ended June 30, 1998, we issued 22,500 shares of our common stock to a former employee as part of a severance package. This transaction was recorded at its estimated fair market value of the common stock issued of approximately $65,000 and expenses, which was based on the quoted market price of the stock at the time of issuance. The Company also agreed to forgive approximately $20,000 in debt owed to us by the former employee. On July 8, 1998, we completed a sale of 2,000 shares of our common stock to an unrelated individual for net proceeds to Delta of $6,000 at a price of $3.24 per share. This transaction was recorded at the estimated fair value of the common stock issued, which was based on the quoted market price of the stock at the time of issuance. On October 12, 1998, we issued 250,000 shares of our common stock, at a price of $1.63 per share, and 500,000 options to purchase its common stock at various exercise prices ranging from $3.50 to $5.00 per share to the shareholders of an unrelated entity in exchange for two licenses for exploration with the government of Kazakhstan. The common stock issued was recorded at the estimated fair value, which was based on the quoted market price of the stock at the time of issuance. The options were valued at $217,000 based on the estimated fair value of the options issued and we recorded $624,000 as undeveloped oil and gas properties. On December 1, 1998, we issued 10,000 shares of our common stock valued at $16,000 at a price of $1.75 per share, to an unrelated entity for public relation services and expensed. The common stock issued was recorded at the estimated fair value, which was based on the quoted market price of the stock at the time of issuance. On January 1, 1999, we completed a sale of 194,444 shares of our common stock to Evergreen Resources, Inc. ("Evergreen"), another oil and gas company, for net proceeds to us of $350,000. During fiscal 1999, we issued 300,000 shares of our common stock, at a price of $2.05 per share, to Whiting Petroleum Corporation ("Whiting"), an unrelated entity, along with a $1,000,000 deposit to acquire a portion of Whiting's interest in the Point Arguello Unit, its three platforms (Hidalgo, Harvest, and Hermosa), along with Whiting's interest in the adjacent undeveloped Rocky Point Unit. (See Item 2. Descriptions of Properties.) The common stock issued was recorded at the estimated fair value, which was based on the quoted market price of the stock at the time of issuance and recorded in oil and gas properties. During fiscal 2000, we issued 215,000 shares of our common stock, at a price of $2.56 per share and valued at $550,000, to an unrelated entity as a commission for its involvement with the Point Arguello Unit and New Mexico acquisitions completed in fiscal 2000. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance and recorded in oil and gas properties. 44 On December 1, 1999, we acquired a 6.07% working interest in the Point Arguello Unit, its three platforms (Hidalgo, Harvest, and Hermosa), along with a 100% interest in two and an 11.11% interest in one of the three leases within the adjacent Rocky Point Unit for $5,625,000 in cash consideration and the issuance of 500,000 shares of our common stock with an estimated fair value of $1,134,000. On December 8, 1999, we completed a sale of 428,000 shares of our common stock, at a price of $1.75 per share, to Bank Leu AG, for $749,000. We paid a commission of $75,000 recorded as an adjustment to equity. In addition, we granted warrants to purchase 250,000 shares of our common stock at prices ranging from $2.00 to $4.00 per share for six to twelve months from the effective date of a registration covering the underlying warrants to an unrelated entity. The warrants were valued at $95,000 which was a 10% discount to market, based on the quoted market price of the stock at the time of issuance. The warrants were accounted for as an adjustment to stockholders' equity. On December 16, 1999, we issued 15,000 shares of our restricted common stock, at a price of $2.14 per share and valued at $32,000, to an unrelated company as a commission for its involvement with establishing a credit facility for our Point Arguello Unit purchase recorded as a deferred financing cost and amortized over the life of the loan. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price on the date the commission was earned. On January 4, 2000, we completed the sale of 175,000 shares of our common stock in a private transaction to Evergreen, also a shareholder, for net proceeds to us of $350,000. On January 5, 2000, we issued 60,000 shares of our restricted common stock, at a price of $2.14 per share and valued at $128,000, to an unrelated company as a commission for its involvement with establishing a credit facility for our Point Arguello Unit purchase which was recorded as a deferred financing cost and amortized over the life of the loan. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price on the date the commission was earned. On June 1, 2000, we issued 90,000 shares of our common stock, at a price of $3.04 per share and valued at $273,000, to Whiting as a deposit to acquire certain interests in producing properties in Stark County, North Dakota. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance and recorded in oil and gas properties. On July 5, 2000, we completed the sale of 258,621 shares of our restricted common stock to an unrelated entity for $750,000. A fee of $75,000 was paid and options to purchase 100,000 shares of our common stock at $2.50 per share and 100,000 shares at $3.00 per share for one year were issued to an unrelated individual and entity as consideration for their efforts and consultation related to the transaction. The options were valued at approximately $307,000 based on the estimated fair value of the options issued and recorded as an adjustment to equity. 45 On July 31, 2000, we issued an aggregate of 30,000 shares of our restricted common stock, at a price of $3.38 per share and valued at $116,000, to the shareholders of Saga Petroleum Corporation (Brent J. Morse, Morse Family Security Trust, and J. Charles Farmer) for an option to purchase certain properties owned by Saga and its affiliates. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance and recorded as a deposit on purchase of oil and gas properties. On August 3, 2000, we issued 21,875 shares of our restricted common stock, at a price of $3.38 per share and valued at $74,000, to CEC Inc. in exchange for an option to purchase certain properties owned by CEC Inc. and its partners. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time the Company committed to the transaction and recorded in oil and gas properties. On September 7, 2000, we issued 103,423 shares of our restricted common stock, at a price of $4.95 per share and valued at $512,000, to shareholders of Saga Petroleum Corporation in exchange for an option to purchase certain properties under a Purchase and Sale Agreement (see Form 8-K dated September 7, 2000). The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance and recorded as a deposit on purchase of oil and gas properties. On September 29, 2000, we issued 487,844 shares of our restricted common stock, at a price of $3.38 per share and valued at $1,646,000, to Castle Offshore LLC, a subsidiary of Castle Energy Corporation and BWAB Limited Liability Company ("BWAB"), as partial payment for properties in Louisiana. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time the Company committed to the transaction and is recorded in oil and gas properties. During the quarter ended September 30, 2000 we issued 100,000 shares of our restricted common stock at a price of $4.50 per share at a value of $450,000 to BWAB as a commission for its involvement with the North Dakota properties acquisition. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time the Commission was earned and is recorded in oil and gas properties. On October 2, 2000, we issued 289,583 shares of our restricted common stock, at a price of $4.61 per share and valued at $1,336,000, to Saga Petroleum Corporation and its affiliates as part of a deposit on the purchase of properties in West Texas and Southeastern New Mexico. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance. On October 11, 2000, we issued 138,461 shares of our restricted common stock to Giuseppe Quirici, Globemedia AG and Guadrafin AG for $450,000. We paid $45,000 to an unrelated individual and entity for their efforts and consultation related to the transaction. On January 3, 2001, we entered into an agreement with Evergreen, also a shareholder, whereby Evergreen acquired 116,667 shares of our restricted common stock for $350,000. We also issued an option to acquire an interest in 46 three undeveloped Offshore Santa Barbara, California properties until September 30, 2001. No book value was assigned to the option. Upon exercise, Evergreen would have been required to transfer the 116,667 shares of our common stock back to us and would have been responsible for 100% of all future minimum payments underlying the properties in which the interest is acquired. This option has expired. On January 12, 2001, we issued 490,000 shares of our restricted common stock to an unrelated entity for $1,102,000. We paid a cash commission of $110,000 to an unrelated individual and issued options to purchase 100,000 shares of our common stock at $3.25 per share to an unrelated company for its efforts in connection with the sale. The options were valued at approximately $200,000. Both the commission and the value of the options have been recorded as an adjustment to equity. On January 18, 2001 Franklin Energy LLC, an affiliate of BWAB Limited Liability Company, a less than 10% shareholder, earned 20,250 shares of our common stock for its assistance in the purchase of the Cedar State property. The shares issued were issued during our most recently completed fiscal quarter and valued at $81,000, which was a 10% discount to market, based on the quoted market price of our stock at the date of the acquisition. The shares were accounted for as an adjustment to the purchase price and capitalized to oil and gas properties. On April 13, 2001, Franklin Energy LLC, an affiliate of BWAB Limited Liability Company, a less than 10% shareholder, earned 10,000 shares of our common stock for its assistance in the sale of the West Delta property. The shares issued were valued at $40,000, which was a 10% discount to market, based on the quoted market price of our stock at the date the contract was entered into. The value of the stock was recorded as an adjustment to the sale price. Agreement with Swartz --------------------- On July 21, 2000, we entered into an investment agreement with Swartz Private Equity, LLC ("Swartz") and issued Swartz a warrant to purchase 500,000 shares of common stock exercisable at $3.00 per share until May 31, 2005. A warrant to purchase 150,000 shares of the Company's common stock at $3.00 per share for five years was also issued to another unrelated company as consideration for its efforts in this transaction and has been recorded as an adjustment to equity. In the aggregate, we issued options to Swartz and the other unrelated company valued at $1,436,000 as consideration for the firm underwriting commitment of Swartz and related services to be rendered and recorded in additional paid in capital. The options were valued at market based on the quoted market price at the time of issuance. The investment agreement entitles us to issue and sell ("Put") up to $20 million of our common stock to Swartz, subject to a formula based on our stock price and trading volume over a three year period following the effective date of a registration statement covering the resale of the shares to the public. Pursuant to the terms of this investment agreement the Company is not obligated to sell to Swartz all of the common stock referenced in the agreement nor does the Company intend to sell shares to the entity unless it is beneficial to the Company. 47 To exercise a Put, we must have an effective registration statement on file with the Securities and Exchange Commission covering the resale to the public by Swartz of any shares that it acquires under the investment agreement. The Company has filed a registration statement covering the Swartz transaction with the SEC. Swartz will pay us the lesser of the market price for each share minus $0.25, or 91% of the market price for each share of common stock under the Put. The market price of the shares of common stock during the 20 business days immediately following the date we exercise a Put is used to determine the purchase price Swartz will pay and the number of shares we will issue in return. If we do not Put at least $2,000,000 worth of common stock to Swartz during each one year period following the effective date of the Investment Agreement, we must pay Swartz an annual non-usage fee. This fee equals the difference between $200,000 and 10% of the value of the shares of common stock we Put to Swartz during the one year period. The fee is due and payable on the last business day of each one year period. Each annual non-usage fee is payable to Swartz, in cash, within five (5) business days of the date it accrued. We are not required to pay the annual non-usage fee to Swartz in years we have met the Put requirements. We are also not required to deliver the non-usage fee payment until Swartz has paid us for all Puts that are due. If the investment agreement is terminated, we must pay Swartz the greater of (i) the non-usage fee described above, or (ii) the difference between $200,000 and 10% of the value of the shares of common stock Put to Swartz during all Puts to date. We may terminate our right to initiate further Puts or terminate the investment agreement at any time by providing Swartz with written notice of our intention to terminate. However, any termination will not affect any other rights or obligations we have concerning the investment agreement or any related agreement. We cannot determine the exact number of shares of our common stock issuable under the investment agreement and the resulting dilution to our existing shareholders, which will vary with the extent to which we utilize the investment agreement and the market price of our common stock. The investment agreement provides that we cannot issue shares of common stock that would exceed 20% of the outstanding stock on the date of a Put unless and until we obtain shareholder approval of the issuance of common stock. We will seek the required shareholder approval under the investment agreement and under NASDAQ rules. Options ------- We received the proceeds from the exercise of options to purchase shares of our common stock of less than one thousand dollars, $1,480,000 and $1,378,000 during the three months ended September 30, 2001 and years ended June 30, 2001 and 2000, respectively. 48 Capital Resources ----------------- We expect to raise additional capital by selling our common stock in order to fund our capital requirements for our portion of the costs of the drilling and completion of development wells on our proved undeveloped properties during the next twelve months. There is no assurance that we will be able to do so or that we will be able to do so upon terms that are acceptable. We will continue to explore additional sources of both short-term and long-term liquidity to fund our operations and our capital requirements for development of our properties including establishing a credit facility, sale of equity or debt securities and sale of properties. Many of the factors which may affect our future operating performance and liquidity are beyond our control, including oil and natural gas prices and the availability of financing. After evaluation of the considerations described above, we presently believe that our cash flow from our existing producing properties and other sources of funds will be adequate to fund our operating expenses and satisfy our other current liabilities over the next year or longer. If it were necessary to sell an existing producing property or properties to meet our operating expenses and satisfy our other current liabilities over the next year or longer we believe we would have the ability to do so. Market Risk ------------ Market risk is the potential loss arising from adverse changes in market rates and prices, such as foreign currency exchange and interest rates and commodity prices. We do not use financial instruments to any degree to manage foreign currency exchange and interest rate risks and do not hold or issue financial instruments to any degree for trading purposes. All of our revenue and related receivables are payable in U.S. dollars. We do have a contract to sell 6,000 barrels a month at $27.31 through February 28, 2002. We were subject to interest rate risk on $8,593,000 of variable rate debt obligations at September 30, 2001. The annual effect of a one percent change in interest rates would be approximately $86,000. The interest rate on these variable rate debt obligations approximates current market rates as of September 30, 2001. Results of Operations --------------------- Three Months Ended September 30, 2001 Compared to Three Months Ended September 30, 2000 ------------------------------------------------- Income (loss). We reported a net loss for the three months ended September 30, 2001 of $244,000 compared to a net income of $270,000 for the three months ended September 30, 2001. The net loss and net income for the three months ended September 30, 2001 and 2000 were affected by numerous items, described in detail below. Revenue. Total revenue for the three months ended September 30, 2001 was $2,443,000 compared to $2,401,000 for the three months ended September 30, 49 2000. Oil and gas sales for the three months ended September 30, 2001 was $2,416,000 compared to $2,359,000 for the three months ended September 30, 2000. The decrease of $57,000 in oil and gas revenue is primarily attributed to the decrease in oil and gas prices which were offset by additional production relating to certain acquisitions during fiscal 2001. Other Revenue. Other revenue includes amounts recognized from production of gas previously deferred pending determination of our interests in the properties. Production volumes and average prices received for the three months ended September 30, 2001 and 2000 are as follows: Three Months Ended September 30, 2001 2000 Onshore Offshore Onshore Offshore Production: Oil (barrels) 27,262 69,219 22,589 71,819 Gas (Mcf) 149,009 -_ 129,050 - Average Price: Net of forward contract sales Oil (per barrel) $ 26.03 $ 17.41 $ 29.05 $ 15.81 Gas (per Mcf) $ 3.37 - $ 4.40 - Gross of forward contract sales* Oil (per barrel) $ 26.15 $ 17.41 $ 29.05 $ 24.63 Gas (per Mcf) $ 6.27 - $ 4.40 - *We sold 25,000 barrels of our offshore production per month from June 2000 to December 2000 at $14.65 per barrel under fixed price contracts with production purchases. We sold 6,000 barrels per month from March 1, 2001 through September 30, 2001 at $27.31 per barrel under fixed price contracts with production purchases. Lease Operating Expenses. Lease operating expenses were $721,000 for the three months ended September 30, 2001 compared to $943,000 for the same period in 2000. On a barrel equivalent basis, lease operating expenses were $3.84 for the three months ended September 30, 2001 compared to $3.85 for the same periods in 2000 for onshore properties. On a barrel equivalent basis, lease operating expenses were $7.53 for the three months ended September 30, 2001 compared to $10.77 for the same periods in 2000 for the offshore properties. The decrease in lease operating expense can be attributed to lower offshore operating costs after the completion of an extensive workover program during fiscal 2001. Depreciation and Depletion Expense. Depreciation and depletion expense for the three months ended September 30, 2001 was $793,000 compared to $465,000 for the same periods in 2000. On a barrel equivalent basis, the depletion rate was $10.82 for the three months ended September 30, 2001 and $6.63 for the same periods in 2000 for onshore properties. On a barrel equivalent basis, the depletion rate was $3.30 for the three months ended September 30, 2001 compared to $2.34 for the same periods in 2000 for offshore properties. The increase in depletion expense can be attributed to the acquisitions completed during fiscal 2001. 50 Exploration Expenses. We incurred exploration expenses of $72,000 for the three months ended September 30, 2001 compared to $13,000 for the same period in 2000. Exploration expense has increased from last year as the Company has expanded its activity in offshore California. Professional fees Professional fees for the three months ended September 30, 2001 were $324,000 compared to $230,000 for the same period in 2000. The increase in professional fees are primarily attributed legal fees for representation in negotiations and discussions with various state and federal governmental agencies relating to the company's undeveloped offshore California leases. General and Administrative Expenses. General and administrative expenses for the three months ended September 30, 2001 were $286,000 compared to $292,000 for the same periods in 2000. Stock Option Expense. Stock option expense has been recorded for the three months ended September 30, 2001 of $17,000 compared to $211,000 for the same period in 2000, for options granted to certain officers, directors, employees and consultants at option prices below the market price at the date of grant. Other income. Other income during the three months ended September 30, 2000 includes the sale of our unsecured claim in bankruptcy against our former parent, Underwriters Financial Group in the amount of $350,000. Interest and Financing Costs. Interest and financing costs for the three months ended September 30, 2001 were $352,000 compared to $338,000 for the same period in 2000. The increase in interest and financing costs can be attributed to the increase in amortization of deferred financing costs relating to the overriding royalties earned under the loan agreement with Kaiser-Francis Oil Company. Year Ended June 30, 2001 Compared to Year Ended June 30, 2000 -------------------------------------------------------------- Net Earnings (Loss). Our net income for the year ended June 30, 2001 was $345,000 compared to a net loss of $3,367,000 for the year ended June 30, 2000. The results for the years ended June 30, 2001 and 2000 were effected by the items described in detail below. Revenue. Total revenue for the year ended June 30, 2001 was $12,877,000 compared to $3,576,000 for the year ended June 30, 2000. Oil and gas sales for the year ended June 30, 2001 were $12,254,000 compared to $3,356,000 for the year ended June 30, 2000. The increase in oil and gas sales during the year ended June 30, 2001 resulted from the acquisitions of twenty producing wells, five injection wells located in Eland and Stadium fields in Stark County, North Dakota and the Cedar State gas property in Eddy County, New Mexico during fiscal 2001 and eleven producing wells in New Mexico and Texas and the acquisition of an interest in the offshore California Point Arguello Unit during fiscal 2000. The increase in oil and gas sales were also impacted by the increase in oil and gas prices. If we would not have sold our proportionate shares of our barrels offshore California at $8.25 and $14.65 per barrel under fixed price contracts with production purchases, we would 51 have realized an increase in income of $1,242,000 in 2001 and $2,033,000 in 2000. Gain on sale of oil and gas properties. During the years ended June 30, 2001 and 2000, we disposed of certain oil and gas properties and related equipment to unaffiliated entities. We have received proceeds from the sales of $3,700,000 and $75,000 which resulted in a gain on sale of oil and gas properties of $458,000 and $75,000 for the years ended June 30, 2001 and 2000, respectively. Other Revenue. Other revenue represents amounts recognized from the production of gas previously deferred pending determination of our interests in the properties. Production volumes and average prices received for the years ended June 30, 2001 and 2000 are as follows: 2001 2000 Onshore Offshore Onshore Offshore Production: Oil (barrels) 117,471 307,723 9,620 186,989 Gas (Mcf) 539,497 - 362,051 - Average Price: Net of forward contract sales Oil (per barrel) $27.10 $18.49 $25.95 $11.54 Gas (per Mcf) $ 6.27 - $ 2.62 - Gross of forward contract sales* Oil (per barrel) $27.30 $22.53 $25.95 $21.14 Gas (per Mcf) $ 6.27 - $ 2.62 - *We sold 25,000 barrels per month from December 1999 to May 2000 at $8.25 per barrel and we sold 25,000 barrels of our offshore production per month from June 2000 to December 2000 at $14.65 per barrel under fixed price contracts with production purchases. We sold 6,000 barrels per month from March 1, 2001 through June 30, 2001 at $27.31 per barrel under fixed price contracts with production purchases. Lease Operating Expenses. Lease operating expenses for the year ended June 30, 2001 were $4,698,000 compared to $2,405,000 for the year ended June 30, 2000. The increase in lease operating expense compared to 2000 resulted from the acquisitions of twenty producing wells and five injection wells in Stark County, North Dakota and the Cedar State gas property in Eddy County, New Mexico during fiscal 2001 and the acquisition of an interest in eleven new properties onshore and an interest in the offshore Point Arguello Unit near Santa Barbara, California during fiscal 2000. On a per Bbl equivalent basis, production expenses and taxes were $3.88 for onshore properties and $12.65 for offshore properties during the year ended June 30, 2001 compared to $4.94 for onshore properties and $11.02 for offshore properties for the year ended June 30, 2000. Depreciation and Depletion Expense. Depreciation and depletion expense for the year ended June 30, 2001 was $2,533,000 compared to $888,000 for the year ended June 30, 2000. On a per Bbl equivalent basis, the depletion rate was $8.16 for onshore properties and $2.71 for offshore properties during the 52 year ended June 30, 2001 compared to $4.64 for onshore properties and $3.00 for offshore properties for the year ended June 30, 2000. Exploration Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals. Exploration expenses were $89,000 for the year ended June 30, 2001 compared to $47,000 for the year ended June 30, 2000. Abandonment and Impairment of Oil and Gas Properties. We recorded an expense for the abandonment and impairment of oil and gas properties for the year ended June 30, 2001 of $798,000. Our proved properties were assessed for impairment on an individual field basis and we recorded impairment provisions attributable to certain producing properties of $174,000 for the year ended June 30, 2001. The expense in 2001 also includes a provision for impairment of the costs associated with the Kazakhstan licenses of $624,000. We made a determination based on the political risk and lack of expertise in the area that it may not be economical to develop this prospect and as such we may not proceed with this prospect. Based on an assessment of all properties as of June 30, 2000, there was no impairment for oil and gas properties in fiscal 2000. See impairment of Long-Lived Assets in "Description of Properties." Professional Fees. Professional fees for the year ended June 30, 2001 were $1,108,000 compared to $519,000 for the year ended June 30, 2000. The increase in professional fees compared to fiscal 2000 can be primarily attributed to legal fees for representation in negotiations and discussions with various state and federal governmental agencies relating to the Company's undeveloped offshore California leases. General and Administrative Expenses. General and administrative expenses for year ended June 30, 2001 were $1,470,000 compared to $1,258,000 for the year ended June 30, 2000. The increase in general and administrative expenses is primarily attributed to the increase in travel, corporate filings, salaries and contract labor. Stock Option Expense. Stock option expense has been recorded for the years ended June 30, 2001 and 2000 of $409,000 and $538,000, respectively, for options granted to certain officers, directors, employees and consultants at option prices below the market price at the date of grant. The stock option expense for fiscal 2001 and 2000 can primarily be attributed to options to certain consultants that provide us with shareholder relations services and options to our directors. Interest and Financing Costs. Interest and financing costs for the year ended June 30, 2001 were $1,861,000 compared to $1,265,000 for the year ended June 30, 2000. The increase in interest and financing costs can be attributed to the increase in the amortization of the deferred financing costs relating to the additional debt for the new acquisitions during fiscal 2001 primarily relating to the overriding royalties earned by Kaiser-Francis Oil Company pursuant to the loan agreement. Other Income. Other income of $528,000 for the year ended June 30, 2001 includes the sale of our unsecured claim in bankruptcy against our former parent, Underwriters Financial Group, in the amount of $350,000. 53 Year Ended June 30, 2000 Compared to Year Ended June 30, 1999 ------------------------------------------------------------- Net Earnings (Loss). Our net loss for the year ended June 30, 2000 was $3,367,000 compared to the net loss of $2,998,000 for the year ended June 30, 1999. The losses for the years ended June 30, 2000 and 1999 were effected by the items described in detail below. Revenue. Total revenue for the year ended June 30, 2000 was $3,576,000 compared to $1,695,000 for the year ended June 30, 1999. Oil and gas sales for the year ended June 30, 2000 were $3,356,000 compared to $558,000 for the year ended June 30, 1999. The increase in oil and gas sales during the year ended June 30, 2000 resulted from the acquisition of eleven producing wells in New Mexico and Texas and the acquisition of an interest in the offshore California Point Arguello Unit. The increase in oil and gas sales were also impacted by the increase in oil and gas prices. If we would have not committed to sell our proportionate shares of our barrels at $8.25 and $14.65 per barrel, we would have realized an increase in income of $2,033,000. Gain on sale of oil and gas properties. During the years ended June 30, 2000 and 1999, we disposed of certain oil and gas properties and related equipment to unaffiliated entities. We have received proceeds from the sales of $75,000 and $1,384,000, which resulted in a gain on sale of oil and gas properties of $75,000 and $957,000 for the years ended June 30, 2000 and 1999, respectively. Other Revenue. Other revenue represents amounts recognized from the production of gas previously deferred pending determination of our interests in the properties. Production volumes and average prices received for the years ended June 30, 2000 and 1999 are as follows: 2000 1999 Onshore Offshore Onshore Offshore ------- -------- ------- -------- Production: Oil (barrels) 9,620 186,989 5,574 - Gas (Mcf) 362,051 - 254,291 - Average Price: Oil (per barrel) $25.95 $11.54* $10.24 - Gas (per Mcf) $ 2.62 - $1.97 - Average Price-Offshore Point Arguello* Oil (per Bbls) gross price - $21.14 - - Oil (per Bbls) net price - $11.54 - - * We record oil and gas revenue net of all forward sales contracts. We sold 25,000 barrels per month from December 1999 to May 2000 at $8.25 per barrel and we have committed to sell 25,000 barrels per month from June 2000 to December 2000 at $14.65 per barrel under fixed price contracts with production purchases. The difference between gross and net price received are a result of these forward sales contracts. 54 Lease Operating Expenses. Lease operating expenses for the year ended June 30, 2000 were $2,405,000 compared to $210,000 for the year ended June 30, 1999. On a per Bbl equivalent basis, production expenses and taxes were $4.94 for onshore properties and $11.02 for offshore properties during the year ended June 30, 2000 compared to $4.37 for onshore properties for the year ended June 30, 1999. The increase in lease operating expense compared to 1999 resulted from the acquisition of an interest in eleven new properties onshore and an interest in the offshore Point Arguello Unit near Santa Barbara, California. In general the cost per Bbl for offshore operations are higher than onshore. The offshore properties had approximately $175,000 in non capitalized workover cost included in lease operating expense. Depreciation and Depletion Expense. Depreciation and depletion expense for the year ended June 30, 2000 was $888,000 compared to $229,000 for the year ended June 30, 1999. On a Bbl equivalent basis, the depletion rate was $4.64 for onshore properties and $3.00 for offshore properties during the year ended June 30, 2000 compared to $4.78 for onshore properties for the year ended June 30, 1999. Exploration Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals. Exploration expenses were $47,000 for the year ended June 30, 2000 compared to $75,000 for the year ended June 30, 1999. Abandonment and Impairment of Oil and Gas Properties. We recorded an expense for the abandonment and impairment of oil and gas properties for the year ended June 30, 1999 of $273,000. Our proved properties were assessed for impairment on an individual field basis and we recorded impairment provisions attributable to certain producing properties of $103,000 for the year ended June 30, 1999. The expense in 1999 also includes a provision for impairment of the costs associated with the Sacramento Basin of Northern California of $170,000. We made a determination based on drilling results that it would not be economical to develop certain prospects and as such we will not proceed with these prospects. Based on an assessment of all properties as of June 30, 2000, there was no impairment for oil and gas properties in fiscal 2000. Professional Fees and General and Administrative Expenses. General and administrative expenses for the year ended June 30, 2000 were $1,777,000 compared to $1,505,000 for the year ended June 30, 1999. The increase in general and administrative expenses compared to fiscal 1999, can be attributed to an increase in shareholder relations and professional services relating to Securities and Exchange related filings. Stock Option Expense. Stock option expense has been recorded for the years ended June 30, 2000 and 1999 of $538,000 and $2,081,000, respectively, for options granted to and/or re-priced for certain officers, directors, employees and consultants at option prices below the market price at the date of grant. The stock option expense for fiscal 2000 can primarily be attributed to repricing options to certain consultants that provide us with shareholder relations services. The most significant amount of the stock option expense for fiscal 1999 can be attributed to a grant by the Incentive Plan Committee ("Committee") of options to purchase 89,686 shares of our common stock and the re-pricing of 980,477 options to purchase shares of our common stock for two of our officers at a price of $.05 per share under the Incentive Plan. The Committee also re-priced 150,000 options to purchase 55 shares of our common stock to two employees at a price of $1.75 per share under the Incentive Plan. Stock option expense in fiscal 1999 of $1,985,414 was recorded based on the difference between the option price and the quoted market price on the date of grant and re-pricing of the options. Interest and Financing Costs. Interest and financing costs for the years ended June 30, 2000 and 1999 were $1,265,000 and $20,000, respectively. The increase in interest and financing costs can be attributed to the new debt established to purchase oil and gas properties. Recently Issued or Proposed Accounting Standards and Pronouncements ------------------------------------------------------------------- In July 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets" and approved for issuance SFAS No. 143, "Accounting for Asset Retirement Allocations." SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated or completed after June 30, 2001. SFAS No. 141 also specifies criteria that intangible assets acquired in a purchase method business combination must meet to be recognized and reported apart from goodwill. The adoption of SFAS No. 141 will have no impact on our fiscal 2001 financial statements. SFAS No. 142 requires that goodwill no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142. Any goodwill and any intangible asset determined to have an indefinite useful life that are acquired in a purchase business combination completed after June 30, 2001 will not be amortized, but will be evaluated for impairment in accordance with the appropriate existing accounting literature. The adoption will have no impact on our fiscal 2001 financial statements. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset and is effective for fiscal years beginning after June 15, 2002. Management is currently assessing the impact SFAS No. 143 will have on our financial condition and results of operations. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment of Disposal of Long-Lived Assets, which is effective for fiscal years beginning after December 15, 2001. SFAS No. 144 establishes one accounting model to be used for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations to included more disposal transaction. We are currently assessing the impact SFAS No. 144 will have on our financial condition and results of operations. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS Executive Officers and Directors -------------------------------- Our Directors and Executive Officers are listed below. Executive Officers are elected by the Board of Directors and hold office until their successors are elected and qualified. 56 Name Age Positions Period of Service Aleron H. Larson, Jr. 56 Chairman of the Board, May 1987 to Present Secretary, and a Director Roger A. Parker 40 President, Chief May 1987 to Present Executive Officer and a Director Jerrie F. Eckelberger 57 Director September 1996 to Present James P. Wallace 72 Director November 2001 to Present Kevin K. Nanke 36 Treasurer and Chief December 1999 Financial Officer to Present The following is additional biographical information as to the business experience of each of our current officers and directors. ALERON H. LARSON, JR., age 56, has operated as an independent in the oil and gas industry individually and through public and private ventures since 1978. From July of 1990 through March 31, 1993, Mr. Larson served as the Chairman, Secretary, CEO and a Director of Chippewa Resources Corporation (now called "Underwriters Financial Group, Inc."), a public company then listed on the American Stock Exchange which was previously our parent ("UFG"). Subsequent to a change of control, Mr. Larson resigned from all positions with UFG effective March 31, 1993. Mr. Larson serves as Chairman, CEO, Secretary, Treasurer and Director of Amber Resources Company ("Amber"), a public oil and gas company which is our majority-owned subsidiary. He has also served, since 1983, as the President and Board Chairman of Western Petroleum Corporation, a public Colorado oil and gas company which is now inactive. Mr. Larson practiced law in Breckenridge, Colorado from 1971 until 1974. During this time he was a member of a law firm, Larson & Batchellor, engaged primarily in real estate law, land use litigation, land planning and municipal law. In 1974, he formed Larson & Larson, P.C., and was engaged primarily in areas of law relating to securities, real estate, and oil and gas until 1978. Mr. Larson received a Bachelor of Arts degree in Business Administration from the University of Texas at El Paso in 1967 and a Juris Doctor degree from the University of Colorado in 1970. ROGER A. PARKER, age 40, served as the President, a Director and Chief Operating Officer of Chippewa Resources Corporation (now called "Underwriters Financial Group, Inc.") from July of 1990 through March 31, 1993. Mr. Parker resigned from all positions with UFG effective March 31, 1993. Mr. Parker also serves as President, Chief Operating Officer and Director of Amber. He also serves as a Director and Executive Vice President of P & G Exploration, Inc., a private oil and gas company (formerly Texco Exploration, Inc.). Mr. Parker has also been the President, a Director and sole shareholder of Apex Operating Company, Inc. since its inception in 1987. He has operated as an independent in the oil and gas industry individually and through public and private ventures since 1982. He was at various times, from 1982 to 1989, a Director, Executive Vice President, President and shareholder of Ampet, Inc. He received a Bachelor of Science in Mineral Land Management from the 57 University of Colorado in 1983. He is a member of the Rocky Mountain Oil and Gas Association and the Independent Producers Association of the Mountain States (IPAMS). JERRIE F. ECKELBERGER, age 57, is an investor, real estate developer and attorney who has practiced law in the State of Colorado since 1971. He graduated from Northwestern University with a Bachelor of Arts degree in 1966 and received his Juris Doctor degree in 1971 from the University of Colorado School of Law. From 1972 to 1975, Mr. Eckelberger was a staff attorney with the eighteenth Judicial District Attorney's Office in Colorado. From 1982 to 1992 Mr. Eckelberger was the senior partner of Eckelberger & Feldman, a law firm with offices in Englewood, Colorado. In 1992, Mr. Eckelberger founded Eckelberger & Associates of which he is still the principal member. Mr. Eckelberger previously served as an officer, director and corporate counsel for Roxborough Development Corporation. Since March 1996, Mr. Eckelberger has acted as President and Chief Executive Officer of 1998, Ltd., a Colorado corporation actively engaged in the development of real estate in Colorado. He is the Managing Member of The Francis Companies, L.L.C., a Colorado limited liability company, which actively invests in real estate and has been since June, 1996. Additionally, since November, 1997, Mr. Eckelberger has served as the Managing Member of the Woods at Pole Creek, a Colorado limited liability company, specializing in real estate development. JAMES B. WALLACE, age 72, has been involved in the oil and gas business for over 40 years and has been a partner of Brownlie, Wallace, Armstrong and Bander Exploration in Denver, Colorado since 1992. From 1980 to 1992 he was Chairman of the Board and Chief Executive Officer of BWAB Incorporated. Mr. Wallace currently serves as Chairman of the Board of Directors of Tom Brown, Inc., an oil and gas exploration company listed on the Nasdaq Natoinal Market System. He received a B.S. Degree in Business Administration from the University of Southern California in 1951. KEVIN K. NANKE, age 36, Chief Financial Officer, joined Delta in April 1995. Since 1989, he has been involved in public and private accounting with the oil and gas industry. Mr. Nanke received a Bachelor of Arts in Accounting from the University of Northern Iowa in 1989. Prior to working with Delta, he was employed by KPMG LLP. He is a member of the Colorado Society of CPA's and the Council of Petroleum Accounting Society. Mr. Nanke is not a nominee for election as a director. There is no family relationship among or between any of our Officers and/or Directors. Messrs. Eckelberger and Wallace serve as the audit committee and as the compensation committee. Messrs. Eckelberger and Wallace also constitute our Incentive Plan Committee for the Delta 1993 Incentive Plan. Our Compensation Committee makes recommendations to our Board in the area of executive compensation. Our Audit Committee is appointed for the purpose of overseeing and monitoring our independent audit process. It is also charged with the responsibility for reviewing all related party transactions for potential conflicts of interest. The Incentive Plan Committee is charged with the responsibility for selecting individual employees to be issued options and other grants under our 2001 Incentive Plan. Members of the Incentive Plan Committee, as non-employee directors, are 58 automatically awarded options on an annual basis under a fixed formula under our 2001 Incentive Plan. (See "Compensation of Directors"). All directors will hold office until the next annual meeting of shareholders. All of our officers will hold office until the next annual directors' meeting. There is no arrangement or understanding among or between any such officers or any persons pursuant to which such officer is to be selected as one of our officers. Indemnification --------------- The Articles of Incorporation and the Bylaws provide that we may indemnify our officers and directors for costs and expenses incurred in connection with the defense of actions, suits, or proceedings where the officer or director acted in good faith and in a manner he reasonably believed to be in our best interest and is a party to such actions by reason of his status as an officer or director. Insofar as indemnification for liabilities arising under the Securities Act of 1933 (the "Act") may be permitted to directors, officers and controlling persons pursuant to the foregoing provisions or otherwise, we have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. EXECUTIVE COMPENSATION Summary Compensation -------------------- The following table shows the aggregate direct remuneration for the fiscal years ended June 30, 2001, 2000, and 1999 to each executive officer: 59

Summary Compensation Table -------------------------- Long Term Compensation ---------------------------------------- Annual Compensation Awards(11) Payouts ---------------------------------- ---------------------- ---------------- Securities All Other Underlying Other Annual Restricted Options/ LTIP Compen- Name and Principal Salary(1) Compen- Stock SARs Payouts sation Position Year ($) Bonus($) sation($) Award(s) (#) ($) ($) ------------------ ---- --------- -------- ------------ --------- ---------- ------- ------- Roger A. Parker 2001 198,000 91,000 0 0 750,000(2) 0 0 Chief Executive 2000 198,000 75,000 0 0 100,000(3) 0 0 Officer and 1999 198,000 105,000 0 0 510,663(4) 0 0 President Aleron H. Larson, Jr. 2001 198,000 91,000 0 0 750,000(2) 0 0 Chairman, Secretary 2000 198,000 75,000 0 0 100,000(3) 0 0 and Director 1999 198,000 105,000 0 0 559,500(5) 0 0 Kevin K. Nanke 2001 120,000 55,000 0 0 225,000(6) 0 0 Chief Financial 2000 105,000 15,000 0 0 100,000(7) 0 0 Officer and Treasurer

(1) Includes reimbursement of certain expenses. (2) Includes options to purchase 300,000 shares of common stock at $3.75 per share until July 14, 2010; options purchase 250,000 shares of common stock at $5.00 per share until October 9, 2010; and options to purchase 200,000 shares of common stock at $3.29 per share until January 8, 2011. (3) Option to purchase 100,000 shares of common stock at $1.75 per share until November 5, 2009. (4) Represents all options held by individual at June 30, 2000. Includes 320,977 previously granted options and 100,000 options granted during fiscal 1999 for which the exercise price was repriced during fiscal 1999 to $0.05 per share and the expiration date extended to 9/01/08 for 320,977 options and to 12/01/08 for 100,000 options. Also includes a grant of options to purchase 89,686 shares of common stock at $0.05 per share until 5/20/09. (5) Represents all options held by individual at June 30, 2000. Includes 459,500 previously granted options and 100,000 options granted during fiscal 1999 for which the exercise price was repriced during fiscal 1999 to $0.05 per share and the expiration date extended to 9/01/08 for 459,500 options and to 12/01/08 for 100,000 options. (6) Includes options to purchase 125,000 shares of common stock at $3.75 per share until July 14, 2010; and options to purchase 100,000 shares of common stock at $3.29 per share until January 8, 2011. 60 (7) Represents options to purchase 75,000 shares of common stock at $1.75 per share until November 5, 2009 and options to purchase 25,000 shares of common stock at $.01 per share until December 31, 2009. Option/SAR Grants in last Fiscal Year - Individual Grants ---------------------------------------------------------

Percent Number of of Total Securities Options/SAR's Exercise Market Underlying Granted to or Base Price on Options/SAR's Employees in Price Date of Expiration Name Granted Fiscal Year ($/Sh) Grant($/sh) Date --------------------- ------------- ------------- -------- ----------- ---------- Roger A. Parker 300,000 15.94% $3.75 $3.75 07/14/10 250,000 13.28% 5.00 5.00 10/09/10 200,000 10.62% 3.29 3.29 01/08/11 Aleron H. Larson, Jr. 300,000 15.94% $3.75 $3.75 07/14/10 250,000 13.28% 5.00 5.00 10/09/10 200,000 10.62% 3.29 3.29 01/08/11 Kevin K. Nanke 125,000 6.64% $3.75 $3.75 07/14/10 100,000 5.31% 3.29 3.29 10/01/10

Aggregated Options/Exercises in Last Fiscal Year and Year-End Option/Values ---------------------------------------------------------------------------

Number of Securities Value of Underlying Unexercised Unexercised in-the-Money Options Options Shares at at Acquired June 30, 2001(#) June 30, 2001($) on Realized Exercisable/ Exercisable/ Name Exercise (#) $ Unexercisable Unexercisable --------------------- ------------ ----------- ---------------- ------------------ Roger A. Parker 250,236 $1,048,000 850,000/0 $ 802,000/0 President, Chief Executive Officer and Director Aleron H. Larson, Jr. 92,810 $ 406,000 1,276,690/0 $2,743,000/0 Chairman, Secretary and Director Kevin K. Nanke 59,725 $ 194,000 464,175/0 $ 946,000/0 Chief Financial Officer and Treasurer

61 Compensation of Directors ------------------------- As a result of elections made by non-employee directors under the formulas provided in our 2001 Incentive Plan, as amended, we granted options to non-employee directors after the fiscal year end as follows: Number Exercise Expiration Director of Options Price Date Terry D. Enright 20,000 $1.95/sh 9/10/2011 Jerrie F. Eckelberger 20,000 1.95/sh 9/10/2011 In addition, the outside non-employee directors are each paid $500 per month. Jerrie F. Eckelberger and Terry D. Enright were each paid $6,000 during the year ended June 30, 2001. Mr. Enright resigned as a Director on November 15, 2001. In connection with his resignation he received 2,500 shares of our restricted Common Stock and is also entitled to receive his compensation for the portion of the calendar year 2001 served (January 1, 2001 through November 15, 2001) in the form of either Common Stock or options, at his election, under our 2001 Incentive Plan. Incentive Compensation Plan --------------------------- On October 25, 2001, the Board of Directors adopted the 2002 Incentive Plan ("2002 Plan"), which will be submitted for ratification by our shareholders at the next meeting of the shareholders. The maximum number of shares of Common Stock that may be issued under the 2002 Plan is 2,000,000 shares. Employment Contracts and Termination of Employment and Change-in-Control Agreement -------------------------------------------------- On November 1, 2001, our Compensation Committee authorized us to enter into employment agreements with our Chairman, President and Chief Financial Officer which employment agreements replaced and superseded the prior employment agreements with these persons. Under the employment agreements our Chairman and President each receive a salary of $240,000 per year and our Chief Financial Officer receives a salary of $144,000 per year. Their employment agreements have five-year terms and include provisions for cars, parking and health insurance. Terms of their employment agreements also provide that the employees may be terminated for cause but that in the event of termination without cause or in the event we have a change in control, as defined in our 2001 Incentive Plan, then the employees will continue to receive the compensation provided for in the employment agreements for the remaining terms of the employment agreements. Also in the event of a change of control and irrespective of any resulting termination, we will immediately cause all of each employee's then outstanding unexercised options to be exercised by us on behalf of the employee and we will pay the employee's federal, state and local taxes applicable to the exercise of the options and warrants. 62 Retirement Savings Plan ----------------------- During 1997 we began sponsoring a qualified tax deferred savings plan in the form of a Savings Incentive Match Plan for Employees ("SIMPLE") IRA plan available to companies with fewer than 100 employees. Under the SIMPLE IRA plan, our employees may make annual salary reduction contributions of up to three percent (3%) of an employee's base salary up to a maximum of $6,000 (adjusted for inflation) on a pre-tax basis. We will make matching contributions on behalf of employees who meet certain eligibility requirements. During the fiscal year ended June 30, 2001, we contributed $11,000 under the plan. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Security Ownership of Certain Beneficial Owners and Security Ownership of Management (a) Security Ownership of Certain Beneficial Owners: The following table presents information concerning persons known by us to own beneficially 5% or more of our issued and outstanding voting securities at November 29, 2001: Name and Address Amount and Nature of Beneficial of Beneficial Percent Title of Class (1) Owner Ownership of Class(2) Common stock Aleron H. Larson, Jr. 1,468,157 shares(3) 11.64% (includes options 555 17th St., #3310 for common stock) Denver, CO 80202 Common stock Roger A. Parker 1,375,557 shares(4) 11.28% (includes options 555 17th St., #3310 for common stock) Denver, CO 80202 Common stock GlobeMedia AG 805,846 shares(5) 6.85% (includes options Immanuel Hohlbauch for common stock) Strasse 41 Goppingen/Germany Common stock Burdette A. Ogle 761,891 shares(6) 6.76% (includes options 1224 Coast Village Rd, #24 for common stock) Santa Barbara, CA 93108 Common stock BWAB Limited Liability 702,930 shares(7) 6.30% Company 475 17th Street Suite 1390 Denver, CO 80202 Common stock Bank Leu AG 692,721 shares(8) 6.20% Bahnhofstrasse 32 8022 Switzerland 63 Common stock Evergreen Resources, Inc. 643,061 shares 5.76% 1401 17th Street Suite 1200 Denver, CO 80202 Common stock Kevin K. Nanke 589,175 shares(9) 5.02% (includes options 555 17th St., #3310 for common stock) Denver, CO 80202 ------------------------------ (1) We have an authorized capital of 300,000,000 shares of $.01 par value common stock of which 11,164,826 shares were issued and outstanding as of October 10, 2001. We also have an authorized capital of 3,000,000 shares of $.10 par value preferred stock of which no shares are outstanding (2) The percentage set forth after the shares listed for each beneficial owner is based upon total shares of common stock outstanding at October 10, 2001 of 11,164,826. The percentage set forth after each beneficial owner is calculated as if any warrants and/or options owned had been exercised by such beneficial owner and as if no other warrants and/or options owned by any other beneficial owner had been exercised. Warrants and options are aggregated without regard to the class of warrant or option. (3) Includes 12,467 shares owned by Mr. Larson's wife and 4,000 shares owned by his children; and 426,690 options to purchase 426,690 shares of common stock at $0.05 per share until September 21, 2008 for 151,690 of the options, until September 1, 2008 for 175,000 of the options and until December 10, 2008 for 100,000 of the options. Also includes options to purchase 100,000 shares of common stock at $1.75 per share until November 5, 2009; options to purchase 300,000 shares of common stock at $3.75 per share until July 14, 2010; options to purchase 250,000 shares of common stock at $5.00 per share until October 9, 2010; options to purchase 200,000 shares of common stock at $3.29 per share until January 8, 2011; and options to purchase 175,000 shares of common stock at $2.38 per share until October 5, 2011. (4) Includes 354,557 shares owned by Mr. Parker directly. Also includes options to purchase 100,000 shares of common stock at $1.75 until November 5, 2009; options to purchase 300,000 shares of common stock at $3.75 per share until July 14, 2010; options to purchase 250,000 shares of common stock at $5.00 per share until October 9, 2010; options to purchase 200,000 shares of common stock at $3.29 per share until January 8, 2011; and options to purchase 175,000 shares of common stock at $2.38 per share until October 5, 2011. (5) Consists of 90,692 shares owned directly by GlobeMedia AG; 54,000 shares owned by its president, Karl Spoddig; 10,000 shares owned by GlobeMedia Gmbh; 46,154 shares owned by Quadrafin AG; options to purchase 5,000 shares of common stock at $2.50 per share until April 10, 2002; options to purchase 200,000 shares of common stock at $4.5625 per share for a period of one year beginning with the effective date of a registration statement covering the shares underlying the options; options in the name of Pegasus Finance Limited, an affiliate of GlobeMedia AG, to purchase common stock for periods beginning with the effective date of a registration statement covering the common shares underlying the options as follows: 100,000 shares at $2.50 per share for one year; 100,000 shares at $3.00 per share for one year; 100,000 shares at $6.00 per share for one year; and options, also in the name of Pegasus Finance 64 Limited, to purchase 100,000 shares of common stock at $3.125 per share until January 9, 2004. (6) Includes 635,264 shares owned by Mr. Ogle directly, 26,627 shares owned beneficially by Sunnyside Production Company, and warrants to purchase 100,000 shares of common stock at $3.00 per share until August 31, 2004, with a call provision that allows us to repurchase any unexercised warrants for an aggregate sum of $1,000 after our stock has traded for $6.00 per share or greater for 30 consecutive trading days. (7) Includes 672,680 shares owned directly and 30,250 shares owned by an affiliate, Franklin Energy, LLC. (8) Shares are held by Bank Leu AG as nominee for various beneficial owners, none of which owns beneficially greater than 5% of our stock. Bank Leu AG holds record title only and does not have voting or investment power for the shares. (9) Consists of 25,000 shares of common stock owned directly by Mr. Nanke; options to purchase 39,175 shares of common stock at $1.125 per share until September 1, 2008; options to purchase 25,000 shares of common stock at $1.5625 per share until December 12, 2008; options to purchase 100,000 shares of common stock at $1.75 per share until May 12, 2009; options to purchase 75,000 shares of common stock at $1.75 per share until November 5, 2009; options to purchase 125,000 shares of common stock at $3.75 per share until July 14, 2010; options to purchase 100,000 shares of common stock at $3.29 until January 9, 2011; and options to purchase 100,000 shares of common stock at $2.38 per share until October 5, 2011. (b) Security Ownership of Management: Name and Address Amount and Nature of Beneficial of Beneficial Percent Title of Class (1) Owner Ownership of Class(2) Common stock Aleron H. Larson, Jr. 1,468,157 shares(3) 11.64% Common stock Roger A. Parker 1,375,557 shares(4) 11.28% Common stock Kevin K. Nanke 589,175 shares(5) 5.02% Common stock Jerrie F. Eckelberger 20,725 shares(7) 0.19% Common stock James B. Wallace 30,000 shares 0.29% Common stock Officers and Directors 3,483,614 shares(8) 24.44% as a Group (5 persons) ------------------------------ (1) See Note (1) to preceding table; includes options. (2) See Note (2) to preceding table. (3) See Note (3) to preceding table. (4) See Note (4) to preceding table. (5) See Note (9) to preceding table. 65 (6) Includes 10,000 Class I warrants to purchase shares of common stock at $3.50 per share until June 9, 2003 and options to purchase 20,000 shares of common stock at $1.95 until September 10, 2001. (7) Includes 725 options to purchase shares of common stock at $2.98 per share until December 31, 2006 and options to purchase 20,000 shares of common stock at $1.95 until September 10, 2011 (8) Includes all warrants, options and shares referenced in footnotes (3), (4), (5), (6) and (7) above as if all warrants and options were exercised and as if all resulting shares were voted as a group. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The following is a list of certain relationships and related party transactions that occurred during our past fiscal year and the two previous fiscal years, as well as transactions that occurred since the beginning of our last fiscal year or are currently proposed: (a) Effective October 28, 1992, we entered into a five year consulting agreement with Burdette A. Ogle and Ronald Heck which provides for an aggregate fee to the two of them of $10,000 per month. We agreed to extend this agreement for one year during the 1998 fiscal year and, subsequent to June 30, 1998, agreed to extend it through December 1, 1999. Subsequent to December 1, 1999 we have retained Messrs. Ogle and Heck on a month to month basis at the same monthly rate. At January 17, 2001, Messrs. Ogle and Heck owned beneficially 6.87% and 2.28%, respectively, of our outstanding Common Stock. To our best knowledge and belief, the consulting fee paid to Messrs. Ogle and Heck is comparable to those fees charged by Messrs. Ogle and Heck to other companies owning interests in properties offshore California for consulting services rendered to those other companies with respect to their own offshore California interests. It is our understanding that, in the aggregate, Mr. Ogle represents, as a consultant, a significant percentage of all of the ownership interests in the various properties that are located in the same general vicinity of our offshore California properties. Mr. Ogle also consults with and advises us relative to properties in areas other than offshore California, relative to potential property acquisitions and with respect to our general oil and gas business. It is our opinion that the fees paid to Messrs. Ogle and Heck for the services rendered are comparable to fees that would be charged by similarly qualified non-affiliated persons for similar services. (b) Effective February 24, 1994, at the time Ogle was the owner of 21.44% of our stock, he granted us an option to acquire working interests in three undeveloped offshore Santa Barbara, California, federal oil and gas units. In August 1994, we issued a warrant to Ogle to purchase 100,000 shares of our common stock for five years at a price of $8 per share in consideration of the agreement by Ogle to extend the expiration date of the option to January 3, 1995. On January 3, 1995, we exercised the option from Ogle to acquire the working interests in three proved undeveloped offshore Santa Barbara, California federal oil and gas units. The purchase price of $8,000,000 is represented by a production payment reserved in the documents of Assignment and Conveyance and will be paid out of three percent (3%) of the oil and gas production from the working interests with a requirement for minimum annual payments. We paid Ogle $1,550,000 through fiscal 1999 and are 66 to continue to pay a minimum of $350,000 annually until the earlier of: 1) when the production payments accumulate to the $8,000,000 purchase price; 2) when 80% of the ultimate reserves of any lease have been produced; or 3) 30 years from the date of the conveyance. Under the terms of the agreement, we may reassign the working interests to Ogle upon notice of not more than 14 months nor less than 12 months, thereby releasing us of any further obligations to Ogle after the reassignment. On December 17, 1998, we amended our Purchase and Sale Agreement with Ogle dated January 3, 1995. As a result of this amended agreement, at the time of each minimum annual payment we will be assigned an interest in the three undeveloped offshore Santa Barbara, California federal oil and gas units proportionate to the total $8,000,000 production payment. Accordingly, the annual $350,000 minimum payment is recorded as an addition to undeveloped offshore California properties. In addition, pursuant to this agreement, we extended and repriced the previously issued warrant to purchase 100,000 shares of our Common Stock. Prior to fiscal 1999, the minimum royalty payment was expensed in accordance with the purchase and sale agreement with Ogle dated January 3, 1995. As of September 30, 2001, we had paid a total of $2,250,000 in minimum royalty payments. The terms of the original transaction and the amendment with Mr. Ogle were arrived at through arms-length negotiations initiated by our management. We are of the opinion that the transaction is on terms no less favorable to us than those which could have been obtained from non-affiliated parties. No independent determination of the fairness and reasonableness of the terms of the transaction was made by any outside person. (c) Our Board of Directors has granted our officers the right to participate on a non-promoted basis in up to a five percent (5%) working interest in any well drilled, re-entered, completed or recompleted by us on our acreage (provided that any well to be re-entered or recompleted is not then producing economic quantities of hydrocarbons) Messrs. Larson and Parker are required to pay us the unpromoted cost thereof. (d) On November 1, 2001, our Compensation Committee authorized us to enter into employment agreements with our Chairman, President and Chief Financial Officer, which employment agreements replaced and superseded the prior employment agreements with such persons. The employment agreements have five year terms and include provisions for cars, parking and health insurance. Terms of the employment agreements also provide that the employees may be terminated for cause but that in the event of termination without cause or in the event we have a change in control, as defined in our 2001 Incentive Plan, as amended, then the employees will continue to receive the compensation provided for in the employment agreements for the remaining terms of the employment agreements. Also in the event of a change of control and irrespective of any resulting termination, we will immediately cause all of each employee's then outstanding unexercised options to be exercised by us on behalf of the employee with us paying the employee's federal, state and local taxes applicable to the exercise of the options and warrants. (e) On January 6, 1999, we and our Compensation Committee authorized our officers to purchase shares of the common stock of another company, Bion Environmental Technologies, Inc. ("Bion"), which were held by us as "securities available for sale," at the market closing price on that date not 67 to exceed $105,000 per officer. Our Chairman, Aleron H. Larson, Jr., purchased 29,900 shares of Bion from us for $89,000. (f) On January 3, 2000, we and our Compensation Committee authorized our officers to purchase shares of Bion which were held by us as "securities available for sale" at the market closing price on that day. Our officers purchased 47,250 shares for $238,000. (g) Our officers, Aleron H. Larson, Jr., our current Chairman and Secretary, and Roger A. Parker, our current President and CEO, loaned us $1,000,000 to make our June 8, 1999 payment to Whiting Petroleum Corporation ("Whiting") required under our agreement with Whiting, also dated June 8, 1999 to acquire Whiting's interests in the Point Arguello Unit and the adjacent Rocky Point Unit. In connection with this loan, Mr. Parker was issued options under our 1993 Incentive Plan, as amended, to purchase 89,868 shares at $.05 per share and the exercise prices of the existing options of Messrs. Parker and Larson were reduced to $.05 per share. (See Form 8-K/A dated June 9, 1999.) (h) On July 30, 1999, we borrowed $2,000,000 from an unrelated entity which was personally guaranteed by Aleron H. Larson, Jr., our current Chairman and Secretary, and Roger A. Parker, our current President and CEO. The proceeds were applied to the acquisition of Whiting's interests in the Point Arguello Unit and adjacent Rocky Point Unit. As consideration for the guarantee of our indebtedness we agreed to assign a 1% overriding royalty interest to each officer in the properties acquired with the proceeds of the loan (proportionately reduced to the interest we acquired in each property). (See Form 8-K dated August 25, 1999.) (i) On November 1, 1999 we borrowed approximately $2,800,000 from an unrelated entity which was personally guaranteed by Aleron H. Larson, Jr., our current Chairman and Secretary, and Roger A. Parker, our current President and CEO. The loan proceeds were used to purchase eleven producing wells and associated acreage in New Mexico and Texas. As consideration for the guarantee of our indebtedness we agreed to assign a 1% overriding royalty interest to each officer in the properties acquired with the proceeds of the loan (proportionately reduced to the interest we acquired in each property). (See Form 8-K dated November 1, 1999.) (j) On December 1, 1999, our Incentive Plan Committee granted Kevin K. Nanke, our Chief Financial Officer, 25,000 options to purchase our common stock at $.01 per share. (k) We operate wells in which our officers or employees or companies affiliated with one of them own working interests. At June 30, 2001 we had $272,000 of net receivables from these related parties (including affiliated companies) primarily for drilling costs and lease operating expenses on wells operated by us. (l) On July 10, 2000, we borrowed $3,795,000 from an unrelated entity which was personally guaranteed by Aleron H. Larson, Jr., our current Chairman and Secretary, and Roger A. Parker, our current President and CEO. The loan proceeds were used by us to purchase interests in producing wells and acreage in the Eland and Stadium fields in Stark County, North Dakota. As consideration for the guarantee of our indebtedness we agreed to issue 300,000 68 options to each of Messrs. Larson and Parker to purchase our common stock for $3.75 per share until July 14, 2010. (m) During the two years ended September 30, 2001 we issued options to GlobeMedia AG and its affiliate, Pegasus Finance, Ltd., as consideration for services relating to raising capital for us in Europe as follows: November 23, 1999, options to purchase 250,000 shares of common stock at $2.50 per share; July 5, 2000, options to purchase 100,000 shares of common stock at $2.50 per share; July 5, 2000, options to purchase 100,000 shares at $3.00 per share; and January 8, 2001, options to purchase 100,000 shares of common stock at $3.125 per share. During the same period we issued options to GlobeMedia AG for services relating to shareholder and public relations in Europe as follows: November 23, 1999, options to purchase 250,000 shares of common stock at $2.50 per share; February 17, 2000, options to purchase 200,000 shares of common stock at $2.50 per share; July 5, 2000, options to purchase 100,000 shares of common stock at $6.00 per share; and March 21, 2001, and options to purchase 200,000 shares of common stock at $4.5625 per share. In addition, during this period we sold 30,692 shares of restricted common stock to GlobeMedia AG on October 11, 2000 at $3.25 per share and we sold 46,154 shares of restricted common stock to Quadrafin AG, an affiliate of GlobeMedia AG, on October 11, 2000 at $3.25 per share. During the past two years we have paid GlobeMedia approximately $105,000 for services and expenses relating to shareholder and public relations in Europe and approximately $285,000 in commissions for raising additional capital. (n) On January 4, 2000 we sold 175,000 shares of restricted common stock at a price of $2.00 per share and on January 3, 2001 we sold 116,667 shares of restricted common stock at a price of $3.00 per share to Evergreen Resources, Inc. In connection with these purchases we gave Evergreen Resources, Inc. an option to acquire an interest in some of our undeveloped properties until September 30, 2001. The option has expired. (o) During the past two years ended September 30, 2001 we issued 315,000 shares of restricted common stock to BWAB Limited Liability Company ("BWAB") in exchange for services related to the acquisition of properties. On September 26, 2000 we exchanged 127,430 shares of restricted common stock and paid $382,000 to BWAB in exchange for producing properties in Louisiana. On January 8, 2001 we issued 200,000 shares of restricted common stock to BWAB as a result of the conversion of a promissory note in the amount of $500,000. (p) On September 29, 2000 we acquired the West Delta Block 52 Unit from Castle Offshore LLC and BWAB Limited Liability Company as described in our Form 8-K dated September 29, 2000, by paying $1,529,000 and issuing 509,719 shares of our restricted common stock at $3.00 per share. We borrowed $1,464,000 of the cash portion of the purchase price from an unrelated entity. To induce this lender to make the loan to us, two of our officers, Aleron H. Larson, Jr., Chairman and Secretary, and Roger A. Parker, President and CEO, agreed to personally guarantee the loan. As consideration for the guarantees of our indebtedness we permitted each of these two officers to purchase up to 5% of the working interest acquired by us in the West Delta Block 52 Unit by delivering shares of our Common Stock at $3.00 per share equal to up to 5% of the purchase price paid by us. We also permitted our Chief Financial Officer and Treasurer, Kevin Nanke, to purchase up to 2-1/2% of the working interest upon the same terms. Messrs. Larson and Parker each delivered 58,333 shares of Common Stock and Mr. Nanke delivered 29,167 shares of Common Stock, 69 thereby purchasing the maximum permitted to each. These shares have been retired. (q) On February 12, 2001, we permitted our officers, Aleron H. Larson, Jr., Chairman and Secretary, Roger A. Parker, President and CEP, and Kevin K. Nanke, Chief Financial Officer and Treasurer, to purchase interests owned by us in the Cedar State gas property in Eddy County, New Mexico, with its existing gas well, and in our Ponderosa Prospect with its approximately 52,000 gross exploratory leasehold acres in Harding and Butte Counties, South Dakota, based upon our purchase price in each property. We permitted these officers to purchase their interests by exchanging their shares of our Common Stock at the market closing price on February 12, 2001 of $5.125 per share. Messrs. Larson and Parker each exchanged 31,310 shares for a 5% interest in each property and Mr. Nanke exchanged 15,655 shares for a 2-1/2% interest in each property. On the same date we permitted our officers to participate in the drilling of our Austin State #1 well in Eddy County, New Mexico, by immediately making a commitment to participate in the well (prior to any bore hole knowledge or information relating to the objective zone or zones) and pay their share of our working interest costs of drilling and completing or abandoning the well. The costs may be paid in either cash or our Common Stock at the February 12, 2001 closing price of $5.125 per share. Messrs. Larson and Parker each committed to pay the costs associated with a 5% working interest in the well and Mr. Nanke likewise committed to a 2-1/2% working interest in the well. Directors and officers were issued options and warrants as disclosed in "Executive Compensation," above. All past and future and ongoing transactions with affiliates are and will be on terms which our management believes are no less favorable than could be obtained from non-affiliated parties. All future and ongoing loans to our affiliates, officials and shareholders will be approved by the majority vote of disinterested directors. SELLING SECURITY HOLDER We currently only have a total of 11,165,000 shares issued and outstanding, so if all of the shares that may be offered are actually sold, our issued and outstanding shares would increase by about 58%. The shares offered by this prospectus are being offered by Swartz. We have been informed by Swartz that Eric S. Swartz is the beneficial holder of all of the shares owned by it. SWARTZ ------ This prospectus covers 6,500,000 shares of common stock issuable to Swartz under the Investment Agreement and shares issuable upon exercise of the warrants we previously issued to Swartz. Swartz is engaged in the business of investing in publicly-traded equity securities for its own use. Swartz does not beneficially own any of our common stock or any other of our securities as of the date of this prospectus other than 500,000 shares underlying the warrant we issued to Swartz in connection with the closing of the Investment Agreement. Other than its obligations to purchase common stock 70 under the Investment Agreement, it has no other commitments or arrangements to purchase or sell any of our securities. Swartz is an underwriter for the sale of its shares. As an underwriter, Swartz is generally liable to pay damages to purchasers of shares if any part of this registration statement has any untrue statement of a material fact in it or if it does not have in it a material fact that is either required to be disclosed or that would be needed to make any of the statements made in this registration statement not misleading. Swartz has not had any relationship with us, any predecessor or affiliate within the past three years. THE DELTA-SWARTZ INVESTMENT AGREEMENT - OVERVIEW On July 21, 2000, we entered into an Investment Agreement with Swartz. The Investment Agreement was amended and restated on April 4, 2001. As amended and restated, the Investment Agreement entitles us to issue and sell up to $20 million of our common stock to Swartz, subject to a formula based on our stock price and trading volume, from time to time over a three year period following the effective date of this registration statement. We refer to each election by us to sell stock to Swartz as a "Put." As partial consideration for executing the Letter of Agreement, Swartz was issued a warrant to purchase 500,000 shares of common stock exercisable at $3.00 per share until May 31, 2005, which is referred to as the commitment warrant. We have agreed to an anti-dilution provision, which provides, if we complete a "reverse stock split" at a time when our shareholders equity is less than $1 million, Swartz shall be issued additional warrants in an amount so that the sum of its warrants equals at least 6.2% of our fully diluted shares. In addition to any other remedies we may have, any unexercised portion of the commitment warrant will be canceled and returned to us, if both (1) we are not in default of any provision of our agreements with Swartz, and (2) Swartz fails to pay for any Puts after one month of being notified in writing by us that such amount is past due. Swartz has agreed to include a dribble-out provision that prevents Swartz from exercising the warrant in excess of a number of shares equal to fifteen percent (15%) of the aggregate trading volume of our Common Stock, on the primary exchange or market upon which our Common Stock is then listed for trading, during the twenty (20) trading days preceding the date of such exercise. The dribble-out provision does not apply if the average closing price of our Common Stock for the five (5) trading days immediately preceding the date of exercise is greater than or equal to eight dollars ($8.00) per share or if we are acquired by another entity. - PUT RIGHTS We may begin exercising Puts on the date of effectiveness of this prospectus and continue for a three-year period. We currently do not intend to issue any shares to Swartz under the Investment Agreement until we obtain shareholder approval. To exercise a Put, we must have an effective registration statement on file with the Securities and Exchange Commission covering the resale to the public by Swartz of any shares that it acquires under the Investment Agreement. Also, we must give Swartz at least 10, but not 71 more than 20, business days advance notice of the date on which we intend to exercise a particular Put right. The notice must indicate the date we intend to exercise the Put and the maximum number of shares of common stock we intend to sell to Swartz. At our option, we may also specify a maximum dollar amount (not to exceed $2 million) of common stock that we will sell under the Put. We may also specify a minimum purchase price per share at which we will sell shares to Swartz. The minimum purchase price cannot exceed 80% of the closing bid price of our common stock on the date we give Swartz notice of the Put. The number of common shares we sell to Swartz may not exceed 15% of the aggregate daily reported trading volume of our common shares during the 20 business days before and 20 days after the date we exercise a Put. Further, we cannot issue additional shares to Swartz that, when added to the shares Swartz previously acquired under the Investment Agreement during the 31 days before the date we exercise the Put, will result in Swartz holding over 9.99% of our outstanding shares upon completion of the Put. Swartz will pay us a percentage of the market price for each share of common stock under the Put. The market price of the shares of common stock during the 20 business days immediately following the date we exercise a Put is used to determine the purchase price Swartz will pay and the number of shares we will issue in return. This 20 day period is the pricing period. For each share of common stock, Swartz will pay us the lesser of: - the market price for each share, minus $.25; or - 91% of the market price for each share. The Investment Agreement defines market price as the lowest closing bid price for our common stock during the 20 business day pricing period. However, Swartz must pay at least the designated minimum per share price, if any, that we specify in our notice. If the price of our common stock is below the greater of the designated minimum per share price plus $.25, or the designated minimum per share price divided by .91 during any of the 20 days during the pricing period, that day is excluded from the 15% volume limitation described above. Therefore, the amount of cash that we can receive for that Put may be reduced if we elect to a minimum price per share and our stock price declines. We must wait a minimum of five business days after the end of the 20 business day pricing period for a prior Put before exercising a subsequent Put. We may, however, give advance notice of our subsequent Put during the pricing period for the prior Put. We can only exercise one Put during each pricing period. - LIMITATIONS AND CONDITIONS TO OUR PUT RIGHTS Our ability to Put shares of our common stock, and Swartz's obligation to purchase the shares, is subject to the satisfaction of certain conditions. These conditions include: - we have satisfied all obligations under the agreements entered into between us and Swartz in connection with the investment agreement; 72 - our common stock is listed and traded on Nasdaq or an exchange, or quoted on the O.T.C. Bulletin Board; - our representations and warranties in the Investment Agreement are accurate as of the date of each Put; - we have reserved for issuance a sufficient number of shares of our common stock to satisfy our obligations to issue shares under any Put and upon exercise of warrants; - the registration statement for the shares we will be issuing to Swartz must remain effective as of the Put date and no stop order with respect to the registration statement is in effect; - shareholder approval is required by Nasdaq rules in connection with a transaction other than a public offering involving the sale by the issuer of common stock at a price less than the greater of book or market value which, together with sales by officers, directors or substantial shareholders of the issuer, equals 20% or more of common stock outstanding before the issuance. - shareholder approval is required by the Investment Agreement if the number of shares Put to Swartz, together with any shares previously Put to Swartz, would equal 20% of all shares of our common stock that would be outstanding upon completion of the Put. Swartz is not required to acquire and pay for any additional shares of our common stock once it has acquired $20 million worth of Put Shares. Additionally, Swartz is not required to acquire and pay for any shares of common stock with respect to any particular Put for which, between the date we give advance notice of an intended Put and the date the particular Put closes: - we announced or implemented a stock split or combination of our common stock; - we paid a dividend on our common stock; - we made a distribution of all or any portion of our assets or evidences of indebtedness to the holders of our common stock; or - we consummated a major transaction, such as a sale of all or substantially all of our assets or a merger or tender or exchange offer that results in a change in control. We may not require Swartz to purchase any subsequent Put shares if: - we, or any of our directors or executive officers, have engaged in a transaction or conduct related to us that resulted in: - a Securities and Exchange Commission enforcement action, administrative proceeding or civil lawsuit; or 73 - a civil judgment or criminal conviction or for any other offense that, if prosecuted criminally, would constitute a felony under applicable law; - the aggregate number of days which this registration statement is not effective or our common stock is not listed and traded on Nasdaq or an exchange or quoted on the O.T.C. Bulletin Board exceeds 120 days; - we file for bankruptcy or any other proceeding for the relief of debtors; or - we breach covenants contained in the Investment Agreement. - COMMITMENT AND TERMINATION FEES If we do not Put at least $2,000,000 worth of common stock to Swartz during each one year period following the effective date of the Investment Agreement, we must pay Swartz an annual non-usage fee. This fee equals the difference between $200,000 and 10% of the value of the shares of common stock we Put to Swartz during the one year period. The fee is due and payable on the last business day of each one year period. Each annual non-usage fee is payable to Swartz, in cash, within five (5) business days of the date it accrued. We are not required to pay the annual non-usage fee to Swartz in years we have met the Put requirements. We are also not required to deliver the non-usage fee payment until Swartz has paid us for all Puts that are due. If the investment agreement is terminated, we must pay Swartz the greater of (i) the non-usage fee described above, or (ii) the difference between $200,000 and 10% of the value of the shares of common stock Put to Swartz during all Puts to date. We may terminate our right to initiate further Puts or terminate the investment agreement at any time by providing Swartz with written notice of our intention to terminate. However, any termination will not affect any other rights or obligations we have concerning the investment agreement or any related agreement. - SHORT SALES The Investment Agreement prohibits Swartz and its affiliates from engaging in short sales of our common stock unless Swartz has received a Put notice and the amount of shares involved in the short sale does not exceed the number of shares we specify in the Put notice. In addition, in accordance with Section 5(b)(2) of the Securities Act of 1933, Swartz must deliver a prospectus when they enter into a short position. - CANCELLATION OF PUTS We must cancel a particular Put if: - we discover an undisclosed material fact relevant to Swartz's investment decision; - the registration statement registering resales of the common shares becomes ineffective; or 74 - our shares of common stock are delisted from Nasdaq, the O.T.C. Bulletin Board or an exchange. If we cancel a Put, it will continue to be effective, but the pricing period for the Put will terminate on the date we notify Swartz that we are canceling the Put. Because the pricing period will be shortened, the number of shares Swartz will be required to purchase in the canceled Put may be smaller than it would have been had we not canceled the Put. - TERMINATION OF INVESTMENT AGREEMENT We may terminate our right to initiate further Puts or terminate the Investment Agreement at any time by providing Swartz with written notice of our intention to terminate. However, any termination will not affect any other rights or obligations we have concerning the Investment Agreement or any related agreement. - CAPITAL RAISING LIMITATIONS During the term of the Investment Agreement and for a period of ninety (90) days after the termination of the Investment Agreement, we are prohibited from entering into any private equity line agreements similar to the Swartz Investment Agreement without obtaining Swartz's prior written approval. We have agreed to give Swartz a Right of First Offer during this same period, the term of the Investment Agreement plus ninety (90) days. If we commence or plan to commence negotiations with another investor, during this time period, for a private capital raising transaction we will first notify and negotiate in good faith with Swartz regarding the potential financing transaction. If Swartz is more than five (5) business days late in paying for the Put shares, then it is not entitled to the benefits of these restrictions until the date amounts due are paid. Neither of the above restrictions apply to the following items and we may engage in and issue securities in the following transactions without notifying or obtaining approval from Swartz; - in connection with a merger, consolidation, acquisition, or sale of assets; - in connection with a strategic partnership or joint venture, the primary purpose of which is not simply to raise money; - in connection with our disposition or acquisition of a business, product or license; - upon exercise of options by employees, consultants or directors; - in an underwritten public offering of our common stock; - upon conversion or exercise of currently outstanding options, warrants or other convertible securities; - under any option or restricted stock plan for the benefit of employees, directors or consultants; or 75 - upon the issuance of debt securities with no equity feature for working capital purposes. - SWARTZ'S RIGHT OF INDEMNIFICATION We have agreed to indemnify Swartz, including its owners, employees, investors and agents, from all liability and losses resulting from any misrepresentations or breaches we make in connection with the Investment Agreement, the registration rights agreement, other related agreements, or the registration statement. We have also agreed to indemnify these persons for any claims based on violation of Section 5 of the Securities Act caused by the integration of the private sale of our common stock to Swartz and the public offering under the registration statement. - EFFECT ON OUTSTANDING COMMON STOCK The issuance of common stock under the Investment Agreement will not affect the rights or privileges of existing holders of common stock except that the issuance of shares will dilute the economic and voting interests of each shareholder. See "Risk Factors." As noted above, we cannot determine the exact number of shares of our common stock issuable under the Investment Agreement and the resulting dilution to our existing shareholders, which will vary with the extent to which we utilize the Investment Agreement, the market price of our common stock, and exercise of the related warrants. The potential effects of any dilution on our existing shareholders include the significant dilution of the current shareholders' economic and voting interests in us. The Investment Agreement provides that we cannot issue shares of common stock that would exceed 20% of the outstanding stock on the date of a Put unless and until we obtain shareholder approval of the issuance of common stock. The table below includes information regarding ownership of our common stock by Swartz on September 30, 2001 and the number of shares that they may sell under this prospectus. The actual number of shares of our common stock issuable upon exercise of warrants to Swartz and our Put rights is subject to adjustment and could be materially less or more than the amount contained in the table below, depending on factors which we cannot predict at this time, including, among other factors, the future price of our common stock. There are no material relationships with Swartz other than as indicated below. Shares Shares Percent Beneficially Beneficially of Class Owned Prior Owned After Owned to the Shares the After the Offering Offered(1) Offering Offering ------------ ---------- ------------- ---------- Swartz Private Equity(2) 500,000 6,500,000 -0- -0- --------------------- (1) Assumes that Swartz will sell all of the shares of common stock offered by this prospectus. We cannot assure you that the Swartz will sell all or any of these shares. 76 (2) Represents 500,000 shares issuable to Swartz under the Swartz commitment warrant and up to 6,000,000 shares ("Put Shares")of common stock issuable to Swartz under the Investment Agreement; however, we are not obligated to sell any Put Shares to Swartz nor do we intend to sell any Put Shares to Swartz unless it is beneficial to us. The Put Shares would not be deemed beneficially owned within the meaning of Sections 13(d) and 13(g) of the Exchange Act before their acquisition by Swartz. If we were to sell all of the 6,000,000 Put Shares to Swartz and if Swartz exercised all of its warrants and did not resell any of the shares, Swartz would own 36.8% of our outstanding common stock based on the number of shares that we currently have issued and outstanding. It is expected, however, that Swartz will not beneficially own more than 9.9% of our outstanding stock at any one time. PLAN OF DISTRIBUTION Swartz and its successors, which term includes its transferees, pledgees or donees or their successors, may sell the common stock directly to one or more purchasers (including pledgees) or through brokers, dealers or underwriters who may act solely as agents or may acquire common stock as principals, at market prices prevailing at the time of sale, at prices related to such prevailing market prices, at negotiated prices or at fixed prices, which may be changed. Swartz may effect the distribution of the common stock in one or more of the following methods: - ordinary brokers transactions, which may include long or short sales; - transactions involving cross or block trades or otherwise on the open market; - purchases by brokers, dealers or underwriters as principal and resale by such purchasers for their own accounts under this prospectus; - "at the market" to or through market makers or into an existing market for the common stock; - in other ways not involving market makers or established trading markets, including direct sales to purchasers or sales effected through agents; - through transactions in options, swaps or other derivatives (whether exchange listed or otherwise); or - any combination of the above, or by any other legally available means. In addition, Swartz or successors in interest may enter into hedging transactions with broker-dealers who may engage in short sales of common stock in the course of hedging the positions they assume with Swartz. Swartz or successors in interest may also enter into option or other transactions with broker-dealers that require delivery by such broker-dealers of the common stock, which common stock may be resold thereafter under this prospectus. 77 Brokers, dealers, underwriters or agents participating in the distribution of the common stock may receive compensation in the form of discounts, concessions or commissions from Swartz and/or the purchasers of common stock for whom such broker-dealers may act as agent or to whom they may sell as principal, or both (which compensation as to a particular broker-dealer may be in excess of customary commissions). Swartz is, and any broker-dealers acting in connection with the sale of the common stock by this prospectus may be deemed to be, an underwriter within the meaning of Section 2(11) of the Securities Act, and any commissions received by them and any profit realized by them on the resale of common stock as principals may be underwriting compensation under the Securities Act. Neither we nor Swartz can presently estimate the amount of such compensation. We do not know of any existing arrangements between Swartz and any other shareholder, broker, dealer, underwriter or agent relating to the sale or distribution of the common stock. We intend, however, to facilitate in the placing of blocks of shares with one or more large investors in the future whenever possible. Swartz and any other persons participating in a distribution of securities will be subject to the rules, regulations and applicable provisions of the Securities Exchange Act, including, without limitation, Regulation M, which may restrict certain activities of, and limit the timing of purchases and sales of securities by, Swartz and other persons participating in a distribution of securities. Furthermore, under Regulation M, persons engaged in a distribution of securities are prohibited from simultaneously engaging in market making and certain other activities with respect to such securities for a specified period of time prior to the commencement of such distributions subject to specified exceptions or exemptions. Swartz has, before any sales, agreed not to effect any offers or sales of the common stock in any manner other than as specified in this prospectus and not to purchase or induce others to purchase common stock in violation of Regulation M under the Exchange Act. All of the foregoing may affect the marketability of the securities offered by this prospectus. Any securities covered by this prospectus that qualify for sale under Rule 144 under the Securities Act may be sold under that Rule rather than under this prospectus. We cannot assure you that Swartz will sell any or all of the shares of common stock offered by Swartz. In order to comply with the securities laws of certain states, if applicable, Swartz will sell the common stock in jurisdictions only through registered or licensed brokers or dealers. In addition, in certain states, Swartz may not sell the common stock unless the shares of common stock have been registered or qualified for sale in the applicable state or an exemption from the registration or qualification requirement is available and is complied with. 78 DESCRIPTION OF SECURITIES COMMON STOCK We are authorized to issue 300,000,000 shares of our $.01 par value common stock, of which 11,165,000 shares were issued and outstanding as of November 13, 2001. Holders of common stock are entitled to cast one vote for each share held of record on all matters presented to shareholders. Shareholders do not have cumulative rights; hence, the holders of more than 50% of the outstanding common stock can elect all directors. Holders of common stock are entitled to receive such dividends as may be declared by the Board of Directors out of funds legally available therefor and, in the event of liquidation, to share pro rata in any distribution of our assets after payment of all liabilities. We do not anticipate that any dividends on common stock will be declared or paid in the foreseeable future. Holders of common stock do not have any rights of redemption or conversion or preemptive rights to subscribe to additional shares if issued by us. All of the outstanding shares of our common stock are fully paid and nonassessable. WARRANTS Under our Investment Agreement, Swartz is the holder of warrants to purchase our common stock (for a further discussion see "Selling Security Holders"). Swartz currently has 500,000 warrants, (for a further discussion see "Selling Security Holders" and Exhibit 10.1 for "The Investment Agreement"). INTERESTS OF NAMED EXPERTS AND COUNSEL EXPERTS The Consolidated Financial Statements of Delta Petroleum Corporation as of June 30, 2001 and 2000, and for each of the years in the three year period ended June 30, 2001, and the Statements of Oil and Gas Revenue and Direct Lease Operating Expenses of the New Mexico Properties for each of the years in the two year period ended June 30, 1999, the Point Arguello Properties for the year ended June 30, 1999 and the nine month period ended June 30, 1998, and the North Dakota Properties for each of the years in the two year period ended June 30, 2000, included in this Registration Statement have been included herein in reliance upon reports by KPMG LLP, independent certified public accountants, appearing elsewhere herein and upon the authority of such firm as experts in accounting and auditing. LEGAL MATTERS The validity of the issuance of the common stock offered by this prospectus will be passed upon for us by Krys Boyle Freedman & Sawyer, P.C., Denver, Colorado. No person is authorized to give any information or to make any representations other than those contained or incorporated by reference in this prospectus and, if given or made, such information or representations must not be relied upon as having been authorized. This prospectus does not 79 constitute an offer to sell or a solicitation of an offer to buy any securities other than the common stock offered by this prospectus. This prospectus does not constitute an offer to sell or a solicitation of an offer to buy any common stock in any circumstances in which such offer or solicitation is unlawful. Neither the delivery of this prospectus nor any sale made in connection with this prospectus shall, under any circumstances, create any implication that there has been no change in our affairs since the date of this prospectus or that the information contained by reference to this prospectus is correct as of any time subsequent to its date. COMMISSION POSITION ON INDEMNIFICATION FOR SECURITIES ACT LIABILITIES Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers or persons controlling the registrant according to the foregoing provisions, the registrant has been informed that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is therefore unenforceable. 80 FINANCIAL STATEMENTS Financial Statements are included on Pages F-1 through F-53. The Table of Contents to the Financial Statements is as follows: Report of Independent Certified Public Accountants KPMG LLP F-1 Consolidated Balance Sheets as of September 30, 2001, June 30, 2000 and 1999 F-2 to F-3 Consolidated Statements of Operations for the Three Months Ended September 30, 2001 and 2000 and the Years Ended June 30, 2001, 2000 and 1999 F-4 Consolidated Statements of Changes in Stockholders' Equity and Comprehensive Income (Loss) for the Three Months Ended September 30, 2001, and the Years ended June 30, 2001, 2000 and 1999 F-5 to F-6 Consolidated Statements of Cash Flows for the Three Months Ended September 30, 2001 and 2000 and the Years Ended June 30, 2001, 2000 and 1999 F-7 Summary of Accounting Policies and Notes to Consolidated Financial Statements F-8 to F-42 Report of Independent Certified Public Accountants KPMG LLP F-43 Delta Petroleum Corporation's New Mexico Properties Statements of Oil and Gas Revenue and Direct Lease Operating Expenses For the Three Months Ended September 30, 1999 and Each of the Years in the Two- Year Period Ended June 30, 1999 F-44 Notes to New Mexico Properties Statements of Oil and Gas Revenue and Direct Lease Operating Expenses F-45 to F-47 Report of Independent Certified Public Accountants KPMG LLP F-48 Delta Petroleum Corporation's Port Arguello Properties Statements of Oil and Gas Revenue and Direct Lease Operating Expenses For the Three Months Ended September 30, 1999, Year Ended June 30, 1999 and Nine Months Ended June 30, 1998 F-49 Notes to Point Arguello Properties Statements of Oil and Gas Revenue and Direct Lease Operating Expenses F-50 to F-53 81 Report of Independent Certified Public Accountants KPMG LLP F-54 Delta Petroleum Corporation's North Dakota Properties Statements of Oil and Gas Revenue and Direct Lease Operating Expenses For Each of the Years in the Two-Year Period Ended June 30, 2000 F-55 Notes to North Dakota Properties Statements of Oil and Gas Revenue and Direct Lease Operating Expenses F-56 to F-58 Independent Auditors' Report The Board of Directors and Stockholders Delta Petroleum Corporation: We have audited the accompanying consolidated balance sheets of Delta Petroleum Corporation (the Company) and subsidiary as of June 30, 2001 and 2000 and the related consolidated statements of operations, stockholders' equity and comprehensive income (loss), and cash flows for each of the years in the three year period ended June 30, 2001. 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 audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. 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 statements presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Delta Petroleum Corporation and subsidiary as of June 30, 2001 and 2000 and the results of their operations and their cash flows for each of the years in the three-year period ended June 30, 2001, in conformity with accounting principles generally accepted in the United States of America. /s/ KPMG LLP KPMG LLP Denver, Colorado October 5, 2001 F-1 DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS -----------------------------------------------------------------------------

September 30 June 30, June 30, 2001 2001 2000 ------------- --------- ---------- Unaudited ASSETS Current Assets: Cash $ 445,000 $ 518,000 $ 302,000 Trade accounts receivable, net of allowance for doubtful accounts of $50,000 at September 30, 2001, June 2001 and 2000 1,553,000 1,673,000 614,000 Accounts receivable - related parties 249,000 272,000 143,000 Prepaid assets 791,000 594,000 373,000 Other current assets 435,000 538,000 198,000 ----------- ----------- ----------- Total current assets 3,473,000 3,595,000 1,630,000 ----------- ----------- ----------- Property and Equipment: Oil and gas properties, at cost (using the successful efforts method of accounting) 30,120,000 29,955,000 20,414,000 Less accumulated depreciation and depletion (5,721,000) (5,024,000) (2,538,000) ----------- ----------- ----------- Net property and equipment 24,399,000 24,931,000 17,876,000 ----------- ----------- ----------- Long term assets: Deferred financing costs 210,000 241,000 367,000 Investment in Bion Environmental 95,000 221,000 229,000 Partnership net assets 892,000 844,000 675,000 Deposit on purchase of oil and gas properties - - 280,000 ----------- ----------- ----------- Total long term assets 1,197,000 1,306,000 1,551,000 ----------- ----------- ----------- $29,069,000 $29,832,000 $21,057,000 =========== =========== ===========

F-2 DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS, CONTINUED (Unaudited) -----------------------------------------------------------------------------

September 30, June 30, June 30, 2001 2001 2000 ------------- ------------ ------------- Unaudited LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Current portion of long-term debt $ 2,865,000 $ 3,038,000 $ 1,766,000 Accounts payable 2,472,000 2,071,000 1,636,000 Other accrued liabilities 76,000 46,000 154,000 Deferred revenue - - 59,000 ------------ ------------ ------------ Total current liabilities 5,413,000 5,155,000 3,615,000 ------------ ------------ ------------ Long-term debt, net 5,728,000 6,396,000 6,479,000 ------------ ------------ ------------ Stockholders' Equity: Preferred stock, $.10 par value; authorized 3,000,000 shares, none issued - - - Common stock, $.01 par value; authorized 300,000,000 shares, issued 11,165,000 shares at September 30, 2001, 11,160,000 at June 30, 2001 and 8,422,000 at June 30, 2000 112,000 112,000 84,000 Additional paid-in capital 40,717,000 40,700,000 33,747,000 Accumulated other comprehensive gain (loss) (57,000) 69,000 77,000 Accumulated deficit (22,844,000) (22,600,000) (22,945,000) ------------ ------------ ------------ Total stockholders' equity 17,928,000 18,281,000 10,963,000 ------------ ------------ ------------ Commitments $ 29,069,000 $ 29,832,000 $ 21,057,000 ============ ============ ============

See accompanying notes to consolidated financial statements. F-3 DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF OPERATIONS -----------------------------------------------------------------------------

Three Months Ended Year Ended ---------------------------- ------------------------------------- September 30, September 30, June 30, June 30, June 30, 2001 2000 2001 2000 1999 ------------- ------------- ---------- ----------- ------------ (Unaudited) (Unaudited) Revenue: Oil and gas sales $2,416,000 $ 2,359,000 $12,254,000 $ 3,356,000 $ 558,000 Gain on sale of oil and gas properties - - 458,000 75,000 957,000 Operating fee income 27,000 27,000 106,000 76,000 43,000 Other revenue - 15,000 59,000 69,000 137,000 ---------- ----------- ----------- ----------- ----------- Total revenue 2,443,000 2,401,000 12,877,000 3,576,000 1,695,000 Operating expenses: Lease operating expenses 721,000 943,000 4,698,000 2,405,000 210,000 Depreciation and depletion 793,000 465,000 2,533,000 888,000 229,000 Exploration expenses 72,000 13,000 89,000 47,000 75,000 Abandoned and impaired properties - - 798,000 - 273,000 Dry hole costs 125,000 - 94,000 - 226,000 Professional fees 324,000 230,000 1,108,000 519,000 372,000 General and administrative 286,000 292,000 1,470,000 1,258,000 1,133,000 Stock option expense 17,000 211,000 409,000 538,000 2,081,000 ---------- ----------- ----------- ----------- ----------- Total operating expenses 2,338,000 2,154,000 11,199,000 5,655,000 4,599,000 ---------- ----------- ----------- ----------- ----------- Income from operations 105,000 247,000 1,678,000 (2,079,000) (2,904,000) Other income and expenses: Other income 3,000 361,000 528,000 90,000 23,000 Interest and financing costs (352,000) (338,000) (1,861,000) (1,265,000) (20,000) Loss on sale of securities available for sale - - - (113,000) (97,000) ---------- ----------- ----------- ----------- ----------- Total other income and expenses (349,000) 23,000 (1,333,000) (1,288,000) (94,000) ---------- ----------- ----------- ----------- ----------- Net income (loss) $ (244,000) $ 270,000 $ 345,000 $(3,367,000) $(2,998,000) ========== =========== =========== =========== =========== Net income (loss) per common share: Basic $ (0.02) $ 0.03 $ (0.46) $ (0.51) $ (0.18) ========== =========== =========== =========== =========== Diluted $ (0.02)* $ 0.03 $ (0.46)* $ (0.51)* $ (0.18)* ========== =========== =========== =========== =========== * Potentially dilutive securities outstanding were anti-dulutive

See accompanying notes to consolidated financial statements. F-4 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Consolidated Statement of Stockholders' Equity and Comprehensive Income (Loss) Years ended June 30, 2001, 2000, 1999 and Three Months ended September 30, 2001 -----------------------------------------------------------------------------

Accumulated other Additional comprehensive Common Stock paid-in income Comprehensive Accumulated Shares Amount capital (loss) income (loss) deficit Total -------------------------------------------------------------------------------------------------------------------------------- Balance, July 1, 1998 5,514,000 $ 55,000 25,572,000 458,000 (16,580,000) 9,505,000 Comprehensive loss: Net loss - - - (2,998,000) (2,998,000) (2,998,000) ----------- Other comprehensive loss, net of tax Unrealized loss on equity securities - - - (670,000) Less: Reclassification adjustment for losses included in net loss 97,000 (573,000) (573,000) ----------- Comprehensive loss - - - (3,571,000) =========== Stock options granted as compensation - - 2,081,000 - - 2,081,000 Shares issued for cash, net of commissions 196,000 2,000 354,000 - - 356,000 Shares issued for cash upon exercise of options 120,000 1,000 159,000 - - 160,000 Shares issued for services 10,000 - 16,000 - - 16,000 Shares issued for oil and gas properties 250,000 3,000 621,000 - - 624,000 Shares issued for deposit on oil and gas properties 300,000 3,000 613,000 - - 616,000 Fair value of warrant extended and repriced - - 60,000 - - 60,000 ---------- -------- ---------- -------- ------------ ----------- Balance, June 30, 1999 6,390,000 $ 64,000 29,476,000 (115,000) (19,578,000) 9,847,000 Comprehensive loss: Net loss - - - (3,367,000) (3,367,000) (3,367,000) ----------- Other comprehensive income, net of tax Unrealized gain on equity securities - - - 79,000 Less: Reclassification adjustment for losses included in net loss - - - 113,000 192,000 192,000 ----------- Comprehensive loss - - - (3,175,000) ==========-= Stock options granted as compensation - - 500,000 - - 500,000 Shares issued for cash, net of commissions 603,000 6,000 1,018,000 - - 1,024,000 Shares issued for cash upon exercise of options 1,049,000 10,000 1,368,000 - - 1,378,000 Shares issued with financing 75,000 1,000 565,000 - - 566,000 Shares issued for oil and gas properties 215,000 2,000 548,000 - - 550,000 Shares issued for deposit on oil and gas properties 90,000 1,000 272,000 - - 273,000 ----------- -------- ----------- --------- ------------ ----------- Balance, June 30, 2000 8,422,000 $ 84,000 33,747,000 77,000 (22,945,000) 10,963,000 F-5 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Consolidated Statement of Stockholders' Equity and Comprehensive Income (Loss) Years ended June 30, 2001, 2000, 1999 and Three Months Ended September 30, 2001 (Continued) ----------------------------------------------------------------------------- Comprehensive income: Net income - - - 345,000 345,000 345,000 ------------ Other comprehensive gain, net of tax Unrealized loss on equity securities - - - (8,000) (8,000) (8,000) ------------ Comprehensive income - - - 337,000 ===========- Stock options granted as compensation - - 520,000 - - 520,000 Fair value of warrants issued for common stock investment agreement - - 1,436,000 - - 1,436,000 Warrant issued in exchange for common stock investment agreement - - (1,436,000) - - (1,436,000) Shares issued for cash, net of commissions 1,004,000 10,000 2,412,000 - - 2,422,000 Shares issued for cash upon exercise of options 922,000 9,000 1,471,000 - - 1,480,000 Conversion of note payable and accrued interest to common stock 200,000 2,000 509,000 - - 511,000 Shares issued for oil and gas properties 851,000 9,000 2,945,000 - - 2,954,000 Shares reacquired and retired (239,000) (2,000) (904,000) - - (906,000) ----------- --------- ----------- -------- ------------ ----------- Balance, June 30, 2001 11,160,000 $112,000 40,700,000 69,000 (22,600,000) 18,281,000 Comprehensive loss: Net loss - - - (244,000) (244,000) (244,000) ------------ Other comprehensive loss, net of tax Unrealized loss on equity securities - - - (126,000) (126,000) (126,000) ------------ Comprehensive loss - - - (370,000) ====-======= Stock options granted as compensation - - 17,000 - - 17,000 Shares issued for cash upon exercise of options 5,000 - - - - - ----------- -------- ----------- --------- ------------ ----------- Balance, September 30, 2001 11,165,000 $112,000 40,717,000 (57,000) (22,844,000) 17,928,000 ========== ======== =========== ========= ============ ===========

F-6 DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS -----------------------------------------------------------------------------

Three Months Ended Year Ended ---------------------------- ----------------------------------- September 30, September 30, June 30, June 30, June 30 2001 2000 2001 2000 1999 ------------- ------------ ------------ ----------- ---------- (Unaudited) (Unaudited) Cash flows operating activities: Net income (loss) $ (244,000) $ 270,000 $ 345,000 (3,367,000) $(2,998,000) Adjustments to reconcile net income (loss) to cash used in operating activities: Gain on sale of oil and gas properties - - (458,000) (75,000) (957,000) Loss on sale of securities available for sale - - - 113,000 97,000 Depreciation and depletion 793,000 465,000 2,533,000 888,000 229,000 Stock option expense 17,000 186,000 520,000 500,000 2,081,000 Amortization of financing costs 141,000 93,000 506,000 467,000 - Abandoned and impaired properties - - 798,000 - 273,000 Common stock issued for services - - - - 16,000 Dry hole costs 125,000 - - - - Net changes in operating assets and operating liabilities: (Increase) decrease in trade accounts receivable 120,000 (502,000) (1,059,000) (533,000) 84,000 (Increase) in prepaid assets (197,000) (79,000) (221,000) (373,000) - (Increase) decrease in other current assets (7,000) 1,000 66,000) (63,000) - (Increase) decrease in accounts payable trade 401,000) 208,000 222,000 1,243,000 (177,000) (Increase) decrease in other accrued liabilities 30,000 (128,000) (269,000) 144,000 - Deferred Revenue - (15,000) (59,000) (69,000) (137,000) ----------- ----------- ----------- ----------- ----------- Net cash provided by (used in) operating activities $ 1,179,000 $ 499,000 $ 2,924,000 $(1,125,000) $(1,489,000) Cash flows from investing activities: Additions to property and equipment (386,000) (5,704,000) (11,613,000) (7,760,000) (507,000) Deposit on purchase of oil and gas properties - (47,000) - (6,000) (1,000,000) Proceeds from sale of securities available for sale - - - 135,000 175,000 Proceeds from sale of oil and gas properties - - 3,700,000 75,000 1,384,000 Increase in long term assets (48,000) (164,000) (169,000) (675,000) - ----------- ----------- ----------- ----------- ----------- Net cash provided by (used in) investing activities (434,000) (5,915,000) (8,082,000) (8,231,000) 52,000 ----------- ----------- ----------- ----------- ----------- Cash flows from financing activities: Stock issued for cash upon exercise of options - 757,000 1,480,000 1,378,000 160,000 Issuance of common stock for cash - 675,000 2,422,000 1,024,000 356,000 Proceeds from borrowings - 5,209,000 14,394,000 12,817,000 1,400,000 Repayment of borrowings (841,000) (982,000) (12,777,000) (5,640,000) (400,000) Decrease (increase) in accounts receivable from related parties 23,000 10,000 (145,000) (20,000) 4,000 ----------- ----------- ----------- ----------- ----------- Net cash provided by (used in) financing activities (818,000) 5,669,000 5,374,000 9,559,000 1,520,000 ----------- ----------- ----------- ----------- ----------- Net increase in cash (73,000) 253,000 216,000 203,000 83,000 ----------- ----------- ----------- ----------- ----------- Cash at beginning of period 518,000 302,000 302,000 99,000 17,000 ----------- ----------- ----------- ----------- ----------- Cash at end of period $ 445,000 $ 555,000 $ 518,000 $ 302,000 $ 100,000 =========== =========== =========== ========== ============ Supplemental cash flow information - Cash paid for interest and financing costs $ 210,000 $ 281,000 $ 1,677,000 $ 741,000 $ 281,000 =========== =========== =========== ========== ============ Non-cash financing activities: Common stock issued for the purchase of oil and gas properties, net of return of deposited shares $ - $ 2,170,000 $ 2,954,000 $ 550,000 $ 20,000 =========== =========== =========== ========== ============ Common stock issued for note payable and accrued financing $ - $ - $ 511,000 $ - $ - =========== =========== =========== ========== ============ Common stock, options and overriding royalties issued for services relating to debt financing $ - $ 130,000 $ 330,000 $ 891,000 $ - =========== =========== =========== ========== ============ Common stock issued for deposit on purchase of oil and gas properties $ - $ 628,000 $ - $ 273,000 $ 616,000 =========== =========== =========== ========== ============ Shares reacquired and retired for oil and gas properties and option exercise $ - $ - $ 906,000 $ - $ - =========== =========== =========== ========== ============

See accompanying notes to consolidated financial statements. F-7 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (Information as of and for the three months ended September 30, 2001 and 2000 is unaudited.) (1) Summary of Significant Accounting Policies Organization and Principles of Consolidation 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 September 30, 2001, 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 also engaged in acquiring, exploring, developing and producing oil and gas properties. The consolidated financial statements include the accounts of Delta and Amber (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. Liquidity The Company has incurred losses from operations over the past several years coupled with significant deficiencies in cash flow from operations, for the same period prior to fiscal 2001. As of September 30, 2001, the Company had a working capital deficit of $1,560,000. These factors among others may indicate that without increased cash flow from operations, sale of oil and gas properties or additional financing the Company may not be able to meet its obligation in a timely manner or be able to fund exploration and development of its oil and gas properties. During fiscal 2001 and 2000, the Company has raised approximately $3,902,000 and $2,402,000, respectively, through private placements and option exercises. In addition, the Company has sold properties to fund its working capital deficits and/or its funding needs. In addition, Recently, the Company has taken steps to reduce losses and generate cash flow from operations through the acquisition of producing oil and gas properties which management believes will generate sufficient cash flow to meet its obligations in a timely manner. Should the Company be unable to achieve its projected cash flow from operations additional financing or sale of oil and gas properties could be necessary. The Company believes that it could sell oil and gas properties or obtain additional financing, however, there can be no assurance that such financing would be available on timely or acceptable terms. F-8 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001 and 1999 (1) Summary of Significant Accounting Policies, Continued Cash Equivalents Cash equivalents consist of money market funds. For purposes of the statements of cash flows, the Company considers all highly liquid investments with maturities at date of acquisition of three months or less to be cash equivalents. Property and Equipment The Company follows the successful efforts method of accounting for its oil and gas activities. Accordingly, costs associated with the acquisition, drilling, and equipping of successful exploratory wells are capitalized. Geological and geophysical costs, delay and surface rentals and drilling costs of unsuccessful exploratory wells are charged to expense as incurred. Costs of drilling development wells, both successful and unsuccessful, are capitalized. Upon the sale or retirement of oil and gas properties, the cost thereof and the accumulated depreciation and depletion are removed from the accounts and any gain or loss is credited or charged to operations. 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. Capitalized costs of undeveloped properties are assessed periodically on an individual field basis and a provision for impairment is recorded, if necessary, through a charge to operations. Furniture and equipment are depreciated using the straight-line method over estimated lives ranging from three to five years. 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 in its consolidated financial statements. Partnership net assets represents the Company's share of net working capital in such entities. Impairment of Long-Lived Assets Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" (SFAS No. 121) 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. 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. F-9 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (1) Summary of Significant Accounting Policies, Continued 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. 121 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. As a result of such assessment, the Company has a $174,000 impairment provision attributable to certain producing properties for the year ended June 30, 2001 and no impairment provision for other periods presented. 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. The Company recorded an impairment provision attributed to certain undeveloped foreign properties of $624,000 for the year ended June 30, 2001 and had no impairment for the other periods presented. Gas Balancing The Company uses the sales method of accounting for gas balancing of gas production. Under this method, all proceeds from production when delivered to a third party pipeline which are credited to the Company are recorded as revenue until such time as the Company has produced its share of the total estimated reserves of the property. Thereafter, additional amounts received are recorded as a liability. As of September 30, 2001, the Company had produced and recognized as revenue approximately 67,000 Mcf more than its share of production. The undiscounted value of this imbalance is approximately $201,000 using the lower of the price received for the natural gas, the current market price or the contract price, as applicable. F-10 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (1) Summary of Significant Accounting Policies, Continued Deferred Revenue Deferred revenue primarily represents amounts received for gas produced and delivered where the Company was uncertain as to the distribution of amounts attributable to its interest, including amounts from a gas purchaser under the terms of a recoupment agreement on properties that the Company acquired during the Amber acquisition. The Company deferred amounts pending a determination of the Company's revenue interest. The statute of limitation has expired for these deferred amounts and accordingly zero and $15,000 for the three months ended September 30, 2001 and 2000 and $59,000, $69,000 and $137,000 for the years ended June 30, 2001, 2000 and 1999, respectively, have been written off and recorded as a component of other income. 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. The Company adopted the disclosure requirement of SFAS No. 123, Accounting for Stock-Based Compensation and provides pro forma net income (loss) and pro forma earnings (loss) per share disclosures for employee stock option grants made in 1995 and future years as if the fair-value based method defined in SFAS No. 123 had been applied. 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 bases 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. F-11 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (1) 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. The effect of potentially dilutive securities outstanding were antidilutive during the three months ended September 30, 2001, and years ended June 30, 2000 and 1999. 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. Actual results could differ from these estimates. Recently Issued Accounting Standards and Pronouncements In July 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets" and approved for issuance SFAS No. 143, "Accounting for Asset Retirement Allocations." SFAS No. 141 requires that the purchase method of accounting be used for all business combinations initiated or completed after June 30, 2001. SFAS No. 141 also specifies criteria that intangible assets acquired in a purchase method business combination must meet to be recognized and reported apart from goodwill. The adoption of SFAS No. 141 will have no impact on our fiscal 2001 financial statements. SFAS No. 142 requires that goodwill no longer be amortized, but instead tested for impairment at least annually in accordance with the provisions of SFAS No. 142. Any goodwill and any intangible asset determined to have an indefinite useful life that are acquired in a purchase business combination completed after June 30, 2001 will not be amortized, but will be evaluated for impairment in accordance with the appropriate existing accounting literature. The adoption will have no impact on our fiscal 2001 financial statements. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset and is effective for fiscal years beginning after June 15, 2002. The Company is currently assessing the impact SFAS No. 143 will have on its financial condition and results of operations. F-12 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (1) Summary of Significant Accounting Policies, Continued In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment of Disposal of Long-Lived Assets, which is effective for fiscal years beginning after December 15, 2001. SFAS No. 144 establishes one accounting model to be used for long-lived assets to be disposed of by sale and broadens the presentation of discontinued operations to included more disposal transaction. The Company is currently assessing the impact SFAS No. 144 will have on its financial condition and results of operations. Reclassification Certain amounts in the 1999 and 2000 financial statements have been reclassified to conform to the 2001 financial statement presentation. (2) Investment The Company's investment in Bion Environmental Technologies, Inc. ("Bion") is classified as an available for sale security and reported at its fair market value, with unrealized gains and losses excluded from earnings and reported as accumulated comprehensive income (loss), a separate component of stockholders' equity. During fiscal 2000 the Company received an additional 16,808 shares of Bion's common stock for rent and other services provided by the Company. The Company realized a loss of $113,000 and $97,000 for the years ended June 30, 2000 and 1999 on the sales of securities available for sale. The Company had no receipts or sales of securities during fiscal 2001 or the three months ended September 30, 2001. The cost and estimated market value of the Company's investment in Bion at June 30, 2001 and 2000 are as follows: Estimated Unrealized Market Cost Gain/(Loss) Value September 30, 2001 $152,000 $ (57,000) $ 95,000 June 30, 2001 $152,000 $ 69,000 $221,000 June 30, 2000 $152,000 $ 77,000 $229,000 As of November 13, 2001, the estimated market value of the Company's investment in Bion, based on the quoted bid price of Bion's common stock, was approximately $84,000. F-13 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (3) 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 $9,365,000, $9,359,000 and $9,109,000, September 30, 2001, June 30, 2001 and June 30, 2000, respectively. 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 as discussed herein. The Company is not the designated operator of any of these properties but is an active participant in the ongoing activities of each property along with the designated operator and other interest owners. If the designated operator elected not to or was unable to continue as the operator, the other property interest owners would have the right to designate a new operator as well as share in additional property returns prior to the replaced operator being able to receive returns. Based on the Company's size, it would be difficult for the Company to proceed with exploration and development plans should other substantial interest owners elect not to proceed. However, to the best of its knowledge, the Company believes the designated operators and other major property interest owners intend to proceed with exploration and development plans under the terms and conditions of the operating agreement. The ownership rights in each of these properties have been retained under various suspension notices issued by the Mineral Management Service of the U.S. Federal Government (MMS) whereby as long as the owners of each property were progressing toward defined milestone objectives, the owners' rights with respect to the properties continue to be maintained. The issuance of the suspension notices has been necessitated by the numerous delays in the exploration and development process resulting from regulatory requirements imposed on the property owners by federal, state and local agencies. The delays have prevented the property owners from submitting for approval an exploration plan on four of the properties. If and when plans are submitted for approval, they are subject to review for consistency with the California Coastal Zone Management Planning (CZMP) and by the MMS for other technical requirements. In the summer of 2001, several events occurred that continue to impact the ability of the property owners to proceed to prepare exploration and development plans for the properties. F-14 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (3) Oil and Gas Properties, Continued In June, 2001, in the case of The State of California ex. rel. The California Coastal Commission: Gray Davis, Governor of California and Bill Lockyer, Attorney General in the State of California et. al., v. Gale A. Norton, Secretary of the Interior, United States Department of the Interior, Minerals Management Service, Regional Supervisor of the Minerals Management Service, et. al., the United States District Court for the Northern District of California found that the previous grants of lease suspensions by the MMS was an activity that required a determination by the MMS under the Coastal Zone Management Act that the lease suspensions were consistent with California's coastal management program, and ordered the MMS to set aside its approval of the subject suspensions and to direct suspensions of the offshore California leases, including all milestone activities, for a time sufficient for the MMS to provide the State of California with a consistency determination under the Coastal Zone Management Act. By correspondence dated on July 2, 2001, the MMS set aside its approval of the previously existing lease suspensions and directed new suspensions of all of the offshore California leases, including all milestone activities, for a time sufficient for the MMS to provide the State of California with a consistency determination under the Coastal Zone Management Act. The new suspensions of operations directed by the correspondence do not specify an end date. The United States government has filed a notice of its intent to appeal the court's order in the Norton case. Based on discussions with the MMS and operators of the properties, the Company currently believes that the MMS will appeal the decision entered in the Norton case and will await the outcome of its appeal prior to providing the State of California with a consistency determination under the Coastal Zone Management Act (see "Properties"). Furthermore, the Company believes that the MMS will seek to modify the previously submitted suspension of production requests to focus solely on "preliminary activities," and will approve new suspensions of production requests that do not contain any "milestones" per se, as the stated milestones in the previous suspensions of production appear to have been a significant factor in the court's decisions. The Company also believes that the end-date of any such new suspensions of production will likely be the anticipated spud date for the delineation wells set forth in the operators' respective requests for suspensions of production. Even though the Company is not the designated operator of the properties and regulatory approvals have not been obtained, the Company believes exploration and development activities on these properties will occur and is committed to expend funds attributable to its interests in order to proceed with obtaining the approvals for the exploration and development activities. F-15 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (3) Oil and Gas Properties, Continued Based on the preliminary indicated levels of hydrocarbons present from drilling operations conducted in the past, the Company believes the fair value of its property interests are in excess of their carrying value at September 30, 2001, June 30, 2001 and June 30, 2000 and that no impairment in the carrying value has occurred. Should the required regulatory approvals not be obtained or plans for exploration and development of the properties not continue, the carrying value of the properties would likely be impaired and written off. Acquisitions On November 1, 1999, the Company acquired interests in 10 operated wells in New Mexico and 1 non-operated well in Texas ("New Mexico") for a cost of $2,880,000. The acquisition was financed through borrowings from an unrelated entity at an interest rate of 18% per annum. On December 1, 1999, the Company refinanced the remaining principal with Kaiser-Francis Oil Company at a rate of prime plus 1-1/2%. On December 1, 1999, the Company completed the acquisition of the equivalent of a 6.07% working interest in the form of a financial arrangement termed a "net operating interest" in the Point Arguello Unit, and its three platforms (Hidalgo, Harvest and Hermosa) ("Point Arguello"), along with a 100% interest in two and an 11.11% interest in one of the three leases within the adjacent unproved undeveloped Rocky Point Unit from Whiting Petroleum Corporation ("Whiting"), a shareholder. Whiting retained its proportionate share of future abandonment liability associated with both the onshore and offshore facilities of the Point Arguello Unit. The acquisition had a purchase price of approximately $6,759,000 consisting of $5,625,000 in cash and 500,000 shares (which included the 300,000 shares issued during fiscal 1999) of the Company's restricted common stock with a fair market value of $1,134,000. The total acquisition cost of $5,059,000 was allocated between proved developed producing of $1,970,000, proved undeveloped of $1,700,000 and unproved undeveloped of $1,389,000. The Company assigned an unaffiliated third party a 3% overriding royalty interest in the Point Arguello properties as consideration for arranging the transaction. Subsequently, the Company committed to sell 25,000 barrels per month from December 1999 to May 2000 at $8.25 per barrel and from June 2000 to December 2000 at $14.65. If the Company would not have committed to sell its proportionate shares of its barrels at $8.25 and $14.65 per barrel, the Company would have realized an increase in income of $1,242,000 for the year ended June 30, 2001 and $2,033,000 for the year ended June 30, 2000. F-16 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (3) Oil and Gas Properties, Continued On July 10, 2000, the Company paid $3,745,000 and issued 90,000 shares of the Company's common stock valued at approximately $280,000 and on September 28, 2000, $1,845,000 to acquire interests in 20 producing wells, 5 injection wells and acreage located in the Eland and Stadium fields in Stark County, North Dakota ("North Dakota"). The July 10, 2000 and September 28, 2000 payments resulted in the acquisition by the Company of 67% and 33%, respectively, of the ownership interest in each property acquired. The $3,745,000 payment on July 10, 2000 was financed through borrowings from an unrelated entity and personally guaranteed by two of the Company's officers, while the payment on September 28, 2000 was primarily paid out of the Company's net revenues from the effective date of the acquisitions through closing. Delta also issued 100,000 shares of its restricted common stock, valued at $450,000, to an unaffiliated party for its consultation and assistance related to the transaction. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time the commission was earned and is recorded in oil and gas properties. On December 1, 2000, the Company acquired a 50% interest and operations in approximately 52,000 gross acres in South Dakota from an unrelated entity for $467,000. On January 18, 2001, the Company acquired the Cedar State gas property ("Cedar State") in Eddy County, New Mexico from Saga Petroleum Corporation ("Saga") for $2,700,000. The consideration was $2,100,000 and 181,219 of the Company's common stock, valued at $600,000. The shares were valued at $3.31 per share based on ninety percent of a thirty day average closing price prior to close as required by the purchase and sale agreement. As part of the acquisition, the Company terminated a December 1, 2000 agreement with Saga and Saga was required to return 393,006 shares of the Company's common stock at closing valued of $1,848,000, which had been previously issued as a deposit for the acquisition of certain properties. On February 12, 2001, the Company permitted the officers of the Company to purchase in aggregate 12.5% of its prospect in South Dakota and in the Cedar State gas property, by delivering to the Company shares of its common stock valued at $5.125 per share, the closing stock price on February 12, 2001. The officers delivered 82,678 shares of common stock valued at $424,000 for actual costs incurred and the exercise of options. On July 1, 2001, the Company purchased all the producing properties of Amber Resources Company, a 91.68% owned subsidiary of the Company, for $107,000. The purchase price was based on an evaluation performed by an unrelated engineering firm. The effects of this transaction are eliminated in these consolidated financial statements. F-17 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (3) Oil and Gas Properties, Continued The following unaudited pro forma consolidated statements of operations information assumes that the acquisitions of North Dakota, New Mexico and Point Arguello discussed above occurred as of July 1, 1999:

Three Months Ended Year Ended September 30, June 30, ------------------------ ------------------------- 2001 2000 2001 2000 Oil and gas sales $2,416,000 $2,651,000 $12,546,000 $ 8,314,000 ========== ========== =========== =========== Net income (loss) $ (244,000) $ 212,000 $ 616,000 $ (786,000) ========== ========== =========== =========== Net income (loss) per common share: Basic $ (.02) $ .02 $ .06 $ (.11) ========== ========== =========== =========== Diluted $ (.02) $ .02 $ .05 $ (.11) ========== ========== =========== ===========

During the years ended June 30, 2001, 2000 and 1999, the Company has disposed of certain oil and gas properties and related equipment to unaffiliated entities. The Company has received proceeds from the sales of $3,700,000, $75,000 and $1,384,000 and resulted in a net gain on sale of oil and gas properties of $458,000, $75,000 and $957,000 for the years ended June 30, 2001, 2000 and 1999, respectively. (4) Long Term Debt September 30, June 30, 2001 2001 2000 ------------- ------------------------ A $7,035,000 $7,337,000 $7,504,000 B 1,558,000 2,097,000 - C - - 741,000 ---------- ---------- ---------- $8,593,000 $9,434,000 $8,245,000 Current Portion 2,865,000 3,038,000 1,766,000 ---------- ---------- ---------- Long-Term Portion $5,728,000 $6,396,000 $6,479,000 ========== ========== ========== F-18 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (4) Long Term Debt, Continued A. On December 1, 1999, the Company borrowed $8,000,000 at prime plus 1-1/2% from Kaiser-Francis Oil Company ("Lender"). As additional consideration for entering into the loan, the Company issued warrants to purchase 250,000 shares of our common stock for two years at $2.00 per share. The 250,000 warrants were valued at $260,000 and recorded as a deferred cost to be amortized over the life of the loan. The loan agreement provides for a 4-1/2 year loan with additional cost in the form of oil and gas overriding royalty interests of two and one-half percent (2.5%) on September 1, 2000 and an additional 2.5% on June 1, 2001, proportionately reduced, on all of the oil and gas properties acquired by Delta pursuant to the offshore agreement. In addition, the Company will be required to pay fees of $250,000 on June 1, 2002 and June 1, 2003 if the loan has not been retired prior to these dates. The proceeds from this loan were used to pay off existing debt and the balance of the Point Arguello Unit and East Carlsbad field purchases. The Company is required to make minimum monthly payments of principal and interest equal to the greater of $150,000 or 75% of net cash flows from the acquisitions completed on November 1, 1999 and December 1, 1999. The lender was assigned a 2.5% overriding royalty on September 1, 2000 and June 1, 2001, proportionately reduced to the Company's working interest ownership, on the offshore properties purchased as required by the loan agreement and valued at $130,000 and $200,000, respectively which was recorded as deferred financing cost and amortized. On June 28, 2001, the Company entered into an agreement to buy back the lender's 250,000 warrants to purchase the Company's common stock for $875,000 which was added to the existing debt obligation in exchange for additional drilling opportunities on the same properties collateralized by the loan. The loan is collateralized by the Company=s oil and gas properties acquired with the loan proceeds. B. On October 25, 2000, the Company borrowed $3,000,000 at prime plus 3%, secured by the acquired interests in the Eland and Stadium fields in Stark County, North Dakota, from US Bank National Association (US Bank). On February 28, 2001, the Company increased its existing loan with US Bank to $5,300,000. The loan matures on August 31, 2003 and is collateralized by certain oil and gas properties. The Company is required to make monthly payments in the amount of 90% of the net revenue from the oil and gas properties collateralizing the loan. The Company, required by the loan agreement, has a contract to sell 6,000 barrels of oil per month at $27.31 per barrel through February 28, 2002. The Company is currently in compliance with the loan agreement. C. On July 30, 1999, the Company borrowed $2,000,000 at 18% per annum from an unrelated entity which was personally guaranteed by two of the officers of the Company. The Company paid a 2% origination fee to the lender. F-19 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (4) Long Term Debt, Continued As consideration for the guarantee of the Company indebtedness, the Company entered into an agreement with two of its officers, under which a 1% overriding royalty interest in the properties acquired with the proceeds of the loan (proportionately reduced to the Company's interest in each property) was assigned to each of the officers. The estimated fair value of each overriding royalty interest of $125,000 was recorded as a deferred financing cost. Each officer earned approximately $65,000 and $25,000 for their 1% overriding royalty interest during fiscal 2001 and 2000, respectively. During the quarter ended September 30, 2000, the Company paid off the loan and expensed the unamortized costs. On January 22, 2001, the Company borrowed $1,600,000 at 15% per annum from an unrelated entity, which was personally guaranteed by two officers of the Company. The proceeds were used to acquire the property from Saga. The loan was collateralized by the Company's oil and gas properties acquired with the loan proceeds. During the fourth quarter, the balance was paid in full. On September 29, 2000, the Company borrowed $1,464,000 at 15% per annum from an unrelated entity, which was personally guaranteed by two officers of the Company and matured on March 1, 2001. The proceeds were used to acquire the West Delta Block 52 Unit, a producing property in Plaquemines Parish, Louisiana. This note was paid in full during the quarter ended December 31, 2000. On September 29, 2000, the Company borrowed $500,000 at 10% per annum from an unrelated entity and matured on January 3, 2001. On December 18, 2001, the note and accrued interest of $11,000 was converted into 200,000 shares of the Company's restricted common stock. On November 1, 1999, the Company borrowed approximately $2,800,000 at 18% per annum from an unrelated entity maturing on January 31, 2000, which was personally guaranteed by two officers of the Company. The loan proceeds were used to purchase the 11 producing wells and associated acreage in New Mexico and Texas. On December 1, 1999, the Company paid the loan in full from the money borrowed from Kaiser-Francis Oil Company. The Company also paid a 1% origination fee to the lender. As consideration for the guarantee of the Company indebtedness, the Company agreed to assign a 1% overriding royalty interest to each officer in the properties acquired with the proceeds of the loan (proportionately reduced to the interest acquired in each property). The estimated fair value of each overriding royalty interest of $38,000 was recorded as a deferred financing cost. Each officer earned approximately $18,000 and $10,000 for their 1% of each overriding royalty interest during fiscal 2001 and 2000, respectively. F-20 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (5) Stockholders' Equity Preferred Stock The Company has 3,000,000 shares of preferred stock authorized, par value $.10 per share, issuable from time to time in one or more series. As of September 30, 2001, June 30, 2001 and 2000, no preferred stock was issued. Common Stock During the year ended June 30, 1998, the Company issued 22,500 shares of the Company's common stock to a former employee as part of a severance package. This transaction was recorded at its estimated fair market value of the common stock issued of approximately $65,000 and expenses, which was based on the quoted market price of the stock at the time of issuance. The Company also agreed to forgive approximately $20,000 in debt owed to us by the former employee. On July 8, 1998, the Company completed a sale of 2,000 shares of its common stock to an unrelated individual for net proceeds to Delta of $6,000 at a price of $3.24 per share. This transaction was recorded at the estimated fair value of the common stock issued, which was based on the quoted market price of the stock at the time of issuance. On October 12, 1998, the Company issued 250,000 shares of its common stock, at a price of $1.63 per share, and 500,000 options to purchase its common stock at various exercise prices ranging from $3.50 to $5.00 per share to the shareholders of an unrelated entity in exchange for two licenses for exploration with the government of Kazakhstan. The common stock issued was recorded at the estimated fair value, which was based on the quoted market price of the stock at the time of issuance. The options were valued at $217,000 based on the estimated fair value of the options issued and the Company recorded $624,000 as undeveloped oil and gas properties. On December 1, 1998, the Company issued 10,000 shares of its common stock valued at $16,000, at a price of $1.75 per share, to an unrelated entity for public relation services and expensed. The common stock issued was recorded at the estimated fair value, which was based on the quoted market price of the stock at the time of issuance. On January 1, 1999, the Company completed a sale of 194,444 shares, of its common stock to Evergreen Resources, Inc. ("Evergreen"), another oil and gas company, for net proceeds to us of $350,000. F-21 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (5) Stockholders' Equity, Continued During fiscal 1999, the Company issued 300,000 shares of its common stock, at a price of $2.05 per share, to Whiting Petroleum Corporation ("Whiting"), an unrelated entity, along with a $1,000,000 deposit to acquire a portion of Whiting's interest in the Point Arguello Unit, its three platforms (Hidalgo, Harvest, and Hermosa), along with Whiting's interest in the adjacent undeveloped Rocky Point Unit. (See Note 3 to the Financial Statements.) The common stock issued was recorded at the estimated fair value, which was based on the quoted market price of the stock at the time of issuance and recorded in oil and gas properties. On December 8, 1999, the Company completed a sale of 428,000 shares of its common stock, at a price of $1.75 per share, to Bank Leu AG, for $749,000. The Company paid a commission of $75,000 recorded as an adjustment to equity. In addition, the Company granted warrants to purchase 250,000 shares of its common stock at prices ranging from $2.00 to $4.00 per share for six to twelve months from the effective date of a registration covering the underlying warrants to an unrelated entity. The warrants were valued at $95,000 which was a 10% discount to market, based on quoted market price of the stock at the time of issuance. The warrants were accounted for as an adjustment to stockholders' equity. On December 16, 1999, the Company issued 15,000 shares of its restricted common stock, at a price of $2.14 per share and valued at $32,000, to an unrelated company as a commission for their involvement with establishing a credit facility for our Point Arguello Unit purchase recorded as a deferred financing cost and amortized over the life of the loan. The common stock issued was recorded at a 10% discount to market, which was based on quoted market price on the date the commission was earned. On January 4, 2000, the Company completed a sale of 175,000 shares of its common stock, at a price of $2.00 per share, to Evergreen, another oil and gas company, for net proceeds to us of $350,000. See note 8, Transactions with Other Stockholders. On January 5, 2000, the Company issued 60,000 shares of its restricted common stock, at a price of $2.14 per share and valued at $128,000, to an unrelated company as a commission for their involvement with establishing a credit facility for our Point Arguello Unit purchase which was recorded as a deferred financing cost and amortized over the life of the loan. The common stock issued was recorded at a 10% discount to market, which was based on quoted market price on the date the commission was earned. F-22 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (5) Stockholders' Equity, Continued On June 1, 2000, the Company issued 90,000 shares of its common stock, at a price of $3.04 per share and valued at $273,000, to Whiting as a deposit to acquire certain interests in producing properties in Stark County, North Dakota. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance and recorded in oil and gas properties. During fiscal 2000, the Company issued 215,000 shares of its common stock, at a price of $2.56 per share and valued at $550,000, to an unrelated entity as a commission for its involvement with the Point Arguello Unit and New Mexico acquisitions completed in fiscal 2000. The common stock was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance and recorded in oil and gas properties. On July 5, 2000, the Company completed a sale of 258,621 shares of its common stock, at a price of $2.90 per share, to Bank Leu AG for $750,000. The Company paid a commission of $75,000 and options to purchase 100,000 shares of the Company's common stock at $2.50 per share and 100,000 shares at $3.00 per share for one year were issued to an unrelated individual and entity with a value of approximately $307,000. The commission paid was recorded as an adjustment to equity. On July 31, 2000, the Company paid an aggregate of 30,000 shares of its restricted common stock, at a price of $3.38 per share and valued at $116,000, to the shareholders of Saga Petroleum Corporation ("Saga")(Brent J. Morse, Morse Family Security Trust, and J. Charles Farmer) for an option to purchase certain properties owned by Saga and its affiliates. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance and recorded as a deposit on purchase of oil and gas properties. On August 3, 2000, the Company issued 21,875 shares of its restricted common stock, at a price of $3.38 per share and valued at $74,000, to CEC Inc. in exchange for an option to purchase certain properties owned by CEC Inc. and its partners. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time the Company committed to the transaction and recorded in oil and gas properties. F-23 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (5) Stockholders' Equity, Continued On September 7, 2000, the Company issued 103,423 shares of its restricted common stock, at a price of $4.95 per share and valued at $512,000, to shareholders of Saga Petroleum Corporation ("Saga") in exchange for an option to purchase certain properties under a Purchase and Sale Agreement. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance and recorded as a deposit on purchase of oil and gas properties. On September 29, 2000, the Company issued 487,844 shares of its restricted common stock, at a price of $3.38 per share and valued at $1,646,000, to Castle Offshore LLC, a subsidiary of Castle Energy Corporation and BWAB Limited Liability Company ("BWAB"), as partial payment for properties in Louisiana. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time the Company committed to the transaction and is recorded in oil and gas properties. During the quarter ended September 30, 2000 the Company issued 100,000 shares of its restricted common stock at a price of $4.50 per share at a value of $450,000 to BWAB as a commission for his involvement with the North Dakota properties acquisition. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time the Commission was earned and is recorded in oil and gas properties. On October 2, 2000, the Company issued 289,583 shares of its restricted common stock, at a price of $4.61 per share and valued at $1,336,000 to Saga Petroleum Corporation and its affiliates as part of a deposit on the purchase of properties in West Texas and Southeastern New Mexico. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance. On October 11, 2000, the Company issued 138,461 shares of our restricted common stock to Giuseppe Quirici, Globemedia AG and Quadrafin AG for $450,000. The Company paid $45,000 to an unrelated individual and entity for their efforts and consultation related to the transaction. F-24 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (5) Stockholders' Equity, Continued On December 1, 2000, we elected to exercise our option to purchase interests in 680 producing wells and associated acreage in the Permian Basin located in eight counties in west Texas and southeastern New Mexico from Saga Petroleum Corporation and its affiliates. Previously, the Company paid Saga and its affiliates $500,000 in cash and issued 393,006 shares of its restricted common stock as a deposit required by the Purchase and Sale Agreement between the parties. On January 18, 2001, the Company terminated this agreement. (See footnote 3, Oil and Gas Properties.) On January 3, 2001, the Company entered into an agreement with Evergreen Resources, Inc. ("Evergreen"), a less than 10% shareholder, whereby Evergreen acquired 116,667 shares of the Company's restricted common stock for $350,000. The Company also issued an option to acquire an interest in three undeveloped Offshore Santa Barbara, California properties until September 30, 2001. No book value was assigned to the option. Upon exercise, Evergreen would have been required to transfer the 116,667 shares of the Company's common stock back to the Company and would have been responsible for 100% of all future minimum payments underlying the properties in which the interest is acquired. The option has expired. On January 12, 2001, the Company issued 490,000 shares of its restricted common stock to an unrelated entity for $1,102,000. The Company paid a cash commission of $110,000 to an unrelated individual and issued options to purchase 100,000 shares of the Company's common stock at $3.25 per share to an unrelated company for their efforts in connection with the sale. The options were valued at approximately $200,000. Both the commission and the value of the options have been recorded as an adjustment to equity. On July 21, 2000, the Company entered into an investment agreement with Swartz Private Equity, LLC ("Swartz") and issued Swartz a warrant to purchase 500,000 shares of common stock exercisable at $3.00 per share until May 31, 2005. A warrant to purchase 150,000 shares of the Company's common stock at $3.00 per share for five years was also issued to another unrelated company as consideration for its efforts in this transaction and have been recorded as an adjustment to equity. In the aggregate, the Company issued options to Swartz and the other unrelated company valued at $1,436,000 as consideration for the firm underwriting commitment of Swartz and related services to be rendered are recorded in additional paid in capital. The options were valued at market based on the quoted market price at the time of issuance. The investment agreement entitles the Company to issue and sell ("Put") up to $20 million of its common stock to Swartz, subject to a formula based on the Company's stock price and trading volume over a three year period following the effective date of a registration statement covering the resale of the shares to the public. Pursuant to the terms of this investment F-25 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (5) Stockholders' Equity, Continued agreement the Company is not obligated to sell to Swartz all of the common stock and additional warrants referenced in the agreement nor does the Company intend to sell shares and warrants to the entity unless it is beneficial to the Company. Each time the Company sells shares to Swartz, the Company is required to also issue five (5) year warrants to Swartz in an amount corresponding to 15% of the Put amount. Each of these additional warrants will be exercisable at 110% of the market price for the applicable Put. To exercise a Put, the Company must have an effective registration statement on file with the Securities and Exchange Commission covering the resale to the public by Swartz of any shares that it acquires under the investment agreement. Swartz will pay the Company the lesser of the market price for each share minus $0.25, or 91% of the market price for each share of common stock under the Put. The market price of the shares of common stock during the 20 business days immediately following the date the Company exercises a Put is used to determine the purchase price Swartz will pay and the number of shares the Company will issue in return. If the Company does not Put at least $2,000,000 worth of its common stock to Swartz during each one year period following the effective date of the Investment Agreement, it must pay Swartz an annual non-usage fee. This fee equals the difference between $200,000 and 10% of the value of the shares of common stock it Put to Swartz during the one year period. The fee is due and payable on the last business day of each one year period. Each annual non- usage fee is payable to Swartz, in cash, within five (5) business days of the date it accrued. The Company is not required to pay the annual non-usage fee to Swartz in years it has met the Put requirements. The Company is also not required to deliver the non-usage fee payment until Swartz has paid for all Puts that are due. If the investment agreement is terminated, the Company must pay Swartz the greater of (i) the non-usage fee described above, or (ii) the difference between $200,000 and 10% of the value of the shares of common stock Put to Swartz during all Puts to date. The Company may terminate its right to initiate further Puts or terminate the investment agreement at any time by providing Swartz with written notice of its intention to terminate. However, any termination will not affect any other rights or obligations the Company has concerning the investment agreement or any related agreement. The Company cannot determine the exact number of shares of its common stock issuable under the investment agreement and the resulting dilution to its existing shareholders, which will vary with the extent to which the Company utilizes the investment agreement and the market price of its common stock. The investment agreement provides that the Company cannot issue shares of common stock that would exceed 20% of the outstanding stock on the date of a Put unless and until the Company obtains shareholder approval of the issuance of common stock. The Company will seek the required shareholder approval under the investment agreement and under NASDAQ rules. F-26 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (5) Stockholders' Equity, Continued Non-Qualified Stock Options-Directors and Employees Under its 1993 Incentive Plan (the "Incentive Plan") the Company has reserved the greater of 500,000 shares of common stock or 20% of the issued and outstanding shares of common stock of the Company on a fully diluted basis. Incentive awards under the Incentive Plan may include non-qualified or incentive stock options, limited appreciation rights, tandem stock appreciation rights, phantom stock, stock bonuses or cash bonuses. Options issued to date have been non-qualified stock options as defined in the Incentive Plan. A summary of the Plan's stock option activity and related information for the years ended June 30, 2001, 2000 and 1999 are as follows:

2001 2000 1999 Weighted-Average Weighted-Average Weighted-Average Exercise Exercise Exercise Options Price Options Price Options Price Outstanding-beginning of year 1,635,886 $1.36 1,640,163 $1.05 1,162,977 $2.25 Granted 1,882,500 $4.00 387,500 1.60 477,186 $1.43 Exercised (562,171) $(.81) (391,777) (.29) - - --------- --------- --------- ----- Outstanding-end of year 2,956,215 $3.14 1,635,886 $1.36 1,640,163 $1.05 ========= ========= ========= ===== Exercisable at end of year 2,006,215 $2.40 1,510,886 $ .95 1,385,163 $2.32 ========= ========= ========= =====

The Company issued options to employees. Accordingly, the Company recorded stock option expense in the amount of $110,000, $92,000 and $1,985,000, to employees for the year ended June 30, 2001, 2000 and 1999, respectively, for options issued to the directors below market. F-27 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (5) Stockholders' Equity, Continued Exercise prices for options outstanding under the plan as of June 30, 2001 ranged from $0.05 to $9.75 per share. All but 60,000 options are fully vested at June 30, 2001. The weighted-average remaining contractual life of those options is 8.57 years. A summary of the outstanding and exercisable options at June 30, 2001, segregated by exercise price ranges, is as follows: Weighted Average Weighted Remaining Weighted Exercise Average Contractual Average Price Options Exercise Life Exercisable Exercise Range Outstanding Price (in years) Options Price -------- ----------- --------- ----------- ----------- --------- $0.05-$1.12 426,690 $0.05 7.25 426,690 $0.05 $1.13-$3.25 489,525 1.71 8.17 489,525 1.71 $3.26-$9.75 2,040,000 4.14 8.95 1,090,000 3.65 --------- ----- ---- --------- ----- 2,956,215 $3.14 8.57 2,006,215 $2.41 ========= ===== ==== ========= ===== Proforma information regarding net income (loss) and earnings (loss) per share is required by Statement of Financial Accounting Standards 123 which requires that the information be determined as if the Company has accounted for its employee stock options granted under the fair value method of that statement. The fair value for these options was estimated at the date of grant using a Black-Scholes option pricing model with the following Weighted- average assumptions for the years ended June 30, 2001, 2000 and 1999, respectively, risk-free interest rate of 5.1%, 5.5% and 6.0%, dividend yields of 0%, 0% and 0%, volatility factors of the expected market price of the Company's common stock of 64.03%, 56.07% and 44.35% and a weighted-average expected life of the options of 6.15, 6.6 and 6.0 years. The Company applies APB Opinion 25 and related Interpretations in accounting for its plans. Accordingly, no compensation cost is recognized for options granted at a price equal or greater to the fair market value of the common stock. 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 years ended June 30, 2001, 2000 and 1999 would have been as follows: F-28 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (5) Stockholders' Equity, Continued June 30, ----------------------------------------- 2001 2000 1999 ---- ---- ---- Net Income (loss) $ 345,000 $(3,367,000) $(2,998,000) FAS 123 compensation effect (3,235,000) (133,000) 756,000 ----------- ----------- ----------- Net loss after FAS 123 compensation effect $(2,890,000) $(3,500,000) $(2,242,000) =========== =========== =========== Income per common share: $ (.28) $ (.45) $ (.38) =========== =========== =========== Non-Qualified Stock Options Non-Employee A summary of the Plan's stock option and warrant activity and related information for the years ended June 30, 2001, 2000 and 1999 are as follows:

2001 2000 1999 Weighted-Average Weighted-Average Weighted-Average Exercise Exercise Exercise Options Price Options Price Options Price --------- ------ ---------- ------ ---------- ------ Outstanding-beginning of year 1,562,500 $ 3.33 1,194,500 $ 4.09 889,500 $ 5.36 Granted 1,250,000 $ 3.46 1,090,000 $ 2.99 525,000 $ 3.86 Exercised (360,000) $ (2.85) (657,000) $(1.92) (120,000) $(1.32) Re-priced - - 350,000 $ 1.93 250,000 $ 2.35 Returned for re-pricing - - (350,000) $(3.48) (250,000) $(4.97) Purchased from Kaiser-Francis Oil Co (250,000) $ (2.00) - - - - Expired (62,500) $(6.125) (65,000) $(2.00) (100,000) $(8.50) --------- --------- Outstanding-end of year 2,140,000 $ 3.56 1,562,500 $ 3.33 1,194,500 $ 4.09 ========= ========= ====== ========= ====== Exercisable at end of year 1,769,167 $ 3.28 1,112,500 2.67 182,000 $ 2.28 ========= =========

F-29 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (5) Stockholders' Equity, Continued The Company issued options to non-employees. Accordingly, the Company recorded stock option expense in the amount of $299,000, $446,000 and $96,000 to non-employees for the years ended June 30, 2001, 2000 and 1999, respectively. Exercise prices for options outstanding under the plan as of June 30, 2001 ranged from $2.00 to $6.00 per share. All options are fully vested at June 30, 2001. The weighted-average remaining contractual life of those options is 5.15 years. A summary of the outstanding and exercisable options at June 30, 2001, segregated by exercise price ranges, is as follows: Weighted Average Weighted Remaining Weighted Exercise Average Contractual Average Price Options Exercise Life Exercisable Exercise Range Outstanding Price (in years) Options Price -------- ----------- ---------- ----------- ----------- ---------- $2.00-$3.25 1,220,000 $2.83 4.67 1,220,000 $2.54 $3.26-$6.00 920,000 4.52 5.79 549,167 4.93 --------- ----- ---- --------- ----- 2,140,000 $3.56 5.15 1,769,167 $3.28 ========= ===== ==== ========= ===== (6) Employee Benefits The Company sponsors a qualified tax deferred savings plan in the form of a Savings Incentive Match Plan for Employees ("SIMPLE") IRA plan (the "Plan") available to companies with fewer than 100 employees. Under the Plan, the Company's employees may make annual salary reduction contributions of up to 3% of an employee's base salary up to a maximum of $6,000 (adjusted for inflation) on a pre-tax basis. The Company will make matching contributions on behalf of employees who meet certain eligibility requirements. For the years ended June 30, 2001, 2000 and 1999 the Company contributed $18,000, $18,000 and $17,000, respectively under the Plan. (7) Income Taxes At June 30, 2001, 2000 and 1999, the Company's significant deferred tax assets and liabilities are summarized as follows: F-30 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (7) Income Taxes, Continued 2001 2000 1999 ---- ---- ---- Deferred tax assets: Net operating loss Carryforwards $ 9,378,000 $ 9,591,000 $ 8,163,000 Allowance for doubtful accounts not deductible for tax purposes 19,000 19,000 19,000 Oil and gas properties, principally due to differences in basis and depreciation and depletion - 555,000 1,058,000 ------------ ------------ ----------- Gross deferred tax assets 9,397,000 10,165,000 (9,240,000) Less valuation allowance (8,144,000) (10,165,000) (9,240,000) Deferred tax liability: Oil and gas properties, principally due to differences in basis and depreciation and depletion (1,253,000) - - ------------ ------------ ----------- Net deferred tax asset: $ - $ - $ - ============ ============ =========== No income tax benefit has been recorded for the years ended June 30, 2001, 2000 or 1999 since the benefit of the net operating loss carryforward and other net deferred tax assets arising in those periods has been offset by the change in the valuation allowance for such net deferred tax assets. At June 30, 2001, the Company had net operating loss carryforwards for regular and alternative minimum tax purposes of approximately $24,700,000 and $23,900,000. If not utilized, the tax net operating loss carryforwards will expire during the period from 2001 through 2021. If not utilized, approximately $1.7 million of net operating losses will expire over the next five years. Net operating loss carryforwards attributable to Amber prior to 1993 of approximately $1,884,000, included in the above amounts are available only to offset future taxable income of Amber and are further limited to approximately $475,000 per year, determined on a cumulative basis. F-31 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (8) Related Party Transactions Transactions with Officers On January 3, 2000, the Company's Compensation Committee authorized the officers of the Company to purchase some of the Company's securities available for sale at the market closing price on that date. The Company's officers purchased 47,250 shares of the Company's securities available for sale for a cost of $238,000. Because the market price per share was below the Company's cost basis the Company recorded a loss on this transaction of $108,000. On December 30, 1999, the Company's Incentive Plan Committee granted the Chief Financial Officer 25,000 options to purchase the Company's common stock at $.01 per share. Stock option expense of $62,000 has been recorded based on the difference between the option price and the quoted market price on the date of grant. The Company's Board of Directors has granted each of our officers the right to participate in the drilling on the same terms as the Company in up to a five percent (5%) working interest in any well drilled, re-entered, completed or recompleted by us on our acreage (provided that any well to be re-entered or recompleted is not then producing economic quantities of hydrocarbons). On February 12, 2001, the Company's Board of Directors permitted Aleron H. Larson, Jr., Chairman, Roger A. Parker, President, and Kevin Nanke, CFO, to purchase working interests of 5% each for Messrs. Larson and Parker and 2-1/2% for Mr. Nanke in the Company's Cedar State gas property located in Eddy County, New Mexico and in the Company's Ponderosa Prospect consisting of approximately 52,000 gross acres in Harding and Butte Counties, South Dakota held for exploration. These officers were authorized to purchase these interests on or before March 1, 2001 at a purchase price equivalent to the amounts paid by Delta for each property as reflected upon our books by delivering to us shares of Delta common stock at the February 12, 2001 closing price of $5.125 per share, the market closing price on this date. Messrs. Larson and Parker each delivered 31,310 shares and Mr. Nanke delivered 15,655 shares in exchange for their interests in these properties. Also on February 12, 2001, the Company granted Messrs. Larson and Parker and Mr. Nanke the right to participate in the drilling of the Austin State #1 well in Eddy County, New Mexico by committing on February 12, 2001 (prior to any bore hole knowledge or information relating to the objective zone or zones) to pay 5% each for Messrs. Larson and Parker and 2-1/2% for Mr. Nanke of Delta's working interest costs of drilling and completion or abandonment costs which costs may be paid in either cash or in Delta common stock at $5.125 per share, the market closing price on this date. All of these officers committed to participate in the well and will be assigned their respective working interests in the well and associated spacing unit after they have been billed and have paid for the interests as required. F-32 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (8) Related Party Transactions, Continued Accounts Receivable Related Parties At September 30, 2001, the Company had $249,000 of receivables from related parties (including affiliated companies) primarily for drilling costs, and lease operating expense on wells owned by the related parties and operated by the Company. The amounts are due on open account and are non-interest bearing. Transactions with Directors Under the Company's 1993 and 2001 Incentive Plans, as amended, the Company grants on an annual basis, to each non-employee director, at the non- employee director's election, either: 1) an option for 10,000 shares of common stock; or 2) 5,000 shares of the Company's common stock. The options are granted at an exercise price equal to 50% of the average market price for the year in which the services are performed. The Company recognized stock option expense of $17,000 and $13,000 for the three months ended September 30, 2001 and 2000 and $110,000, $30,000 and $24,000 for the years ended June 30, 2001, 2000 and 1999, respectively. Transactions with Other Stockholders On December 17, 1998, the Company amended its January 3, 1995 Purchase and Sale Agreement with Ogle under which it had previously acquired an additional undeveloped 1.53% working interest in the Gato Canyon unit, an additional 2.83% working interest in the Point Sal unit and an additional 12.62% working interest in the Lion Rock unit of the offshore Santa Barbara, California, federal oil and gas units, from Ogle on January 3, 1995. As a result of this amended agreement, at the time of each minimum annual payment the Company will be assigned an interest in three undeveloped offshore Santa Barbara, California, federal oil and gas units proportionate to the total $8,000,000 production payment. Accordingly, the annual $350,000 minimum payment has been recorded as an addition to undeveloped offshore California properties. In addition, under this agreement, the Company extended and re- priced a previously issued warrant to purchase 100,000 shares of the Company's common stock. The $60,000 fair value placed on the extension and re-pricing of this warrant was recorded as an addition to undeveloped offshore California properties. Prior to fiscal 1999, the minimum royalty payment was expensed in accordance with the purchase and sale agreement with Ogle dated January 3, 1995 and recorded as a minimum royalty payment and expensed. As of June 30, 2001, the Company has paid a total of $2,250,000 in minimum royalty payments and is to pay a minimum of $350,000 annually until the earlier of: 1) when the production payments accumulate to the $8,000,000 purchase price; 2) when 80% of the ultimate reserves of any lease have been produced; or 3) 30 years from the date of the purchase. On December 30, 1999, the Company entered into an F-33 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (8) Related Party Transactions, Continued agreement with Ogle amending the Purchase and Sale Agreement between them dated January 3, 1995 to provide for and clarify the sharing of any compensation which the Company might receive in any form as consideration for any agreement, settlement, regulatory action or other arrangement with or by any governmental unit or other party precluding the further development of the properties acquired by the Company. On January 3, 2001, the Company granted an option to acquire 50% of the above mentioned undeveloped proved property to Evergreen Resources, Inc. ("Evergreen"), a less than 10% shareholder, until September 30, 2001. Upon exercise, Evergreen would have been required to transfer 116,667 shares of Delta's common stock back to the Company and would have been responsible for all future cash payments of the Company to Ogle of $6,100,000. The value on our books of the interest that was subject to the option is $550,000. Evergreen has had this option for three consecutive years. The option expired September 30, 2001. On January 18, 2001, Franklin Energy LLC, an affiliate of BWAB Limited Liability Company, a less than 10% shareholder, earned 20,250 shares of the Company's common stock for their assistance in the purchase of the Cedar State property. The shares issued were valued at $81,000 which was a 10% discount to market, based on the quoted market price of our stock at the date of the acquisition. The shares were accounted for as an adjustment to the purchase price and capitalized to oil and gas properties. On April 13, 2001, Franklin Energy LLC, an affiliate of BWAB Limited Liability Company, a less than 10% shareholder, earned 10,000 shares of the Company's common stock for its assistance in the sale of the West Delta property. The shares issued were valued at $40,000, which was a 10% discount to market, based on the quoted market price of our stock at the date the contract was entered into. The value of the stock was recorded as an adjustment to the sale price. The Company has a month to month consulting agreement with Messrs. Burdette A. Ogle and Ronald Heck (collectively "Ogle") which provides for a monthly fee of $10,000. F-34 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (9) Earnings Per Share The following table sets forth the computation of basic and diluted earnings per share:

Three Months Ended September 30, Year Ended June 30, --------------------------- ------------------------------------------ 2001 2000 2001 2000 1999 Numerator: Numerator for basic and diluted earnings per share - income available to common stockholders $ (244,000) $ 270,000 $ 345,000 $(3,367,000) $(2,998,000) ------------ ------------ ------------ ----------- ----------- Denominator: Denominator for basic earnings per share-weighted average shares outstanding 11,164,000 8,973,000 10,289,000 7,271,000 5,855,000 Effect of dilutive securities- stock options and warrants * 1,496,000 1,464,000 * * ------------ ------------ ------------ ----------- ----------- Denominator for diluted earnings per common shares 11,164,000 10,469,000 11,753,000 7,271,000 5,855,000 ============ ============ ============ =========== =========== Basic earnings per common share $ (.02) .03 .03 (.46) (.51) ============ ============ ============ =========== =========== Diluted earnings per common share (.02)* .03 .03 (.46) (.51) ============ ============ ============ =========== =========== *Potentially dilutive securities outstanding were anti-dilutive.

(10) Commitments The Company rents an office in Denver under an operating lease which expires in April 2002. Rent expense, net of sublease rental income, for the for the years ended June 30, 2001, 2000 and 1999 was approximately $82,000, $60,000 and $53,000, respectively. Future minimum payments under non- cancelable operating leases are as follows: 2002 $116,000 2003 $ 40,000 2004 $ 31,000 2005 $ 6,000 As a condition of the October 25, 2000 loan (note 5), the Company entered into a contract with Enron North America Corp. to sell 6,000 barrels per month of the production from these properties at an equivalent well head price of approximately $27.31 per barrel through February 28, 2002. F-35 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (11) Disclosures About Capitalized Costs, Cost Incurred and Major Customers Capitalized costs related to oil and gas producing activities are as follows: September 30, June 30, 2001 2001 2000 ------------- ----------- ---------- Unproved undeveloped offshore California properties* $ 9,365,000 $ 9,359,000 $9,109,000 Proved undeveloped offshore California properties 996,000 1,149,000 1,700,000 Undeveloped onshore domestic properties 1,616,000 1,616,000 452,000 Undeveloped foreign properties - - 624,000 Developed Offshore California properties 4,972,000 4,699,000 3,286,000 Developed onshore domestic properties 13,075,000 13,038,000 5,154,000 ----------- ----------- ---------- 30,024,000 29,861,000 20,325,000 Accumulated depreciation and depletion (5,636,000) (4,940,000) (2,457,000) ----------- ----------- ---------- $24,388,000 $24,921,000 $17,868,000 =========== =========== =========== * The unproved undeveloped offshore California properties have no proved reserves. F-36 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (11) Disclosures About Capitalized Costs, Cost Incurred and Major Customers, Continued Costs incurred in oil and gas producing activities are as follows:

September 30, June 30, ------------------------------------------ ------------------------------------------------------------------- 2001 2000 2001 2000 1999 Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore -------- -------- ---------- ---------- ---------- ---------- --------- ---------- ---------- -------- Unproved property acquisition costs $ - $ 7,000 $ - $ - $1,132,000 $ 350,000 $ - $2,739,000 $1,034,000 $ - Proved property acquisition costs $ - $ - $4,543,000 $3,253,000 $7,480,000 $2,931,000 $2,756,000 $4,308,000 $ 17,000 $ - Development cost incurred on undeveloped reserves $ 56,000 $ 39,000 $ - $ - $ - $ 686,000 $ 39,000 $ 328,000 $ 62,000 $ - Development costs- other $204,000 $ 80,000 $ 14,000 $ 64,000 $ 592,000 $ 375,000 $ 73,000 $ 351,000 78,000 $ - Exploration costs $ 7,000 $ 65,000 $ 1,000 $ 12,000 $ 32,000 $ 57,000 $ 33,000 $ 14,000 $ 75,000 $ - $267,000 $191,000 $4,558,000 $3,329,000 $9,436,000 $4,399,000 $2,901,000 $6,740,000 $1,266,000 $ - Transferred amounts from undeveloped to developed properties $ 15,000 $153,000 $ - $ 340,000 $ - $ 510,000 $ - $ 55,000 $ 50,000 $ - Transferred from oil and gas properties to deferred financing costs $ - $ - $ - $ 130,000 $ - $ 330,000 $ - $ - $ - $ -

F-37 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (11) Disclosures About Capitalized Costs, Cost Incurred and Major Customers, Continued A summary of the results of operations for oil and gas producing activities, excluding general and administrative cost, is as follows:

September 30, June 30, ------------------------------------------ ----------------------------------------------------------------- 2001 2000 2001 2000 1999 Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- -------- Revenue: Oil and gas revenues $1,212,000 $1,204,000 $1,224,000 $1,135,000 $6,564,000 $5,690,000 $1,199,000 $2,157,000 $ 558,000 $ - Operating Income $ 27,000 $ - $ 27,000 $ - $ 106,000 $ - $ 76,000 $ 209,000 $ 43,000 $ - Gain (loss) on sale of oil and gas properties $ - $ - $ - $ - $ (1,000) $ 459,999 $ - $ - $ - $ - Expenses: Lease operating $ 200,000 $ 521,000 $ 170,000 $ 773,000 $ 805,000 $3,893,000 $ 345,000 $2,060,000 $ 210,000 $ - Depletion $ 564,000 $ 229,000 $ 296,000 $ 168,000 $1,691,000 $ 839,000 $ 325,000 $ 561,000 $ 229,000 $ - Exploration $ 7,000 $ 65,000 $ 1,000 $ 12,000 $ 32,000 $ 57,000 $ 33,000 $ 14,000 $ 75,000 $ - Abandonment and impaired properties $ - $ - $ - $ - $ 798,000 $ - $ - $ - $ 273,000 $ - Dry hole costs $ 125,000 $ - $ - $ - $ 94,000 $ - $ - $ - $ 226,000 $ - Results of operations of oil and gas producing activities $ 343,000 $ 389,000 $ 784,000 $ 182,000 $3,249,000 $ 572,000 $ - $ (478,000) $(412,000) $ -

Statement of Financial Accounting Standards 131 "Disclosures about segments of an enterprises and Related Information" (SFAS 131) establishes standards for reporting information about operating segments in annual and interim financial statements. SFAS 131 also establishes standards for related disclosures about products and services, geographic areas and major customers. The Company manages its business through one operating segment. The Company's sales of oil and gas to individual customers which exceeded 10% of the Company's total oil and gas sales for the years ended June 30, 2001, 2000 and 1999 were: 2001 2000 1999 ---- ---- ---- A 59% 71% -% B 19% - -% C 5% 13% -% D -% -% 38% E -% -% 17% F-38 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (12) Information Regarding Proved Oil and Gas Reserves (Unaudited) Proved Oil and Gas Reserves. Proved oil and gas reserves are the 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, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producability is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. (iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in underlaid prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. F-39 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (12) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. A summary of changes in estimated quantities of proved reserves for the years ended June 30, 2001, 2000 and 1999 are as follows:

Onshore Offshore GAS OIL GAS OIL (MCF) (BBLS) (MCF) (BBLS) --------- -------- ------- --------- Balance at July 1, 1998 9,433,000 147,000 - - Revisions of quantity estimates (3,751,000) 5,000 - - Sales of properties (1,601,000) (4,000) - - Production (254,000) (5,000) - - Balance at July 1, 1999 3,827,000 143,000 - - Revisions of quantity estimates 449,000 10,000 - - Purchase of properties 3,166,000 107,000 - 1,771,000 Production (362,000) (10,000) - (187,000) ---------- -------- ----- --------- Balance at June 30, 2000 7,080,000 250,000 - 1,584,000 Revisions of quantity estimate (3,743,000) ( 25,000) - ( 90,000) Extensions and discoveries 102,000 3,000 - - Purchase of properties 1,782,000 233,000 - 747,000 Sales of properties - - - (720,000) Production (539,000) (117,000) - (308,000) ---------- -------- ----- --------- Balance at June 30, 2001 4,682,000 344,000 - 1,213,000 ========== ======== ====== ========= Proved developed reserves: June 30, 1999 2,289,000 13,000 - - June 30, 2000 5,672,000 120,000 - 908,000 June 30, 2001 4,474,000 342,000 - 906,000

F-40 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (12) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued Future net cash flows presented below are computed using year-end prices and costs and are net of all overriding royalty revenue interests. Future corporate overhead expenses and interest expense have not been included.

Onshore Offshore Combined ------------ ---------- ---------- June 30, 1999 Future cash inflows $ 10,147,000 - 10,147,000 Future costs: Production 3,354,000 - 3,353,000 Development 1,287,000 - 1,287,000 Income taxes - - - ------------ ---------- ---------- Future net cash flows 5,506,000 - 5,506,000 10% discount factor 2,154,000 - 2,154,000 ------------ ---------- ---------- Standardized measure of discounted future net cash flows $ 3,352,000 - $ 3,352,000 ============ ========== ========== June 30, 2000 Future cash inflows $ 30,760,000 36,820,000 67,580,000 Future costs: Production 7,713,000 12,027,000 19,740,000 Development 1,584,000 3,309,000 4,893,000 Income taxes - - - ------------ ---------- ---------- Future net cash flows 21,463,000 21,485,000 42,948,000 10% discount factor 10,427,000 5,394,000 15,821,000 ------------ ---------- ---------- Standardized measure of discounted future net cash flows $ 11,036,000 $16,091,000 $27,127,000 ============ =========== =========== June 30, 2001 Future cash inflows 24,570,000 22,098,000 46,668,000 Future costs: Production 7,971,000 11,969,000 19,940,000 Development 382,000 2,010,000 2,392,000 Income taxes - - - ------------ ---------- ---------- Future net cash flows 16,217,000 8,119,000 24,336,000 10% discount factor 6,267,000 2,095,000 8,362,000 ------------ ---------- ---------- Standardized measure of discounted $ 9,950,000 $ 6,024,000 $15,974,000 future net cash flows =========== =========== =========== Estimated future development cost anticipated for fiscal 2001 and 2002 $ 359,000 $ 1,206,000 $ 1,565,000 =========== =========== ==========

F-41 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements September 30, 2001, June 30, 2001, 2000 and 1999 (12) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued The principal sources of changes in the standardized measure of discounted net cash flows during the years ended June 30, 2001, 2000 and 1999 are as follows:

2001 2000 1999 ----------- ----------- ----------- Beginning of year $27,127,000 $ 3,352,000 $ 6,563,000 Sales of oil and gas produced during the period, net of production costs (7,556,000) (950,000) (348,000) Purchase of reserves in place 9,082,000 21,678,000 - Net change in prices and production costs (2,634,000) 2,080,000 (377,000) Changes in estimated future development costs (371,000) 218,000 891,000 Extensions, discoveries and improved recovery 242,000 - - Revisions of previous quantity estimates, estimated timing of development and other (9,739,000) 336,000 (2,636,000) Previously estimated development costs incurred during the period 686,000 78,000 78,000 Sales of reserves in place (3,576,000) - (1,475,000) Accretion of discount 2,713,000 335,000 656,000 ----------- ----------- ----------- End of year $15,974,000 $27,127,000 $ 3,352,000 =========== =========== ===========

F-42 INDEPENDENT AUDITORS' REPORT THE BOARD OF DIRECTORS WHITING PETROLEUM CORPORATION We have audited the accompanying statement of oil and gas revenue and direct lease operating expenses of oil and gas properties as described in Note 1 ("the New Mexico Properties") of Whiting Petroleum Corporation ("Whiting") acquired by Delta Petroleum Corporation for each of the years in the two-year period ended June 30, 1999. This financial statement is the responsibility of Whiting's management. Our responsibility is to express an opinion on this financial statement based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of oil and gas revenue and direct lease operating expenses is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of oil and gas revenue and direct lease operating expenses. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The accompanying statement of oil and gas revenue and direct lease operating expenses was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. Full historical financial statements, including general and administrative expenses and other indirect expenses, have not been presented as management of the New Mexico Properties cannot make a practicable determination of the portion of their general and administrative expenses or other indirect expenses which are attributable to the New Mexico Properties. In our opinion, the statement of oil and gas revenue and direct lease operating expenses referred to above presents fairly, in all material respects, the oil and gas revenue and direct lease operating expenses of the New Mexico Properties for each of the years in the two-year period ended June 30, 1999, in conformity with generally accepted accounting principles. /s/ KPMG LLP KPMG LLP Denver, Colorado December 29, 1999 F-43 NEW MEXICO PROPERTIES STATEMENT OF OIL AND GAS REVENUE AND DIRECT LEASE OPERATING EXPENSES Three months Ended September 30, Years Ended June 30, 1999 1999 1998 ---- ---- ---- (Unaudited) Operating Revenue: Sales of condensate $ 47,689 124,083 165,555 Sales of natural gas 207,243 648,583 675,536 -------- ------- ------- Total Operating Revenue 254,932 772,621 841,091 Direct Lease Operating Expenses 66,339 250,373 221,593 -------- ------- ------- Net Operating Revenue $188,593 522,248 619,498 ======== ======= ======= See accompanying notes to financial statements. F-44 NOTES TO NEW MEXICO PROPERTIES STATEMENT OF OIL AND GAS REVENUE AND DIRECT LEASE OPERATING EXPENSES FOR EACH OF THE YEARS IN THE TWO-YEAR PERIOD ENDED JUNE 30, 1999 1) PURCHASE OF OIL AND GAS PROPERTIES AND BASIS OF PRESENTATIONS The accompanying financial statement presents the revenues and direct lease operating expenses of certain oil and gas properties of Whiting Petroleum Corporation (the "New Mexico Properties") for each of the years in the two-year period ended June 30, 1999. On November 1, 1999, the Company purchased interests in 10 operated wells in Eddy County, New Mexico with an average working interest of 75% and 1 non-operated well in Matagorda County, Texas with a working interest of 39.5% for a purchase price of $2,879,850 financed through borrowings from an unrelated entity at an interest rate of 18% per annum. These properties are subject to an agreement whereby Delta Petroleum Corporation's purchase is effective July 1, 1999. The accompanying statement of oil and gas revenue and direct lease operating expenses of the New Mexico Properties was prepared to comply with certain rules and regulations of the Securities and Exchange Commission. Full historical financial statements including general and administrative expenses and other indirect expenses, have not been presented as management of the New Mexico Properties cannot make a practicable determination of the portion of their general and administrative expenses or other indirect expenses which are attributable to the New Mexico Properties. Oil and gas activities follow the successful efforts method of accounting. Accordingly, costs associated with the acquisition, drilling, and equipping of successful exploratory wells are capitalized. Geological and geophysical costs, delay and surface rentals and drilling costs of unsuccessful exploratory wells are charged to expense as incurred. Costs of drilling development wells, both successful and unsuccessful, are capitalized. Revenue in the accompanying statement of oil and gas revenue and direct lease operating expenses is recognized on the sales method. Under this method, all proceeds from production when delivered which are credited to the Company are recorded as revenue until such time as the Company has produced its share of the total estimated reserves of the property. Thereafter, additional amounts received are recorded as a liability. Direct lease operating expenses are recognized on the accrual basis and consist of all costs incurred in producing, marketing and distributing products produced by the property as well as production taxes and monthly administrative overhead costs. 2) SUPPLEMENTAL FINANCIAL DATA -OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The following unaudited information has been prepared in accordance with Statement of Financial Accounting Standards No. 69, DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (SFAS 69). F-45 A) ESTIMATED PROVED OIL AND GAS RESERVES Proved oil and gas reserves are the 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; i.e., prices and costs as of the date the estimate is made. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. An estimate of proved developed future net recoverable oil and gas reserves of the Whiting Properties and changes therein follows. Such estimates are inherently imprecise and may be subject to substantial revisions. Proved undeveloped reserves attributable to the New Mexico Properties are not significant. Oil and Natural Condensate Gas (Bbls) (Mcf) ---------- --------- Balance at July 1, 1997 107,847 3,752,496 Production (10,129) (286,248) Effect of changes in prices and other 1,190 71,163 ------- --------- Balance at June 30, 1998 98,908 3,537,411 Production (9,698) (305,944) Effect of changes in prices and other 4,046 145,563 ------- --------- Balance at June 30, 1999 93,256 3,377,030 ======= ========= B) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS The standard measure of discounted future net cash flows has been calculated in accordance with the provisions of SFAS No. 69. Future oil and gas sales and production costs have been estimated using prices and costs in effect at the end of the years indicated. Future income tax expenses have not been considered, as the properties are not a tax paying entity. Future general and administrative and interest expenses have also not been considered. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of the proved reserves. The standardized measure of discounted future net cash flows as of June 30, 1999 and 1998 is as follows: F-46 1999 1998 ---- ---- Future oil and gas sales $9,911,271 8,635,254 Future production costs (4,176,027) (3,999,310) Future development costs -- -- ---------- ---------- Future net revenue 5,735,244 4,635,944 10% annual discount for estimated timing of cash flows (2,622,202) (2,047,660) ---------- ---------- Standardized measure of discounted Future net cash flows $3,113,042 2,588,284 ========== ========== No income taxes have been reflected due to available net operating loss carry forwards of Delta Petroleum Corporation. C) CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES An analysis of the changes in the total standardized measure of discounted future net cash flows during each of the last two years is as follows: 1999 1998 ---- ---- Beginning of year $2,588,284 2,526,799 Changes resulting from: Sales of oil and gas, net of Production costs (522,248) (619,498) Changes in prices and other 788,178 428,303 Accretion of discount 258,828 252,680 ---------- --------- End of year $3,113,042 2,588,284 ========== ========= F-47 INDEPENDENT AUDITORS' REPORT The Board of Directors Whiting Petroleum Corporation We have audited the accompanying statement of oil and gas revenue and direct lease operating expenses of oil and gas properties as described in Note 1 ("the Point Arguello Properties") of Whiting Petroleum Corporation ("Whiting") acquired by Delta Petroleum Corporation for the year ended June 30, 1999 and the nine month period ended June 30, 1998. This financial statement is the responsibility of Whiting's management. Our responsibility is to express an opinion on this financial statement based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of oil and gas revenue and direct lease operating expenses is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of oil and gas revenue and direct lease operating expenses. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The accompanying statement of oil and gas revenue and direct lease operating expenses was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. Full historical financial statements, including general and administrative expenses and other indirect expenses, have not been presented as management of the Point Arguello Properties cannot make a practicable determination of the portion of their general and administrative expenses or other indirect expenses which are attributable to the Point Arguello Properties. In our opinion, the statement of oil and gas revenue and direct lease operating expenses referred to above presents fairly, in all material respects, the oil and gas revenue and direct lease operating expenses of the Point Arguello Properties for the year ended June 30, 1999 and the nine month period ended June 30, 1998, in conformity with generally accepted accounting principles. /s/ KPMG LLP KPMG LLP Denver, Colorado February 7, 2000 F-48 POINT ARGUELLO PROPERTIES STATEMENT OF OIL AND GAS REVENUE AND DIRECT LEASE OPERATING EXPENSES Three Nine Months Year Months Ended Ended Ended September 30, June 30, June 30, 1999 1999 1998 ---- ---- ---- (unaudited) Operating Revenue Sales of condensate $903,646 3,084,165 3,174,108 Direct Lease Operating Expenses 800,776 3,341,406 4,681,593 -------- --------- ---------- Net Operating Revenue (loss) $102,870 (257,241) (1,507,485) ======== ========= ========== See accompanying notes to financial statements. F-49 NOTES TO POINT ARGUELLO PROPERTIES STATEMENT OF OIL AND GAS REVENUE AND DIRECT LEASE OPERATING EXPENSES FOR THE YEAR ENDED JUNE 30, 1999 AND THE NINE MONTHS ENDED JUNE 30, 1998 1) PURCHASE OF OIL AND GAS PROPERTIES AND BASIS OF PRESENTATIONS The accompanying financial statement presents the revenues and direct lease operating expenses of certain oil and gas properties of Whiting Petroleum Corporation (the "Point Arguello Properties") for the year ended June 30, 1999 and the nine months ended June 30, 1998. On December 1, 1999, the Company purchased a 6.07% working interest in the offshore California Point Arguello Unit, with its three producing platforms and related facilities, and a 75% leasehold interest in the adjacent undeveloped Rocky Point Unit for a purchase price of $6,758,500, consisting of $5,625,000 in cash and 500,000 shares of the Company's restricted common stock with a fair market value of $1,133,550. The acquisition was financed through a borrowing from an unrelated entity at an interest rate of prime plus 1.5% per annum and the issuance of 250,000 options to purchase the Company's common stock at $2.00 per share. The accompanying statement of oil and gas revenue and direct lease operating expenses of the Point Arguello Properties was prepared to comply with certain rules and regulations of the Securities and Exchange Commission. Full historical financial statements including general and administrative expenses, depreciation and amortization and other indirect expenses, have not been presented as management of the Point Arguello Properties cannot make a practicable determination of the portion of their general and administrative expenses or other indirect expenses which are attributable to the Point Arguello Properties. Accordingly these financial statements are not indicative of the operating results, subsequent to the acquisition. Oil and gas activities follow the successful efforts method of accounting. Accordingly, costs associated with the acquisition, drilling, and equipping of successful exploratory wells are capitalized. Geological and geophysical costs, delay and surface rentals and drilling costs of unsuccessful exploratory wells are charged to expense as incurred. Costs of drilling development wells, both successful and unsuccessful, are capitalized. Revenue in the accompanying statement of oil and gas revenue and direct lease operating expenses is recognized on the sales method. Under this method, all proceeds from production when delivered which are credited to the Company are recorded as revenue until such time as the Company has produced its share of the total estimated reserves of the property. Thereafter, additional amounts received are recorded as a liability. Direct operating expenses are recognized on the accrual basis and consist of all costs incurred in producing, in the property and distributing products produced by the property as well as production taxes and monthly administrative overhead costs. 2) SUPPLEMENTAL FINANCIAL DATA-OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The following unaudited information has been prepared in accordance with Statement of Financial Accounting Standards No. 69, DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (SFAS 69). F-50 A) ESTIMATED PROVED OIL AND GAS RESERVES Proved oil and gas reserves are the 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, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. (iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in underlaid prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. An estimate of proved future net recoverable oil and gas reserves of the Point Arguello Properties and changes therein follows. Such estimates are inherently imprecise and may be subject to substantial revisions. F-51 Oil and Condensate (Bbls) ------ Balance at October 1, 1997 - Production (396,134) Reserves equal to production 396,134 --------- Balance at June 30, 1998 - Production (412,002) Reserves due to change in price 2,135,945 --------- Balance at June 30, 1999 1,723,943 ========= Proved developed: October 1, 1997 - June 30, 1998 - June 30, 1999 796,821 B) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS The standard measure of discounted future net cash flows has been calculated in accordance with the provisions of SFAS No. 69. Future oil and gas sales and production costs have been estimated using prices and costs in effect at the end of the years indicated. Future income tax expenses have not been considered, as the properties are not a tax paying entity. Future general and administrative and interest expenses have also not been considered. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of the proved reserves. The standardized measure of discounted future net cash flows as of June 30, 1999 is as follows: 1999 ---- Future oil and gas sales $19,842,595 Future production costs (13,330,199) Future development costs - ----------- Future net revenue 6,512,396 10% annual discount for estimated timing of cash flows (1,479,049) ----------- Standardized measure of discounted future net cash flows $ 5,033,347 ----------- As of June 30, 1998 the standardized measure of discounted future net cash flows was zero due to the oil and gas prices prevailing at July 1, 1998. F-52 C) CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES An analysis of the changes in the total standardized measure of discounted future net cash flows during each of the last year is as follows: 1999 ---- Beginning of year $ - Changes resulting from: Sales of oil and gas, net of production costs 257,241 Changes in prices and other 4,776,106 ---------- End of year $5,033,347 ========== As of June 30, 1998 the standardized measure of discounted future net cash flows was zero due to the oil and gas prices prevailing at July 1, 1998. The standardized measure of discounted future net cash flows utilize the providing oil prices at the measurement dates of $11.51, $5.85 and $8.74 for the June 30, 1999, 1998 and 1997, respectively. F-53 INDEPENDENT AUDITORS' REPORT THE BOARD OF DIRECTORS WHITING PETROLEUM CORPORATION We have audited the accompanying statements of oil and gas revenue and direct lease operating expenses of oil and gas properties as described in Note 1 ("the North Dakota Properties") of Whiting Petroleum Corporation ("Whiting") acquired by Delta Petroleum Corporation for each of the years in the two-year period ended June 30, 2000. These financial statement are the responsibility of Whiting's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of oil and gas revenue and direct lease operating expenses is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of oil and gas revenue and direct lease operating expenses. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The accompanying statements of oil and gas revenue and direct lease operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. Full historical financial statements, including general and administrative expenses and other indirect expenses, have not been presented as management of the North Dakota Properties cannot make a practicable determination of the portion of their general and administrative expenses or other indirect expenses which are attributable to the North Dakota Properties. In our opinion, the statements of oil and gas revenue and direct lease operating expenses referred to above present fairly, in all material respects, the oil and gas revenue and direct lease operating expenses of the North Dakota Properties for each of the years in the two-year period ended June 30, 2000, in conformity with generally accepted accounting principles. /s/ KPMG LLP KPMG LLP Denver, Colorado November 28, 2000 F-54 NORTH DAKOTA PROPERTIES STATEMENTS OF OIL AND GAS REVENUE AND DIRECT LEASE OPERATING EXPENSES Years Ended June 30, 2000 1999 ---- ---- Operating Revenue: Sales of condensate $2,915,500 1,527,930 Sales of natural gas 218,065 118,801 ---------- ---------- Total Operating Revenue 3,133,565 1,646,731 Direct Lease Operating Expenses 233,475 136,996 ---------- ---------- Excess Revenue Over Direct Operating Expenses $2,900,090 $1,509,735 ========== ========== See accompanying notes to financial statements. F-55 NOTES TO NORTH DAKOTA PROPERTIES STATEMENTS OF OIL AND GAS REVENUE AND DIRECT LEASE OPERATING EXPENSES FOR EACH OF THE YEARS IN THE TWO-YEAR PERIOD ENDED JUNE 30, 2000 (1) PURCHASE OF OIL AND GAS PROPERTIES AND BASIS OF PRESENTATIONS The accompanying financial statements present the revenues and direct lease operating expenses of certain oil and gas properties of Whiting Petroleum Corporation (the "North Dakota Properties") for each of the years in the two-year period ended June 30, 2000. The properties consist of 100% of the working interests in oil and gas properties located in North Dakota that are subject to an agreement for acquisition by Delta Petroleum Corporation ("Delta") effective February 1, 2000, which were acquired on July 10, 2000 (67%) and September 28, 2000 (33%), respectively. These properties include 20 producing and 5 injection wells. The largest value is located in the Eland field where our working interest averages 3.25%. On July 10, 2000 the Company paid $3,745,000 and issued 90,000 shares of the Company's common stock valued at approximately $280,000 and on September 28, 2000, the Company paid $1,845,000, to acquire interests in producing wells and acreage located in the Eland and Stadium fields in Stark County, North Dakota. The July 10, 2000 and September 28, 2000 transactions resulted in the acquisition by the Company of 67% and 33%, respectively, of the ownership interest in each property acquired. The $3,745,000 payment on July 10, 2000 was financed through borrowings from an unrelated entity and personally guaranteed by two of the Company's officers. The payment on September 28, 2000 was primarily paid out of the Company's share of excess revenues over direct lease operating expenses from the effective date of the acquisitions of February 1, 2000 through closing. Delta also issued 100,000 shares of its restricted common stock to an unaffiliated party for its consultation and assistance related to the transaction. The fair value of the shares at the date of issuance is $450,000 and is included as a component of the cost of the properties. The accompanying statements of oil and gas revenue and direct lease operating expenses of the North Dakota Properties were prepared to comply with certain rules and regulations of the Securities and Exchange Commission and include 100% of the property interests acquired in the two transactions. Full historical financial statements including general and administrative expenses and other indirect expenses, have not been presented as management of the North Dakota Properties cannot make a practicable determination of the portion of their general and administrative expenses or other indirect expenses which are attributable to the North Dakota Properties. Accordingly, their financial statements are not indicative of the operating results, subsequent to the acquisition. Oil and gas activities follow the successful efforts method of accounting. Accordingly, costs associated with the acquisition, drilling, and equipping of successful exploratory wells are capitalized. Geological and geophysical costs, delay and surface rentals and drilling costs of unsuccessful exploratory wells are charged to expense as incurred. Costs of drilling development wells, both successful and unsuccessful, are capitalized. F-56 Revenue in the accompanying statement of oil and gas revenue and direct lease operating expenses is recognized on the sales method. Under this method, all proceeds from production when delivered which are credited to the Company are recorded as revenue until such time as the Company has produced its share of the total estimated reserves of the property. Thereafter, additional amounts received are recorded as a liability. Direct lease operating expenses are recognized on the accrual basis and consist of all costs incurred in producing, marketing and distributing products produced by the properties as well as production taxes and monthly administrative overhead costs charged by the operator. (2) SUPPLEMENTAL FINANCIAL DATA-OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) The following unaudited information has been prepared in accordance with Statement of Financial Accounting Standards No. 69, DISCLOSURE ABOUT OIL AND GAS PRODUCING ACTIVITIES (SFAS 69). A) ESTIMATED PROVED OIL AND GAS RESERVES Proved oil and gas reserves are the 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; i.e., prices and costs as of the date the estimate is made. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based on future conditions. An estimate of proved developed future net recoverable oil and gas reserves of the North Dakota Properties and changes therein follows. Such estimates are inherently imprecise and may be subject to substantial revisions. Proved undeveloped reserves attributable to the North Dakota Properties are not significant. Oil and Condensate Natural Gas (Bbls) (Mcf) ------ ----- Balance at July 1, 1998 533,497 250,778 Production (121,885) (60,622) -------- ------- Balance at June 30, 1999 411,612 190,156 Production (120,066) (59,312) -------- ------- Balance at June 30, 2000 291,546 130,844 ======== ======= F-57 B) STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS The standard measure of discounted future net cash flows has been calculated in accordance with the provisions of SFAS No. 69. Future oil and gas sales and production costs have been estimated using prices and costs in effect at the end of the years indicated. Future income tax expenses have not been considered, due to available net operating loss carry forwards of the Company. Future general and administrative and interest expenses have also not been considered. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of the proved reserves. The standardized measure of discounted future net cash flows as of June 30, 2000 and 1999 is as follows: 2000 1999 ---- ---- Future oil and gas sales $9,366,613 $6,042,856 Future production and development costs (826,349) (1,057,438) ---------- ---------- Future net revenue 8,540,264 4,985,418 10% annual discount for estimated timing of cash flows (1,518,845) (597,353) ---------- ---------- Standardized measure of discounted Future net cash flows $7,021,419 $4,388,065 ========== ========== C) CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES An analysis of the changes in the total standardized measure of discounted future net cash flows during each of the last two years is as follows: 2000 1999 ---- ---- Beginning of year $4,388,065 3,485,232 Changes resulting from: Sales of oil and gas, net of production costs (2,900,090) (1,509,735) Changes in prices and other 5,094,637 2,064,045 Accretion of discount 438,807 348,523 ---------- ---------- End of year $7,021,419 $4,388,065 ========== ========== F-58 PART II INFORMATION NOT REQUIRED IN PROSPECTUS OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION The expenses of the Offering are estimated as follows: Attorneys Fees $ 25,000.00 Accountants Fees $ 5,000.00 Registration Fees $ 7,434.38 Printing $ 500.00 Other Expenses $ 2,065.62 ----------- TOTAL $ 40,000.00 =========== INDEMNIFICATION OF DIRECTORS AND OFFICERS The Colorado Business Corporation Act (the "Act") provides that a Colorado corporation may indemnify a person made a party to a proceeding because the person is or was a director against liability incurred in the proceeding if (a) the person conducted himself or herself in good faith, and (b) the person reasonably believed: (i) in the case of conduct in an official capacity with the corporation, that his or her conduct was in the corporation's best interests; and (ii) in all other cases, that his or her conduct was at least not opposed to the corporation's best interests; and (iii) in the case of any criminal proceeding, the person had no reasonable cause to believe his or her conduct was unlawful. The termination of a proceeding by judgment, order, settlement, conviction, or upon a plea of nolo contendere or its equivalent is not, of itself, determinative that the director did not meet the standard of conduct described in the Act. The Act also provides that a Colorado corporation is not permitted to indemnify a director (a) in connection with a proceeding by or in the right of the corporation in which the director was adjudged liable to the corporation; or (b) in connection with any other proceeding charging that the director derived an improper personal benefit, whether or not involving action in an official capacity, in which proceeding the director was adjudged liable on the basis that he or she derived an improper personal benefit. Indemnification permitted under the Act in connection with a proceeding by or in the right of the corporation is limited to reasonable expenses incurred in connection with the proceeding. Article X of our Articles of Incorporation provides as follows: "ARTICLE X" INDEMNIFICATION The corporation may: (A) Indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending, or completed action, suit, or proceeding, whether civil, criminal, administrative, or investigative (other II-1 than an action by or in the right of the corporation), by reason of the fact that he is or was a director, officer, employee, or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee, or agent of another corporation, partnership, joint venture, trust, or other enterprise, against expenses (including attorneys' fees), judgments, fines, and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit, or proceeding, if he acted in good faith and in a manner he reasonably believed to be in the best interest of the corporation and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. The termination of any action, suit, or proceeding by judgment, order, settlement, or conviction or upon a plea of nolo contendere or its equivalent shall not of itself create a presumption that the person did not act in good faith and in a manner which he reasonably believed to be in the best interest of the corporation and, with respect to any criminal action or proceeding, had reasonable cause to believe his conduct was unlawful. (B) The corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending, or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that he is or was a director, officer, employee, or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee, or agent of another corporation, partnership, joint venture, trust or other enterprise against expenses (including attorneys' fees) actually and reasonably incurred by him in connection with the defense or settlement of such action or suit if he acted in good faith and in a manner he reasonably believed to be in the best interest of the corporation; but no indemnification shall be made in respect of any claim, issue, or matter as to which such person has been adjudged to be liable for negligence or misconduct in the performance of his duty to the corporation unless and only to the extent that the court in which such action or suit was brought determines upon application that, despite the adjudication of liability, but in view of all circumstances of the case, such person is fairly and reasonably entitled to indemnification for such expenses which such court deems proper. (C) To the extent that a director, officer, employee, or agent of a corporation has been successful on the merits in defense of any action, suit, or proceeding referred to in (A) or (B) of this Article X or in defense of any claim, issue, or matter therein, he shall be indemnified against expenses (including attorneys' fees) actually and reasonably incurred by him in connection therewith. (D) Any indemnification under (A) or (B) of this Article X (unless ordered by a court) and as distinguished from (C) of this Article shall be made by the corporation only as authorized in the specific case upon a determination that indemnification of the director, officer, employee, or agent is proper in the circumstances because he has met the applicable standard of conduct set forth in (A) or (B) above. Such determination shall be made by the board of directors by a majority vote of a quorum consisting of directors who were not parties to such action, suit, or proceeding, or, if such a quorum is not obtainable or, even if obtainable, if a quorum of disinterested directors so directs, by independent legal counsel in a written opinion, or by the shareholders. II-2 (E) Expenses (including attorneys' fees) incurred in defending a civil or criminal action, suit, or proceeding may be paid by the corporation in advance of the final disposition of such action, suit, or proceeding as authorized in (C) or (D) of this Article X upon receipt of an undertaking by or on behalf of the director, officer, employee, or agent to repay such amount unless it is ultimately determined that he is entitled to be indemnified by the corporation as authorized in this Article X. (F) The indemnification provided by this Article X shall not be deemed exclusive of any other rights to which those indemnified may be entitled under any applicable law, bylaw, agreement, vote of shareholders or disinterested directors, or otherwise, and any procedure provided for by any of the foregoing, both as to action in his official capacity and as to action in another capacity while holding such office, and shall continue as to a person who has ceased to be a director, officer, employee, or agent and shall inure to the benefit of heirs, executors, and administrators of such a person. (G) The corporation may purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the corporation or who is or was serving at the request of the corporation as a director, officer, employee, or agent of another corporation, partnership, joint venture, trust, or other enterprise against any liability asserted against him and incurred by him in any such capacity or arising out of his status as such, whether or not the corporation would have the power to indemnify him against such liability under provisions of this Article X." RECENT SALES OF UNREGISTERED SECURITIES. Unregistered securities sold within the last three fiscal years in the following private transactions were exempt from registration under the Securities Act of 1933 under Section 4(2). In all instances we had a prior relationship with the purchaser, either through business operations or personal contacts with our officers and directors. We reasonably believe that all of the purchasers of these shares were "Accredited Investors" as such term is defined in Rule 501 of Regulation D promulgated under the Securities Act of 1933 at the time the transaction occurred. On July 8, 1998, we completed a sale of 2,000 shares of our common stock to Ralf Knueppel for net proceeds to Delta of $6,000 at a price of $3.24 per share. This transaction was recorded at the estimated fair value of the common stock issued, which was based on the quoted market price of the stock at the time of issuance. On October 12, 1998, we issued 250,000 shares of our common stock at a price of $1.63 per share and also issued options to purchase up to 500,000 shares of our common stock to the shareholders of an unrelated closely held entity in exchange for two licenses for exploration with the government of Kazakhstan. The options that were issued in connection with this transaction are exercisable at various prices ranging from $3.50 to $5.00 per share. The common stock issued was recorded at the estimated fair value, which was based II-3 on the quoted market price of the stock at the time of issuance. The options were valued at $217,000 based on the estimated fair value of the options issued and recorded at $624,000 as undeveloped oil and gas properties. On December 1, 1998, we issued 10,000 shares of our common stock valued at $16,000, at a price of $1.75 per share, to an unrelated entity for public relation services and expensed. The common stock issued was recorded at the estimated fair value, which was based on the quoted market price of the stock at the time of issuance. On January 1, 1999, we completed a sale of 194,444 shares, of our common stock to Evergreen, another oil and gas company, for net proceeds to us of $350,000. During fiscal 1999, we issued 300,000 shares of our common stock, at a price of $2.05 per share, to Whiting Petroleum Corporation ("Whiting"), an unrelated entity, along with a $1,000,000 deposit to acquire a portion of Whiting's interest in the Point Arguello Unit, its three platforms (Hidalgo, Harvest, and Hermosa), along with Whiting's interest in the adjacent undeveloped Rocky Point Unit. (See Item 2. Descriptions of Properties.) The common stock issued was recorded at the estimated fair value, which was based on the quoted market price of the stock at the time of issuance and recorded in oil and gas properties. On December 8, 1999, we completed a sale of 428,000 shares of our common stock, at a price of $1.75 per share, to Bank Leu AG, for $749,000. We paid a commission of $75,000 recorded as an adjustment to equity. On December 16, 1998, we issued 15,000 shares of our restricted common stock, at a price of $2.14 per share and valued at $32,000, to an unrelated company as a commission for their involvement with establishing a credit facility for our Point Arguello Unit purchase recorded as a deferred financing cost and amortized over the life of the loan. The common stock issued was recorded at a 10% discount to market, which was based on quoted market price on the date the commission was earned. On January 4, 2000, we completed a sale of 175,000 shares of our common stock, at a price of $2.00 per share, to Evergreen, another oil and gas company, for net proceeds to us of $350,000. On January 5, 2000, we issued 60,000 shares of our restricted common stock, at a price of $2.14 per share and valued at $128,000, to an unrelated company as a commission for their involvement with establishing a credit facility for our Point Arguello Unit purchase recorded as a deferred financing cost and amortized over the life of the loan. The common stock issued was recorded at a 10% discount to market, which was based on quoted market price on the date the commission was earned. On June 1, 2000, we issued 90,000 shares of our common stock, at a price of $3.04 per share and valued at $273,000, to Whiting as a deposit to acquire certain interest in producing properties in Stark County, North Dakota. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance and recorded in oil and gas properties. II-4 During fiscal 2000, we issued 215,000 shares of our common stock, at a price of $2.56 per share and valued at $550,000, to an unrelated entity as a commission for their involvement with the Point Arguello Unit and New Mexico acquisitions completed in fiscal 2000. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance and recorded in oil and gas properties. On July 3, 2000, we completed a sale of 258,621 shares of our common stock, at a price of $2.90 per share, to Bank Leu AG for $750,000. We paid a commission of $75,000 recorded as an adjustment to equity. On July 31, 2000, we paid an aggregate of 30,000 shares of our restricted common stock, at a price of $3.38 per share and valued at $116,000, to the shareholders of Saga Petroleum Corporation ("Saga")(Brent J. Morse, Morse Family Security Trust, and J. Charles Farmer) for an option to purchase certain properties owned by Saga and its affiliates. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance and recorded as a deposit on purchase of oil and gas properties. On August 3, 2000, we issued 21,875 shares of our restricted common stock, at a price of $3,38 per share and valued at $74,000, to CEC Inc. in exchange for an option to purchase certain properties owned by CEC Inc. and its partners. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time we committed to the transaction and recorded in oil and gas properties. On September 7, 2000, we issued 103,423 shares of our restricted common stock, at a price of $4.95 per share and valued at $512,000, to shareholders of Saga Petroleum Corporation in exchange for an option to purchase certain properties under a Purchase and Sale Agreement (see Form 8-K dated September 7, 2000). The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance and recorded as a deposit on purchase of oil and gas properties. On September 29, 2000, we issued 487,844 shares of our restricted common stock, at a price of $3.38 per share and valued at $1,646,000, to Castle Offshore LLC, a subsidiary of Castle Energy Corporation and BWAB Limited Liability Company, as partial payment for properties in Louisiana. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time we committed to the transaction and recorded in oil and gas properties. During the six months ended December 31, 2000 we issued 100,000 shares of our restricted common stock at a price of $4.50 per share at a value of $450,000 to an unrelated individual as a commission for their involvement with the North Dakota properties acquisition. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time the Commission was earned. On September 30, 2000, we issued 289,583 shares of our restricted common stock, at a price of $4.61 per share and valued at $1,336,000, to Saga Petroleum Corporation ("SAGA") and its affiliates as part of a deposit on the II-5 purchase of properties in West Texas and Southeastern New Mexico. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time of issuance. On October 11, 2000, we issued 138,461 shares of our restricted common stock to Giuseppe Quirici, Globe Media AG and Quadrafin AG for $450,000. We paid a cash commission of $45,000. On December 18, 2000, we entered into an agreement with SAGA which replaces and supersedes the September 6, 2000 agreement. Under this agreement, we will acquire a producing property for $2,100,000 paid in cash and 181,269 shares of common stock, valued at $600,000. The shares were valued at $3.31 per share based on the quoted market price of the stock at the date the acquisition was announced. In accordance with the agreement, SAGA has returned 393,006 shares of our restricted common stock that were issued as a deposit. On January 3, 2001, we entered into an agreement with Evergreen Resources, Inc., also a shareholder, whereby they acquired 116,667 shares of our common stock and an option to acquire an interest in three undeveloped Offshore Santa Barbara, California properties until September 30, 2001. Upon exercise, they must transfer the 116,667 shares of our common stock back to us and would be responsible for 100% of all future minimum payments underlying the properties in which the interest is acquired. On January 12, 2001, we issued 490,000 shares of our restricted common stock to an unrelated entity for $1,102,000. We paid a cash commission of $110,000 to an unrelated individual and issued options to purchase 100,000 shares of our common stock at $3.25 per share to an unrelated company for their efforts in connection with the sale. INDEX TO EXHIBITS. Exhibit No. Description -------- ----------- 3.1 Articles of Incorporation of Delta Petroleum Corporation (incorporated by reference to Exhibit 3.1 to the Company's Form 10 filed September 9, 1987 with the Securities and Exchange Commission. (1) 3.2 By-laws of Delta Petroleum Corporation (incorporated by reference to Exhibit 3.2 to the Company's Form 10 filed September 9, 1987 with the Securities and Exchange Commission. (1) 5.1 Opinion of Krys Boyle Freedman & Sawyer, P.C. regarding legality. (2) 10.1 Amended and Restated Investment Agreement between the registrant and Swartz Private Equity, LLC. (2) 10.2 Amended and Restated Registration Rights Agreement. (2) II-6 10.3 Amended and Restated Agreement (warrant side agreement). (2) 10.4 Warrant Interpretation Agreement. (2) 10.5 Agreement effective October 28, 1992 between Delta Petroleum Corporation, Burdette A. Ogle and Ron Heck. Incorporated by reference from Exhibit 28.2 to the Company's Form 8-K dated December 4, 1992. (1) 10.6 Option Amendment Agreement effective March 30, 1993. Incorporated by reference from Exhibit 28.2 to the Company's Form 8-K dated April 14, 1993. (1) 10.8 Agreement between Delta Petroleum Corporation and Burdette A. Ogle dated February 24, 1994 for offshore Santa Barbara California Federal oil and gas units. Incorporated by reference from Exhibit 28.1 to the Company's Form 8-K dated February 25, 1994. (1) 10.9 Addendum to agreement dated February 24, 1994 between Delta Petroleum Corporation and Burdette A. Ogle for offshore Santa Barbara California Federal oil and gas units. Incorporated by reference from Exhibit 28.1 to the Company's Form 8-K dated May 24, 1994. (1) 10.10 Addendum #2 to agreement dated February 24, 1994 between Delta Petroleum Corporation and Burdette A. Ogle for offshore Santa Barbara California Federal oil and gas units. Incorporated by reference from Exhibit 28.2 to the Company's Form 8-K dated July 15, 1994. (1) 10.11 Addendum #3 to agreement dated February 24, 1994 between Delta Petroleum Corporation and Burdette A. Ogle. Incorporated by reference from Exhibit 28.3 to the Company's Form 8-K dated August 9, 1994. (1) 10.12 Addendum #4 to agreement dated February 24, 1994 between Delta Petroleum Corporation and Burdette A. Ogle for offshore Santa Barbara California Federal oil and gas units. Incorporated by reference from Exhibit 28.1 to the Company's Form 8-K dated August 31, 1993. (1) 10.13 Burdette A. Ogle "Assignment, Conveyance and Bill of Sale of Federal Oil and Gas Leases Reserving a Production Payment", "Lease Interests Purchase Option Agreement" and "Purchase and Sale Agreement". Incorporated by reference from Exhibit 28.1 to the Company's Form 8-K dated January 3, 1995. (1) 10.14 Companies Employment Agreements with Aleron H. Larson, Jr. and Roger A. Parker, previously filed on Form 10-KSB for the fiscal year ended June 30, 1998. (1) 10.15 Delta Petroleum Corporation 1993 Incentive Plan, as amended. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated November 1, 1996. (1) 11-7 10.16 Agreement among Eva H. Posman, as Chapter 11 Trustee of Underwriters Financial Group, Inc., Snyder Oil Corporation and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated May 23, 1997. (1) 10.17 Option and First Right of Refusal between Evergreen Resources, Inc., and Delta Petroleum Corporation dated December 23, 1997, previously filed on Form 10-KSB for the fiscal year ended June 30, 1998. (1) 10.18 Professional Services Agreement with GlobeMedia AG and Investment Representation Agreements with GlobeMedia AG, incorporated by reference from Exhibits 99.2 and 99.3 to the Company's Form 8-K dated April 9, 1998. (1) 10.19 Delta Petroleum Corporation 1993 Incentive Plan, as amended June 30, 1999. Incorporated by reference to the Company's Notice of Annual Meeting and Proxy Statement dated June 1, 1999. (1) 10.20 Agreement between Evergreen Resources, Inc., and Delta Petroleum Corporation effective January 1, 1999. Incorporated by reference from Exhibit 99.1 to the Company's Form 10-QSB for the quarterly period ended December 31, 1998. (1) 10.21 Agreement between Burdette A. Ogle and Delta Petroleum Corporation effective December 17, 1998. Incorporated by reference from Exhibit 99.2 to the Company's Form 10-QSB for the quarterly period ended December 31, 1998. (1) 10.22 Agreement between Delta Petroleum Corporation and Ambir Properties, Inc., dated October 12, 1998. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated October 16, 1998. (1) 10.23 Agreement between Whiting Petroleum Corporation and Delta Petroleum Corporation (including amendment) dated June 8, 1999. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated June 9, 1999. (1) 10.24 Purchase and Sale Agreement dated October 13, 1999 between Whiting Petroleum Corporation and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated November 1, 1999. (1) 10.25 Agreement between Delta Petroleum Corporation, Roger A. Parker and Aleron H. Larson, Jr. dated November 1, 1999. Incorporated by reference from Exhibit 99.3 to the Company's Form 8-K dated November 1, 1999. (1) 10.26 Conveyance and Assignment from Whiting Petroleum Corporation dated December 1, 1999. Incorporated by reference from Exhibit 10.1 to the Company's Form 8-K dated December 1, 1999. (1) II-8 10.27 Loan Agreement (without exhibits) between Kaiser-Francis Oil Company and Petroleum Corporation dated December 1, 1999. Incorporated by reference from Exhibit 10.2 to the Company's Form 8-K dated December 1, 1999. (1) 10.28 Promissory Note dated December 1, 1999. Incorporated by reference from Exhibit 10.3 to the Company's Form 8-K dated December 1, 1999. (1) 10.29 July 29, 1999 Agreement between GlobeMedia AG and Delta Petroleum Corporation with November 23, 1999 amendment. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated January 4, 2000. (1) 10.30 Letter Agreement between GlobeMedia AG and Delta Petroleum Corporation dated November 23, 1999. Incorporated by reference from Exhibit 99.3 to the Company's Form 8-K dated January 4, 2000. (1) 10.31 Agreement dated December 30, 1999 between Burdette A. Ogle and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.4 to the Company's Form 8-K dated January 4, 2000. (1) 10.32 Investment Representation Agreement dated December 17, 1999 between Evergreen Resources, Inc. and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.5 to the Company's Form 8-K dated January 4, 2000. (1) 10.33 Option Agreement between Evergreen Resources, Inc. and Delta Petroleum Corporation dated December 17, 1999 (effective as of January 4, 2000). Incorporated by reference from Exhibit 99.6 to the Company's Form 8-K dated January 4, 2000. (1) 10.34 Purchase and Sale Agreement dated June 1, 2000 between Whiting Petroleum Corporation and Delta Petroleum Corporation. Incorporated by reference from Exhibit 10.1 to the Company's Form 8-K dated July 10, 2000. (1) 10.35 Documents and Agreements dated July 10, 2000 between Delta Petroleum Corporation and Hexagon Investments, Inc. and/or Sovereign Holdings, LLC related to financing arrangements: -Partial Assignment of Contract; -Collateral Assignment of Purchase and Sale Agreement; -Letter Agreement re: loan; -Estoppel Certificate and Agreement; -Promissory Note; -Guarantee Agreement Incorporated by reference from Exhibit 10.2 to the Company's Form 8-K dated July 10, 2000. (1) 10.36 Investment Agreement dated July 21, 2000 between Delta Petroleum Corporation and Swartz Private Equity, LLC and related agreements. Incorporated by reference from Exhibit 99.2 to the Company's Form 8-K dated July 10, 2000. (1) II-9 10.37 Purchase and Sale Agreement and supplemental Letter Agreement dated September 6, 2000, between Saga Petroleum Corporation, et al. and Delta Petroleum Corporation. Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated September 7, 2000. (1) 10.38 Purchase and Sale Agreement between Delta Petroleum Corporation and Castle Offshore LLC and BWAB Limited Liability Company dated August 4, 2000. Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated September 29, 2000. (1) 10.39 Documents evidencing financing arrangements between Hexagon Investments and Delta Petroleum Corporation dated September 28, 2000. Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated September 29, 2000. (1) 10.40 Termination Agreement and Purchase and Sale Agreement dated as of December 18, 2000 between Delta Petroleum Corporation and Saga Petroleum Corp., et al. Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated December 22, 2000. (1) 10.41 Agreements between Evergreen Resources Inc. and Delta Petroleum Corporation dated January 3, 2001. Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated January 22, 2001. (1) 10.41 Purchase and Sale Agreement dated March 29, 2001, between Delta Petroleum Corporation and Panaco, Inc. (without exhibits). Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated April 13, 2001. (1) 21 Subsidiaries of the Registrant (2) 23.2 Consent of KPMG LLP (3) 23.3 Consent of Krys Boyle Freedman & Sawyer, P.C. ** ------------------------ (1) Incorporated by reference. (2) Previously filed. (3) Filed herewith electronically. ** Contained in the legal opinion filed as Exhibit 5.1. Undertakings The Company on behalf of itself hereby undertakes and commits as follows: A. 1. To file, during any period in which it offers or sells securities, a post-effective amendment to this registration statement to: (i) Include any prospectus required by Section 10(a)(3) of the Securities Act. II-10 (ii) Reflect in the prospectus any facts or events which, individually or together, represent a fundamental change in the information in the registration statement. (iii) Include any additional or changed material information on the plan of distribution. 2. For determining liability under the Securities Act, to treat each post-effective amendment as a new registration statement of the securities offered, and the offering of the securities at that time to be the initial bona fide offering. 3. To file a post-effective amendment to remove from registration any of the securities that remain unsold at the end of the offering. B. Insofar as indemnification for liabilities arising under the Securities Act of 1933 (the "Act") may be permitted to directors, officers and controlling persons of Delta under the foregoing provisions, or otherwise, Delta has been advised that in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by Delta of expenses incurred or paid by a director, officer or controlling person of Delta in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, Delta will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue. II-11 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, we have caused this Amendment to be signed on our behalf by the undersigned, who are authorized to do so. DELTA PETROLEUM CORPORATION Date: November 29, 2001 By: /s/ Roger A. Parker ---------------------------------- Roger A. Parker, President and Chief Executive Officer Date: November 29, 2001 By: /s/ Kevin K. Nanke ---------------------------------- Kevin K. Nanke, Treasurer and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on our behalf and in the capacities and on the dates indicated. Date: November 29, 2001 /s/ Aleron H. Larson, Jr. ---------------------------------- Aleron H. Larson, Jr., Director Date: November 29, 2001 /s/ Roger A. Parker ---------------------------------- Roger A. Parker, Director Date: November 29, 2001 /s/ Jerrie F. Eckelberger ---------------------------------- Jerrie F. Eckelberger, Director Date: November 29, 2001 /s/ James P. Wallace ---------------------------------- James P. Wallace, Director