S-1/A 1 deltas1a5.txt DELTA PETROLEUM CORPORATION S-1 A/5 As Filed With the Securities and Exchange Commission on August 9, 2002 Registration Statement No.333-59898 ============================================================================= UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 -------- FORM S-1/A AMENDMENT NO. 5 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) 475 17th Street, Suite 1400 Denver, Colorado 80202 (303) 293-9133 (Address and telephone number of issuer's principal executive offices) Roger A. Parker, President/CEO 475 17th Street, Suite 1400 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 Rule 457(c). (3) Previously paid PROSPECTUS SUBJECT TO COMPLETION DATED AUGUST __, 2002 ----------------------------------------------------------------------------- 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 Corporation ("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 4 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 _____________, 2002 Table of Contents Part I Table of Contents...................................................... i Prospectus Summary .................................................... 1 Risk Factors........................................................... 4 Use of Proceeds ....................................................... 10 Determination of Offering Price ....................................... 10 Information with Respect to Delta ..................................... 10 Our Business .................................................... 11 Acquisition of Assets of Castle Energy........................... 18 Description of Property ......................................... 31 Legal Proceedings ............................................... 54 Common Equity Securities ........................................ 55 Financial Data .................................................. 56 Management's Discussion and Analysis or Plan of Operation ....... 56 Directors, Executive Officers, Promoters and Control Persons .... 77 Executive Compensation .......................................... 80 Security Ownership of Certain Beneficial Owners and Management .. 83 Certain Relationships and Related Party Transactions ............ 85 Selling Security Holder ............................................... 90 Plan of Distribution .................................................. 96 Description of Securities ............................................. 98 Interests of Named Experts and Counsel ................................ 99 Commission Position on Indemnification for Securities Act Liabilities ........................................... 99 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 1400, 475 Seventeenth Street, Denver, Colorado 80202, and our telephone number is (303) 293-9133. Our common stock is listed on the 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 nine months ended March 31, 2002, we had total revenue of $4,232,000, operating expenses of $7,849,000 and a net loss for the nine months of $3,493,000. During the year ended June 30, 2001, we had total revenue of $12,877,000, operating expenses of $11,199,000 and net income for fiscal 2001 of $345,000. During the year ended June 30, 2000, we had total revenue 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 seven states. We had undeveloped properties in five states, and interests in five federal units and one lease offshore California near Santa Barbara. We operated 25 of the wells and the remaining wells were operated by independent operators. As discussed in more detail below, since June 30, 2001 we have made several acquisitions and disposed of properties which will significantly affect our operating results in the future, the largest of which was our acquisition of all of the domestic oil and gas properties of Castle Energy Corporation on May 31, 2002. Subsequent to our fiscal year end we purchased all the producing properties of Amber Resources Company, our 91.68% owned subsidiary, 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. On November 15, 2001, we acquired producing oil and gas interests in Texas from certain unrelated entities and an unrelated individual. The acquisition had a purchase price of approximately $788,000 consisting of $413,000 in cash and 137,000 shares of our restricted common stock with a fair value of $375,000 based on the closing price on the date of closing. On February 19, 2002, we completed the acquisition of Piper Petroleum Company ("Piper"), a privately owned oil and gas company headquartered in Fort Worth, Texas. We issued 1,374,240 shares of our restricted common stock for 100% of the shares of Piper. The 1,374,240 shares of restricted common stock were valued at approximately $5,234,000 based on the five-day average closing price surrounding the announcement of the merger. In addition, we issued 51,000 shares for the cancellation of certain debt of Piper. As a result of 1 the acquisition, we acquired Piper's working and royalty interests in over 300 properties which are primarily located in Texas, Oklahoma and Louisiana along with a 5% working interest in the Comet Ridge coal bed methane gas project in Queensland, Australia. This project is classified as held for sale at March 31, 2002 at its estimated fair value of $5,272,000. We completed the sale of 21 producing wells and acreage located primarily in the Eland and Stadium fields of Stark County, North Dakota, to Sovereign Holdings, LLC, a privately-held Colorado limited liability company, for cash consideration of $2,750,000 pursuant to a purchase and sale agreement dated February 1, 2002 and effective January 1, 2002. As a result of the sale, we recorded a loss on sale of oil and gas properties of $1,000. These properties accounted for approximately 9.45% of our total assets as of June 30, 2001 and also accounted for approximately 22.6% of our total revenues and approximately 11.9% of our total operating expenses during our past fiscal year. Approximately $1,300,000 of the proceeds from the sale were used to pay existing debt. On March 1, 2002, we sold the properties acquired on November 15, 2001, to Whiting Petroleum Corporation for $648,000. As a result of the sale, we recorded a loss on sale of oil and gas properties of $106,000. Proceeds from the sale were used to pay existing debt. On May 24, 2002 we completed the sale of our undivided interests in an Authority to Prospect (ATP) covering lands in Queensland, Australia, to Tipperary Corporation, in exchange for Tipperary's producing properties in the West Buna Field (Hardin and Jasper counties, Texas), $700,000 in cash and 250,000 unregistered shares of Tipperary common stock. Net daily production from the West Buna Field approximates 900,000 cubic feet equivalent. On May 31, 2002, we acquired all of the domestic oil and gas properties of Castle Energy Corporation. The properties acquired from Castle consist of interests in approximately 525 producing wells located in fourteen (14) states, plus associated undeveloped acreage. We issued 9,566,000 shares of common stock to Castle Energy Corporation as part of the purchase price. We are entitled to repurchase up to 3,188,667 of our shares from Castle for $4.50 per share for a period of one year after closing. Our agreement with Castle was effective as of October 1, 2001 and the net operating revenues from the properties between the effective date and the May 31, 2002 closing date will be recorded as an adjustment to the purchase price. Also on May 31, 2002 we obtained a new $20 million credit facility with the Bank of Oklahoma and Local Oklahoma Bank, part of which was used to pay the remainder of the Castle purchase price. Approximately $19 million of the credit facility was utilized to close the Castle transaction and to pay off our existing loan with US Bank. Our total debt now approximates $25 million. A substantial portion of our oil and gas properties is pledged as collateral for our new loan and the terms of the Credit Agreement limit our flexibility to engage in many types of business activities without obtaining the consent of our lenders in advance. See "Credit Facility." 2 The Offering ------------ Selling Security Holder Swartz Private Equity, LLC. Securities Offered A total of 6,500,000 shares 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 29,117,959 including all of the shares Outstanding after issuable upon the exercise of warrants held by Offering Swartz. We currently only have a total of 22,617,959 shares issued and outstanding, so if all of the shares that may be offered are actually sold, they would constitute about 22% of our then outstanding shares. Under the terms of the Investment Agreement with Swartz, we are not obligated to sell Swartz all of the Put Shares nor do we intend to sell Put Shares to Swartz unless it is beneficial to us. 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"). 3 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 our oil and gas properties and our production revenue. Although we intend to seek outside capital to either refinance the debt or provide liquidity, 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 March 31, 2002 we had an accumulated deficit of $26,093,000. During the nine months ended March 31, 2002, we had total revenue of $5,290,000, operating expenses of $7,849,000 and a net loss for the six months of $3,493,000. During fiscal 2001 we had total revenue 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 revenue 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 an 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 4 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"). 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 is intended to present a long-term regional perspective of potential onshore constraints that should be considered when developing existing undeveloped offshore leases. The "worst" case scenario under the COOGER study 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. Under those circumstances 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/or for the value of the oil and gas reserves found on the leases through our exploration activities and those of our predecessors. On June 22, 2001, in litigation relating to the development of these properties brought by the State of California, 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. In a separate action, on January 9, 2002 we and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government materially breached the terms of the leases for our offshore California properties. Our suit seeks compensation for the lease bonuses and rentals paid to the Federal Government, exploration costs, and related expenses. The ultimate outcome and effects of the litigation pertaining to our Offshore California properties 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. During the nine months ended March 31, 2002, we 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 5 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. 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. 6 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. 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 depend on key personnel. We currently have only 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 do not have key man insurance on the lives of any of these individuals. 7 14. 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 committed to participate in the well under the condition that they would be assigned their respective working interests in the well and associated spacing unit after they had been billed and had 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. 15. The exercise of our Put Rights may dilute the interests of other security holders. We have entered into an arrangement with Swartz Private Equity, LLC under which we may sell shares of our common stock to Swartz at a discount from the then prevailing market price. The exercise of these rights may substantially dilute the interests of other security holders. Under the terms of our relationship with Swartz, we will issue shares to Swartz upon exercise of our Put Rights at a price equal to the lesser of: 8 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 exercise of our Put Rights 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 Put Rights. 16. 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. 17. 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 Put Rights 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. Under the terms of the Investment Agreement with Swartz, however, we are not obligated to sell any of our shares to Swartz nor do we intend to sell shares to Swartz unless it is beneficial to us. 18. There are Uncertainties Associated with the Castle Acquisition. On May 31, 2002, we acquired all of Castle's domestic oil and gas assets consisting of approximately 525 properties located in 14 states. Due to the size of this acquisition relative to our size before the transaction occurred, it has been necessary for us to significantly increase our staff, implement new operational processes and procedures and incur incremental increases in our costs of doing business. We have not yet hired all of the new staff or made all of the operational changes that we will need to effectively absorb these assets into our business, and there is risk that we will be unsuccessful in our efforts to do so. 9 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 August 6, 2002, the reported closing price for our common stock on the Nasdaq Small-Cap Market was $3.30. 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 10 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. - 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 1400, 475 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 also had undeveloped properties in six states, and interests in five federal units and one lease offshore California near Santa Barbara. We operated 27 of the wells and the remaining wells were operated by independent operators. All of these 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. As discussed in more detail below, since June 30, 2001 we have made several acquisitions and disposed of properties which will significantly affect our operating results in the future, the largest of which was our acquisition of all of the domestic oil and gas properties of Castle Energy Corporation on May 31, 2002. (See "Description of Property.") 11 We have 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 22,482,030 shares were issued and outstanding as of June 30, 2002. 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 June 1, 2002. Additionally, as of June 30, 2002, we had 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 June 30, 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 have historically included oil and gas exploration, development, and production operations. Amber owned 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 until July 1, 2001 when we purchased all of Amber's assets. 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. We are 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. Prior to our acquisition of Piper Petroleum Company on February 19, 2002 and, among other transactions, our acquisition of all of the domestic oil and gas properties of Castle Energy Corporation on May 31, 2002, we, directly and through Amber, owned producing and non-producing oil and gas interests, undeveloped leasehold interests and related assets in Arkansas, California, Colorado, Oklahoma, New Mexico, South Dakota, Texas and Wyoming; and interests in a producing Federal unit offshore California and undeveloped offshore Federal leases near Santa Barbara, California. As the result of our recent acquisitions, we have acquired additional properties located in Alabama, California, Illinois, Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Pennsylvania, Texas and Wyoming. 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. Subsequent to our fiscal year end we purchased all the producing properties of Amber Resources Company, our 91.68% owned subsidiary, 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. On November 15, 2001, we acquired 12 producing oil and gas interests in Texas from certain unrelated entities and an unrelated individual. The acquisition had a purchase price of approximately $788,000 consisting of $413,000 in cash and 137,000 shares of our restricted common stock with a fair value of $375,000 based on the closing price on the date of closing. On February 19, 2002, we completed the acquisition of Piper Petroleum Company ("Piper"), a privately owned oil and gas company headquartered in Fort Worth, Texas. We issued 1,374,240 shares of our restricted common stock for 100% of the shares of Piper. The 1,374,240 shares of restricted common stock were valued at approximately $5,234,000 based on the five-day average closing price surrounding the announcement of the merger. In addition, we issued 51,000 shares for the cancellation of certain debt of Piper. As a result of the acquisition, we acquired Piper's working and royalty interests in over 300 properties which are primarily located in Texas, Oklahoma and Louisiana along with a 5% working interest in the Comet Ridge coal bed methane gas project in Queensland, Australia. This project is classified as held for sale at March 31, 2002 at its estimated fair value of $5,272,000. We completed the sale of 21 producing wells and acreage located primarily in the Eland and Stadium fields of Stark County, North Dakota, to Sovereign Holdings, LLC, a privately-held Colorado limited liability company, for cash consideration of $2,750,000 pursuant to a purchase and sale agreement dated February 1, 2002 and effective January 1, 2002. As a result of the sale, we recorded a loss on sale of oil and gas properties of $1,000. These properties accounted for approximately 9.45% of our total assets as of June 30, 2001 and also accounted for approximately 22.6% of our total revenues and approximately 11.9% of our total operating expenses during our past fiscal year. Approximately $1,300,000 of the proceeds from the sale were used to pay existing debt. On March 1, 2002, we sold the properties acquired on November 15, 2001, to Whiting Petroleum Corporation for $648,000. As a result of the Sale, we recorded a loss on sale of oil and gas properties of $106,000. Proceeds from the sale were used to pay existing debt. On May 24, 2002 we completed the sale of our undivided interests in an Authority to Prospect (ATP) covering lands in Queensland, Australia, to Tipperary Corporation, in exchange for Tipperary's producing properties in the West Buna Field (Hardin and Jasper counties, Texas)which had a fair market value of approximately $4,100,000, $700,000 in cash, and 250,000 unregistered shares of Tipperary common stock. Net daily production from the West Buna Field approximates 900,000 cubic feet equivalent. On May 31, 2002, we acquired all of the domestic oil and gas properties of Castle Energy Corporation. The properties acquired from Castle consist of interests in approximately 525 producing wells located in fourteen (14) states, plus associated undeveloped acreage. We issued 9,566,000 shares of Common Stock to Castle Energy Corporation as part of the purchase price. We are entitled to repurchase up to 3,188,667 of our shares from Castle for $4.50 per share for a period of one year after closing. Our agreement with Castle was effective as of October 1, 2001 and the net operating revenues from the properties between the effective date and the May 31, 2002 closing date will be recorded as an adjustment to the purchase price. 13 Also on May 31, 2002 we obtained a new $20 million credit facility with the Bank of Oklahoma and Local Oklahoma Bank, part of which was used to pay the remainder of the Castle purchase price. Approximately $19 million of the credit facility was utilized to close the Castle transaction and to pay off our existing loan with US Bank. Our total debt now approximates $25 million. A substantial portion of our oil and gas properties is pledged as collateral for our new loan and the terms of the Credit Agreement limit our flexibility to engage in many types of business activities without obtaining the consent of our lenders in advance. "See Credit Agreement." (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. 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. 14 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 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 15 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 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 16 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. (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, 17 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 approximately twenty (20) full-time employees. Additionally, certain 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. ACQUISITION OF ASSETS OF CASTLE ENERGY Because of the date on which the Castle acquisition occurred, May 31, 2002, we are presenting information with respect to Castle separately and Castle has not yet been integrated into our disclosures. All of the information provided in this prospectus with respect to Castle has been obtained from Castle's 10-K dated September 30, 2001 and from its subsequent periodic reports. The effects of the Castle acquisition will be reflected in our 10-K for the year ended June 30, 2002. At our annual meeting of shareholders on May 30, 2002, our shareholders approved our purchase of the domestic oil and gas properties of Castle Energy Corporation, and the transaction was completed on May 31, 2002. The properties acquired from Castle consist of interests in approximately 525 producing wells located in fourteen (14) states, plus associated undeveloped acreage. We issued 9,566,000 shares of Common Stock to Castle Energy Corporation as part of the purchase price. Our agreement with Castle was effective as of October 1, 2001 and the net operating revenues from the properties between the effective date and the May 31, 2002 closing date will be recorded as an adjustment to the purchase price. On January 15, 2002 we entered into a Purchase and Sale Agreement with Castle Energy Corporation and three of its subsidiaries ("Castle") pursuant to which we and one of our subsidiaries agreed to purchase all of Castle's United States oil and gas properties in exchange for $20 million in cash and 9,566,000 shares of Delta's Common Stock. As a part of the acquisition, upon closing, we granted the right to acquire a 4% working interest in the properties acquired for a cost of $974,000 to BWAB Limited Liability Company, a less than 10% shareholder of Delta, for its consultation and assistance related to the acquisition. The difference between the price to be paid by BWAB and 4% of the cost of the Castle properties will be treated as an additional acquisition cost to us. Also on May 31, 2002 we obtained a new $20 million credit facility with the Bank of Oklahoma and Local Oklahoma Bank, part of which was used to pay the remainder of the purchase price. Approximately $19 million of the credit facility was utilized to close the Castle Energy transaction and to pay off our existing loan with US Bank. Our total debt now approximates $25 million. A substantial portion of our oil and gas properties is pledged as collateral for our new loan and the terms of the Credit Agreement limit our flexibility to engage in many types of business activities without obtaining the consent of our lenders in advance. A copy of the Credit Agreement is attached as an exhibit to this Report. (See "Credit Facility") 18 As of the record date for our shareholders' meeting, May 1, 2002, we had 12,836,800 shares issued and outstanding. As a result, the 9,566,000 shares issued to Castle represent an amount equal to approximately 42.5% of the shares outstanding after giving effect to the issuance of the shares to Castle. In addition to the shares issued to Castle at closing, it should be noted that Castle previously owned 382,289 of our shares and as a result Castle now owns approximately 44% of our outstanding shares. Our management became aware of the possibility that Castle might be willing to sell its domestic oil and gas properties as the result of an introduction made by BWAB. BWAB is in the business of buying and selling oil and gas properties and occasionally acts as a broker in some oil and gas transactions, including several acquisition and 32 divestiture transactions involving both Castle and us. On September 29, 2000 we acquired 100% of the West Delta Block 52 unit, which was owned 75% by Castle and 25% by BWAB. Although BWAB is not an affiliate of Castle, it has had numerous business dealings with Castle over the past several years and it is our understanding that Steven Roitman, the President of BWAB, became aware of the possible availability of the Castle properties through his contact with Joseph Castle. Mr. Roitman then presented the opportunity to purchase the properties to Roger Parker, our President and Chief Executive Officer, who on our behalf negotiated the terms of the transaction directly with Joseph Castle over the course of a number of months in 2001 leading up to the execution of the Purchase and Sale Agreement. After reviewing the engineering reports related to Castle's domestic oil and gas properties and considering the market value of our common stock at the time, the parties agreed upon a price that we believe is reasonable. During the course of negotiations, BWAB continued to provide both parties with helpful insights because of its familiarity with some of the properties. BWAB also made its employees and analysis tools available to both parties to enhance their ability to make various decisions as negotiations continued. Since BWAB had relationships with both Castle and us, it was also able to facilitate communication between us, minimize our misunderstandings and help us to reach a final agreement. BWAB's right to acquire an interest in the properties was determined by the parties at the outset of negotiations, contingent upon our reaching an agreement and closing the transaction. Reports, Opinions and Appraisals -------------------------------- We did not engage an independent firm to render a fairness opinion. Management believed that an independent fairness opinion was unnecessary for the following reasons: the assets acquired consist almost entirely of oil and gas leases, the most valuable of which had recent engineering reports; management believed such reports in themselves provided an independent valuation of the assets similar to what would be expected from an independent fairness opinion; and the Board believed that our management possessed sufficient skills and experience to negotiate a fair price for the assets that were ultimately acquired. The engineering reports reviewed by management were prepared by Huntley & Huntley and Ralph E. Davis Associates, Inc., independent petroleum reservoir engineers. Huntley & Huntley, Inc. of Monroeville, Pennsylvania is an oil and gas consulting firm that has provided reservoir engineering and geological services to the petroleum industry since 1912. The principal services offered 19 by this firm are geological feasibility and due diligence reports, well engineering and drilling, and reserves and economics evaluations. Huntley & Huntley provides oil and gas reserve reports to numerous publicly-held companies. Ralph E. Davis Associates, Inc., Houston, Texas, is a consulting firm that has provided reservoir engineering and geological services to the petroleum industry since 1924. This firm currently has a staff of six engineers and geologists who specialize in petroleum reservoir evaluation and analysis. Ralph E. Davis Associates, Inc. provides oil and gas reserve reports and other services to many publicly-held companies. Huntley & Huntley and Ralph E. Davis Associates, Inc. were selected by and paid by Castle to prepare the reserve estimates used in Castle's Annual Report on Form 10-K for the fiscal year ended September 30, 2001. We did not pay either of these firms any compensation in connection with the transaction with Castle, nor is any compensation expected to be paid in connection with the transaction in the future. It is possible that we might use the services of either or both of these firms in the future for the preparation of reserve estimates or other services. The reserve estimates reviewed by us were based upon subjective engineering judgments made by Huntley & Huntley and Ralph E. Davis Associates, Inc. and may be affected by the limitations inherent in such estimations. The process of estimating reserves is subject to continuous revisions as additional information is made available through drilling, testing, reservoir studies and production history. There can be no assurance such estimates will not be materially revised in subsequent periods. Estimated quantities of proved reserves as of September 30, 2001, the date of last official appraisal of properties, all of which are domestic reserves, combined from the reports provided by Huntley & Huntley and Ralph E. Davis Associates, Inc., are summarized below: Net MCF (1) of gas: Proved developed ......................... 26,480,000 Proved undeveloped ....................... 4,212,000 ---------- Total..................................... 30,692,000 ========== Net barrels of oil: Proved developed ......................... 1,890,000 Proved undeveloped ....................... 1,119,000 ---------- Total..................................... 3,009,000 ========== ------------------- (1) Thousand cubic feet The following is a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil and gas reserves, as prescribed in Statement of Financial Accounting Standards No. 69. The standardized measure of discounted future net cash flows does not purport to 20 present the fair market value of our oil and gas properties. An estimate of fair market value would also take into account, among other factors, the likelihood of future recoveries of oil and gas in excess of proved reserves, anticipated future changes in prices of oil and gas and related development and production costs, a discount factor based on market interest rates in effect at the date of valuation and the risks inherent in reserve estimates. September 30, 2001 ------------------ Future cash inflows $130,289,000 Future production costs (41,193,000) Future development costs (8,585,000) Future income tax expense (10,892,000) ------------ Future net cash flows 69,619,000 Discount factor of 10% for estimated timing of future cash flows (33,599,000) ------------ Standardized measure of discounted future cash flows $ 36,020,000 ============ The future cash flows were computed using the applicable year-end prices and costs that related to the then existing proved oil and gas reserves in which Castle had interests. The estimates of future income tax expense are computed at the blended rate (Federal and state combined) of 36%. The following were the sources of changes in the standardized measure of discounted future net cash flows: September 30, 2001 ------------------ Standardized measure, beginning of year $ 91,119,000 Sale of oil and gas, net of production costs (13,745,000) Net changes in prices (62,271,000) Purchase of reserves in place 7,662,000 Changes in estimated future development costs 1,518,000 Development costs incurred during the period that reduced future development costs 2,113,000 Revisions in reserve quantity estimates (27,596,000) Net changes in income taxes 31,054,000 Accretion of discount 9,112,000 Other: Change in timing of production (944,000) Other factors (2,002,000) ------------ Standardized measure, end of year $ 36,020,000 ============ Past Material Relationships --------------------------- In September 2000, a subsidiary of Castle sold us its majority interest in twenty-six offshore Louisiana wells. Our adjusted purchase price of 21 $3,059,000 consisted of $1,122,000 cash plus 382,289 shares of our Common Stock valued at the closing market price of $1,937,000. We became aware of this opportunity as a result of an introduction by BWAB. New Directors ------------- Upon closing of the transaction with Castle, our four-person board of directors was expanded with the appointment of three additional directors that were selected by Castle in accordance with the terms of our Purchase and Sale Agreement. The three persons appointed are Joseph L. Castle II, Russell S. Lewis and John P. Keller, all of whom also currently serve as directors of Castle. Biographical information on our three new directors is as follows: Joseph L. Castle II (age 70) has been a Director of Castle since 1985. Mr. Castle is the Chairman of the Board of Directors and Chief Executive Officer of Castle, having served as Chairman from December 1985 through May 1992 and since December 20, 1993. Mr. Castle also served as President of Castle from December 1985 through December 20, 1993, when he reassumed his position as Chairman of the Board. Previously, Mr. Castle was Vice President of Philadelphia National Bank, a corporate finance partner at Butcher and Sherrerd, an investment banking firm, and a Trustee of The Reading Company. Mr. Castle has worked in the energy industry in various capacities since 1971. Mr. Castle is also a director of Comcast Corporation and Charming Shoppes, Inc. Since May of 2000, Mr. Castle has served as the Chairman of the Board of Trustees of the Diet Drug Products Liability ("Phen-Fen") Settlement Trust. Russell S. Lewis (age 47) has been a director of Castle since April 2000. From 1994 to 1999, Mr. Lewis was the Chief Executive Officer of TransCore, Inc., a company which sells and installs electronic toll collection systems. Since 1999, Mr. Lewis has been the owner and President of Lewis Capital Group, a company investing in and providing consulting services to growth-oriented companies. Since March 2000, Mr. Lewis has also been Senior Vice President of Corporate Development at VeriSign, Inc. In February of 2002, Mr. Lewis jointed VeriSign full time as Executive Vice President and General Manager of VeriSign's Global Registry Services Group, which maintains the authoritative databases for all ".com," ".net" and ".org" domain names in the internet. John P. Keller (age 63) has been a director of Castle since April 1997. Since 1972, Mr. Keller has served as the President of Keller Group, Inc., a privately-held corporation with subsidiaries in Ohio, Pennsylvania and Virginia. In 1993 and 1994, Mr. Keller also served as the Chairman of American Appraisal Associates, an appraisal company. Mr. Keller is also a director of A.M. Castle & Co. and Old Kent Financial Corporation. Retained Assets --------------- Pursuant to the terms of the Purchase and Sale Agreement, Castle retained all of its business records, cash, bank accounts, letters of credit and prepaid insurance; the management information systems, accounting software and other intellectual property used in the administration of Castle's businesses; all claims that Castle may have under any policy of insurance, indemnity or bond other than claims relating to property damage or casualty loss affecting the leases and wells occurring between the effective date and closing; all 22 accounts receivable, trade credits or notes receivable relating to transactions processed by Castle prior to closing; any files or records that Castle is contractually or otherwise obligated not to disclose to Delta; all claims and causes of action arising from acts, omissions or events, or damage or destruction of property occurring prior to the effective date; engineering studies or reserve reports relating to the leases and wells; and all interests and rights not related to the leases and wells to be purchased. Castle retained ownership of a fifty percent interest in a drilling concession in Romania and a thirty-five percent membership interest in Networked Energy LLC, a private company engaged in the operation of energy facilities that supply power, heating and cooling services directly to retail customers. Title Matters ------------- Prior to the closing, we and our representatives had the right to examine all of the title records, opinions and other documents relating to the assets to determine if any title defects exist as defined in the agreement. By correspondence dated March 26, 2002, we notified Castle of certain claimed title defects. If Castle agrees that any title defects exist, it will indemnify us for expenses. Post Closing Matters -------------------- Upon closing of the Purchase and Sale Agreement, we have agreed to diligently pursue the filing and other requirements to assume the operation and ownership of the assets. We will also provide transitional accounting personnel at our expense for at least two months before assuming full accounting responsibilities for the assets. On July 3, 2002, at our expense we filed a registration statement with the Securities and Exchange Commission to register the 9,566,000 shares issued to Castle in connection with the sale of the assets. This registration statement was declared effective on July 16, 2002. For a period of one year after the closing, we will have the right to repurchase up to 3,188,667 of the shares issued to Castle at $4.50 per share. Castle has agreed to retain at least 3,188,667 shares of our common stock during this period for possible repurchase. Credit Facility --------------- Our credit facility allows us to borrow, repay and reborrow amounts subject to the terms and conditions of the Credit Agreement. At the time we entered into our Credit Agreement with Bank of Oklahoma and Local Oklahoma Bank and related promissory notes on May 31, 2002, we granted a first and prior lien to the lending banks on most of our oil and gas properties, certain related equipment, oil and gas inventory, certain bank accounts and proceeds. Under the terms of the Credit Agreement, the oil and gas properties mortgaged must represent not less than 80% of the engineered value of our oil and gas properties as determined by the Bank of Oklahoma using its own pricing parameters, exclusive of the properties that are mortgaged to Kaiser-Francis under a separate lending arrangement. "Engineered value" for the purposes of 23 our credit facility means our future net revenues discounted at the discount rate being used by the Bank of Oklahoma as of the date that the determination is made using the pricing parameters used in the engineering report that is furnished to the Bank of Oklahoma. Since this engineering report will be obtained by the Bank of Oklahoma using its own parameters, it may reach different conclusions than those in reserve reports obtained by us from other sources. In addition, any obligations arising from transactions between us and one or more of the banks providing for the hedging, forward sale or swap of crude oil or natural gas or interest rate protection will also be required to be secured by a mortgage on our properties and will consequently reduce our borrowing base. These hedging obligations will be required to be secured and repaid on the same basis as our indebtedness and obligations under the loan documents. Our borrowing base, which determines the amounts that we are allowed to borrow or have outstanding under our credit facility, was initially determined to be $20 million at the time we entered into the Credit Agreement. Subsequent determinations of our borrowing base will be made by the lending banks at least semi-annually on October 1 and April 1 of each year beginning October 1, 2002 or as unscheduled redeterminations. In connection with each determination of our borrowing base, the banks will also redetermine the amount of our monthly commitment reduction. The monthly commitment reduction was $260,000.00 beginning as of July 1, 2002 and will continue at that amount until the amount of the monthly commitment reduction is redetermined. Our borrowing base and the revolving commitment of the banks to lend money under the Credit Agreement will be reduced as of the first day of each month by an amount determined by the banks under the Credit Agreement. The amount of the borrowing base will also be reduced from time to time by the amount of any prepayment that results from our sale of oil and gas Properties. If as a result of any such monthly commitment reduction or reduction in the amount of our borrowing base, the total amount of our outstanding debt ever exceeds the amount of the revolving commitment then in effect, then within 30 days after we are notified by the Bank of Oklahoma, we must make a mandatory prepayment of principal that is sufficient to cause our total outstanding indebtedness to not exceed our borrowing base. If for any reason we were unable to pay the full amount of the mandatory prepayment within the 30 requisite day period, we would be in default of our obligations under the Credit Agreement. If an unscheduled redetermination of our borrowing base is made by the banks, we will be notified of the new borrowing base and monthly commitment reduction, and this new borrowing base and monthly commitment reduction will then continue until the next determination date. All determinations (scheduled or unscheduled) of the borrowing base and the monthly commitment reduction require the approval of a majority of the lending banks, but the amount of the borrowing base cannot be increased, and the amount of the monthly commitment reduction cannot be reduced, without the approval of all of the lending banks. If at any time any of the oil and gas properties are sold, the borrowing base then in effect will automatically be reduced by a sum equal to the amount of prepayment that is required to be made. In general, we will be required to immediately make a prepayment of principal on our revolving notes in an amount equal to 100% of the release price that we receive from the sale of any of our oil and gas properties. Any 24 such sale would be required to be approved in advance by a majority of the lending banks. The amount of the release price will be determined by a majority of the lending banks in their discretion based upon the loan collateral value which such banks in their discretion (using such methodology, assumptions and discounts rates as the banks customarily use in assigning collateral value to oil and gas properties, oil and gas gathering systems, gas processing and plant operations) assign to such oil and gas properties at the time in question. Any such prepayment of principal on our revolving notes will not be in lieu of, but will be in addition to, any monthly commitment reduction or any mandatory prepayment of principal required to be paid under the Credit Agreement. We are also required to establish and maintain our operating accounts with the Bank of Oklahoma as agent for the lending banks. These operating accounts are required to be our primary oil and gas operating bank accounts for the purpose of depositing proceeds from oil and gas sales received from the collateral for the credit facility and these accounts are to be maintained with the Bank of Oklahoma until all amounts due have been paid in full. We granted a security interest to the lending banks in and to these operating accounts and all checks, drafts and other items ever received by any Bank for deposit therein. If any event of default occurs under the loan documents, the Bank of Oklahoma will have the immediate right, without prior notice or demand, to take and apply against our obligations any and all funds legally and beneficially owned by us then or thereafter on deposit in the operating accounts. We are not permitted to redirect the payment of such proceeds of production without the consent of the Bank of Oklahoma. Within five days after receiving a written request from the Bank of Oklahoma, as agent for the lending banks, we are obligated to deliver such additional mortgages, deeds of trust, instruments, security agreements, assignments, financing statements, and other documents, as may be reasonably necessary in the opinion of Bank of Oklahoma and its counsel, to grant valid first mortgage liens and first, prior and perfected security interests in and to additional oil and gas properties of such value as the banks deem necessary to provide additional security for full and prompt payment of all amounts owed. For so long as the revolving commitment is in existence or any amount is owed under any of the loan documents, without the prior written consent of a majority of the lending banks: (a) We will not be permitted to create, incur, assume or permit to exist any lien, security interest or other encumbrance on any of our assets or properties except for certain permitted liens. (b) We will not be permitted to sell, lease, transfer or otherwise dispose of, in any fiscal year, any of our oil and gas assets except for sales of production from our oil and gas properties made in the ordinary course of our oil and gas businesses, sales made with the consent of a majority of the lending banks and sales, leases or transfers or other dispositions of oil and gas properties made by us during any fiscal year, in one or any series of transactions, the aggregate value of which does not exceed $100,000.00 if, and only if, such sale, lease, transfer or other disposition does not result in the occurrence of a default or event of default under our loan documents. Further, neither we nor any of our subsidiaries can, without the prior written 25 consent of a majority of the lending banks, sell, lease, transfer or otherwise dispose of any oil and gas assets unless such disposition is specifically permitted by the Credit Agreement. (c) We cannot allow our ratio of consolidated current assets to consolidated current liabilities to be less than 1.0 to 1.0 as of the end of any fiscal quarter. (d) We cannot allow our consolidated debt service coverage ratio to ever be less than 1.20 to 1.0 for any quarterly fiscal period. (e) Except under very limited circumstances, we will not be permitted to consolidate or merge with or into any other person. (f) We will not be permitted to incur, create, assume or in any manner become or be liable in respect of any indebtedness (including letters of credit other than those letters of credit permitted in the Credit Agreement) in excess of $100,000.00 in the aggregate, nor may we guarantee or otherwise in any manner become or be liable in respect of any indebtedness, liabilities or other obligations of any other person or entity, whether by agreement to purchase the indebtedness of any other person or entity or agreement for the furnishing of funds to any other person or entity through the purchase or lease of goods, supplies or services (or by way of stock purchase, capital contribution, advance or loan) for the purpose of paying or discharging the indebtedness of any other person or entity, or otherwise, except that the foregoing restrictions shall not apply to: (i) the promissory notes issued under the Credit Agreement and any renewal or increase thereof, or our other indebtedness that was disclosed in our Financial Statements or on a schedule to the Credit Agreement; or (ii) taxes, assessments or other government charges which are not yet due or are being contested in good faith by appropriate action promptly initiated and diligently conducted, if such reserve as shall be required by generally accepted accounting principles shall have been made therefor and levy and execution thereon have been stayed and continue to be stayed; or (iii) indebtedness (other than in connection with a loan or lending transaction) incurred in the ordinary course of business, including, but not limited to indebtedness for drilling, completing, leasing and reworking oil and gas wells or the treatment, distribution, transportation of sale of production therefrom; (iv) any renewals or extensions of (but not increases in) any of the foregoing; or (v) indebtedness to the other borrowers under the Credit Agreement. 26 (g) We will not be permitted to declare, pay or make, whether in cash or property, or set aside or apply any money or assets to pay or make any dividend or distribution during any fiscal year. (h) We will not be permitted to make or permit to remain outstanding any loans or advances made by us to or in any person or entity, except that the foregoing restriction shall not apply to: (i) loans or advances to any person, the material details of which have been set forth in our Financial Statements that were furnished to the banks; or (ii) advances made in the ordinary course of our oil and gas business; or (iii) loans or advances among the borrowers under the Credit Agreement. (i) We will not be permitted to discount or sell with recourse, or sell for less than the greater of the face or market value thereof, any of our notes receivable or accounts receivable. (j) We cannot allow any material change to be made in the character of our business as carried on as of May 31, 2002. (k) We will not be permitted to enter into any transaction with any of our affiliates, except transactions upon terms that are no less favorable to us than would be obtained in a transaction negotiated at arm's length with an unrelated third party. (l) We will not be permitted to enter into any transaction providing (i) for the hedging, forward sale, swap or any derivative thereof of crude oil or natural gas or other commodities, or (ii) for a swap, collar, floor, cap, option, corridor, or other contract which is intended to reduce or eliminate the risk of fluctuation in interest rates, as such terms are referred to in the capital markets, except the foregoing prohibitions shall not apply to (x) transactions consented to in writing by a majority of the lending banks which are on terms acceptable to them, or (y) pre-approved contracts (i) to hedge, forward sell or swap crude oil or natural gas or otherwise sell up to 75% of our monthly production forecast for all of our (A) proved and producing oil properties for the period covered by the proposed hedging transaction, and (B) proved and producing gas properties for the period covered by the proposed hedging transaction, (ii) with a term of eighteen (18) months or less, (iii) with "strike prices" per barrel or MCF as applicable greater than the Bank of Oklahoma's forecasted price in the most recent engineering evaluation, and (iv) with counter-parties approved by the Bank of Oklahoma. (m) We will not be permitted to make any investments in any person or entity, except such restriction shall not apply to: (i) investments and direct obligations of the United States of America or any agency thereof; (ii) investments in certificates of deposit issued by the lending banks or certificates of deposit with maturities 27 of less than one year, issued by other commercial banks in the United States having capital and surplus in excess of $500,000,000 and which have a senior unsecured debt rating of A+ by Standard & Poor's Ratings Group or A1 by Moody's Investors Service, Inc.; or (iii) investments in insured money market funds or such investment with maturities of less than ninety (90) days at other commercial banks having capital and surplus in excess of $500,000,000 and which have a senior unsecured debt rating of A+ by Standard & Poor's Ratings Group or A1 by Moody's Investors Service, Inc.; or (iv) investments in oil and gas properties; or (v) investments in other borrowers under the Credit Agreement; provided such investments may not require a transfer of assets other than cash. (n) We cannot permit any amendment to, or any alteration of, our Articles of Incorporation or Bylaws, which amendment or alteration could reasonably be expected to have a material adverse effect under the Credit Agreement. (o) We will not be permitted to enter into or agree to enter into, any rental or lease agreement resulting or which would result in aggregate rental or lease payments by us exceeding $100,000.00 in the aggregate in any fiscal year under all rental or lease agreements under which we are a lessee of the property or assets covered thereby; provided, however, that the foregoing restriction shall not apply to oil, gas and mineral leases or permits or similar agreements entered into in the ordinary course of business or orders of any governmental authority adjudicating the rights or pooling the interests of the owners of oil and gas properties or lease agreements in effect as of May 31, 2002. (p) We may not allow our accounts payable to become in excess of 120 days past due from the date of invoice, except such accounts payable as are being contested by us in good faith. (q) We may not issue any preferred stock without the consent of a majority of the lending banks. (r) We cannot permit or suffer to exist any change in a majority of our current board of director membership or a change or amendment to our current corporate structure except as set forth in the Credit Agreement. (s) Except as may be otherwise permitted the Credit Agreement, we may not directly or indirectly make any payments upon any debt other than regularly scheduled installments of principal and interest. (t) We may not repurchase or set aside any funds to repurchase any stock or partnership interests. 28 (u) We cannot make, permit or suffer to exist a change in management. (v) We may not amend, modify or otherwise alter our loan agreement and related documents with Kaiser-Francis Oil Company dated December 1, 1999 without the lending banks' prior written consent which such consent shall not be unreasonably withheld. Any one or more of the following events are considered an event of default under the Credit Agreement: (a) If we should fail to pay when due or declared due the principal of, and/or the interest on, the notes, or any fee or any of our other indebtedness incurred under our Credit Agreement or any related loan document and such failure to pay is not cured within three days after written notice of such failure is sent to us; or (b) If any representation or warranty made by us under the Credit Agreement, or in any certificate or statement furnished or made to the banks pursuant thereto or in connection therewith, or in connection with any document furnished thereunder, shall prove to be untrue in any material respect as of the date on which such representation or warranty is made (or deemed made), or any representation, statement (including financial statements), certificate, report or other data furnished or to be furnished or made by us under any loan document proves to have been untrue in any material respect, as of the date as of which the facts therein set forth were stated or certified; or (c) If default is made in the due observance or performance of any of our covenants or agreements contained in the Credit Agreement or other loan documents and such default continues for more than thirty days after notice is received by us; or (d) If default is made in the due observance or performance of our negative covenants listed above; or (e) If default is made in respect of any obligation for borrowed money in excess of $100,000.00, other than the promissory notes issued under the Credit Agreement, for which we are liable (directly, by assumption, as guarantor or otherwise), or any obligations secured by any mortgage, pledge or other security interest, lien, charge or encumbrance with respect thereto, on any of our assets or property in respect of any agreement relating to any such obligations unless we are not liable for same (i.e., unless remedies or recourse for failure to pay such obligations is limited to foreclosure of the collateral security therefor), and if such default shall continue for more than thirty days after notice is received by us; or (f) If we commence a voluntary case or other proceeding seeking liquidation, reorganization or other relief with respect to us or our debts under any bankruptcy, insolvency or other similar law now or hereafter in effect or seeking an appointment of a trustee, receiver, liquidator, custodian or other similar official of us or any substantial part of our property, or if we consent to any such relief or to the appointment of or taking possession by any such official in an involuntary case or other proceeding commenced against us, or if we make a general assignment for the benefit of our creditors, or 29 fail generally to pay our debts as they become due, or take any corporate action authorizing the foregoing; or (g) If an involuntary case or other proceeding is commenced against us seeking liquidation, reorganization or other relief with respect to us or our debts under any bankruptcy, insolvency or similar law now or hereafter in effect or seeking the appointment of a trustee, receiver, liquidator, custodian or other similar official of us or any substantial part of our property, and such involuntary case or other proceeding should remain undismissed and unstayed for a period of sixty (60) days; or an order for relief shall be entered against us under the federal bankruptcy laws; or (h) A final judgment or judgments or order for the payment of money in excess of $100,000 during any one (1) fiscal year in the aggregate shall be rendered against us and such judgments or orders shall continue unsatisfied and unstayed for a period of thirty days; or (i) In the event our total outstanding indebtedness should at any time exceed the borrowing base established for the revolving notes, and if we should fail to comply with the provisions of the Credit Agreement that require us to immediately prepay an amount sufficient to cause our total outstanding indebtedness to not exceed our borrowing base; or (j) A change of management occurs; or (k) Any security instrument for the indebtedness under the Credit Agreement for any reason does not, or ceases to, create a valid and perfected first-priority lien against all of the collateral purportedly covered thereby and such occurrence would have a material adverse effect. Upon occurrence of any event of default specified above and after the expiration of any cure period provided in the Credit Agreement, the entire principal amount due under the notes and all interest then accrued thereon, and any other liabilities that we might have to the lending banks under the loan documents, will become immediately due and payable all without notice and without presentment, demand, protest, notice of protest or dishonor or any other notice of default of any kind. In any other event of default, the Bank of Oklahoma, upon request of a majority of the lending banks, may by notice to us declare the principal of, and all interest then accrued on, the notes and any other liabilities hereunder to be forthwith due and payable, whereupon the same shall forthwith become due and payable without presentment, demand, protest, notice of intent to accelerate, notice of acceleration or other notice of any kind. Upon the occurrence and during the continuance of any event of default beyond any cure period provided in the Credit Agreement, the lending banks are authorized at any time and from time to time, without notice to us, to set-off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by any of the banks to or for our credit or our account against any and all of our indebtedness under the notes and related loan documents, irrespective of whether or not the banks shall have made any demand under the loan documents and although such indebtedness may be unmatured. Any amount set-off by any of the banks is to be applied against the indebtedness owed by us to the banks. The banks have agreed to promptly notify us after any such 30 set-off and application, provided that the failure to give such notice shall not affect the validity of such set-off and application. These rights are in addition to other rights and remedies (including, without limitation, other rights of set-off) which the banks might have. Upon the occurrence of and during the continuance of any event of default, we will not be permitted to service our obligations under our loan agreement with Kaiser-Francis Oil Company from proceeds of the collateral securing the loan under our Credit Agreement including, but not limited to, oil and gas properties or any related operating fees. The foregoing does not purport to be a complete summary of the Credit Agreement and other loan documents. Complete copies of these documents are filed as exhibits to our Report on Form 8-K dated January 15, 2002. DESCRIPTION OF PROPERTY (a) Office Facilities. ----------------- Our offices are located at 475 Seventeenth Street, Suite 1400, Denver, Colorado 80202. We lease approximately 6,700 square feet of office space for approximately $11,500 per month and the lease will expire in September 2008. (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 registration statement. 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. Castle Properties - Proved Oil and Gas Reserves ----------------------------------------------- The following is a summary of Castle's oil and gas reserves as of September 30, 2001. All estimates of reserves are based upon engineering evaluations prepared by Castle's independent petroleum reservoir engineers, Huntley & Huntley and Ralph E. Davis Associates, Inc., in accordance with the requirements of the Securities and Exchange Commission and are based upon September 30, 2001 spot prices. Such estimates include only proved reserves. Castle reports its reserves annually to the Department of Energy. Castle's estimated reserves as of September 30, 2001, the date of last official appraisal of properties, were as follows: 31 Net MCF (1) of gas: Proved developed............................................. 26,480,000 Proved undeveloped........................................... 4,212,000 ---------- Total........................................................ 30,692,000 ========== Net barrels of oil: Proved developed............................................. 1,890,000 Proved undeveloped........................................... 1,470,000 ---------- Total........................................................ 3,360,000 ========== ----------------- (1) Thousand cubic feet Castle Oil and Gas Production ----------------------------- The following table summarizes the net quantities of oil and gas production of Castle for each of the three fiscal years in the period ended September 30, 2001, including production from acquired properties since the date of acquisition. Fiscal Year Ended September 30, 2001 2000 1999 ---- ---- ---- Oil -- Bbls (barrels)................. 262,000 279,000 124,000 Gas -- MCF............................ 3,083,000 3,547,000 1,971,000 Average Sales Price and Production Cost Per Unit ------------------------------------------------ The following table sets forth the average sales price per barrel of oil and MCF of gas produced by Castle, including hedging adjustments, and the average production cost (lifting cost) per equivalent unit of production for the periods indicated. Production costs include applicable operating costs and maintenance costs of support equipment and facilities, labor, repairs, severance taxes, property taxes, insurance, materials, supplies and fuel consumed in operating the wells and related equipment and facilities. Fiscal Year Ended September 30, 2001 2000 1999 ---- ---- ---- Average Sales Price per Barrel of Oil.......... $27.39 $27.94 $18.36 Average Sales Price per MCF of Gas............. $ 4.53 $ 2.87 $ 2.25 Average Production Cost per Equivalent MCF(1).. $ 1.59 $ 1.19 $ .70 -------------- (1) For purposes of equivalency of units, a barrel of oil is assumed to be equal to six MCF of gas, based upon relative energy content. 32 No production was hedged in fiscal 2001. The average sales price per barrel of crude oil decreased $4.64 per barrel for the year ended September 30, 2000 and increased $.11 per barrel for the year ended September 30, 1999 as a result of hedging. The average sales price per mcf (thousand cubic feet) of natural gas decreased $.07 for each of the years ended September 30, 2000 and 1999 as a result of hedging. Oil and gas sales were not hedged after July 2000. Castle Productive Wells and Acreage ----------------------------------- The following table presents the oil and gas properties in which Castle held an interest as of September 30, 2001. The wells and acreage owned by Castle and its subsidiaries are located primarily in Alabama, California, Illinois, Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Pennsylvania, Texas and Wyoming. As of September 30, 2001 Gross(2) Net (3) -------- ------- Productive Wells:(1) Gas Wells........................................... 521 203 Oil Wells........................................... 103 49 Acreage: Developed Acreage................................... 129,517 31,351 Undeveloped Acreage................................. 85,686 29,678 ---------------- (1) A "productive well" is a producing well or a well capable of production. Fifty-nine wells are dual wells producing oil and gas. Such wells are classified according to the dominant mineral being produced. (2) A gross well or acre is a well or acre in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. (3) A net well or acre is deemed to exist when the sum of fractional working interests owned in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres. Our Principal Properties as of June 30, 2001. -------------------------------------------- The following is a brief description of our principal properties as of June 30, 2001, which was prior to our acquisition of the Castle properties: 33 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 March 31, 2002, 20 wells had been drilled of which ten are now producing and one is awaiting completion. 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. 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. 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 us 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 34 properties, including the plugging and abandonment obligation, were returned to us. We 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. 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 us 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 five injection wells. Current production net to the interests acquired by us is approximately 300 barrels of oil equivalent per day as of September 30, 2001. During the quarter ended March 31, 2002, we sold all of our interests in the North Dakota properties. 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 drilling program. We drilled four wells on the property, none of which was successful. We are currently evaluating the geologic information to determine whether to go forward with more drilling or to attempt to sell the acreage position. 35 Offshore: -------- Offshore Federal Waters: Santa Barbara, California Area ------------------------------------------------------- Unproved Undeveloped Properties: ------------------------------- 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"). Although significant quantities of oil and gas have been produced and sold from drilling conducted on POCS leases between 1966 and 1989, we do not own any interest in any offshore California production except for our small interest in the Point Arguello Unit discussed below, and there is 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 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 36 Army Corps of Engineers, also have oversight of 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. 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 37 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 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 38 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 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 39 Arguello Unit upon which the Rocky Point leases would be drilled from existing Point Arguello platforms with extended reach drilling technology. The approximate distances required to drain the Rocky Point leases range from 2,276 feet to 13,999 feet at proposed total vertical depths ranging from 6,620 feet to 7,360 feet. 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 Norton ruling. The United States government has filed a notice of its intent to appeal the court's order in the Norton case. On January 9, 2002, we and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of forty undeveloped federal leases, some of which are part of our Offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their Offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the 40 judicial determination in the California v. Norton case that a 1990 amendment to the Coastal Zone Management Act required the Government to make a consistency determination prior to granting lease suspension requests in 1999 constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations. The forty undeveloped leases are located in the Offshore Santa Maria Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the Santa Barbara Channel off Santa Barbara and Ventura counties. None of these leases is currently impaired, but in the event that there is some future adverse ruling by the California Coastal Commission under the Coastal Zone Management Act and we decide not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear our appeal of any such ruling or ultimately makes a determination adverse to us, it is likely that some or all of these leases would become impaired and written off at that time. In addition, it should be noted that our pending litigation against the United States is predicated on the ruling of the lower court in California v. Norton. The United States has appealed the decision of the lower court to the 9th Circuit Court of Appeals. In the event that the United States is not successful in its appeal(s) of the lower court's decision in the Norton case and the pending litigation with us is not settled, it would be necessary for us to reevaluate whether the leases should be considered impaired at that time. As the ruling in the Norton case currently stands, the United States has been ordered to make a consistency determination under the Coastal Zone Management Act, but the leases are still valid. If through the appellate process the leases are found not to be valid for some reason, or if the United States is finally ordered to make a consistency determination and either does not do so or finds that development is inconsistent with the Coastal Zone Management Act, it would appear that the leases would become impaired even though we would undoubtedly proceed with our litigation. It is also possible that other events could occur during the appellate process that would cause the leases to become impaired, and we will continuously evaluate those factors as they occur. The suit seeks compensation for the lease bonuses and rentals paid to the Federal Government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. Our claim for lease bonuses and rentals paid by us and our predecessors is in excess of $152,000,000. In addition, our claim for exploration costs and related expenses will also be substantial. 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 41 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 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 42 and completion programs; a detailed description of new or unusual technology 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. 43 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 44 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 45 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 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. Our 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. 46 The Point Sal field is located in the Offshore Santa Maria Basin approximately six miles seaward of the coastline. 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. Any processed oil would then be transported out of Santa Barbara County in either the All American Pipeline or the Tosco-Unocal Pipeline. Offshore pipeline distance is approximately six to eight miles depending on the final choice of the point of landfall. Our 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 in the Lion Rock Unit and a 24.21692% working interest 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. 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, and would be transported out of Santa Barbara County in the All American Pipeline or the Tosco-Unocal Pipeline. Offshore pipeline distance will be eight to ten miles, depending on the point of landfall. Our 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 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 average gravity of 10.6E API. The two 47 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. 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. 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. Our 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 us 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. 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 48 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 Norton case. See "Management's Discussion and Analysis or Plan of Operation-Offshore Undeveloped Properties". On January 9, 2002, we filed a lawsuit against the U.S. government along with several other companies alleging that the government breached the terms of some of our undeveloped, offshore California properties. See "Legal Proceedings." 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 us (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 continue to drill developmental wells on the Point Arguello Unit during fiscal 2003. 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. 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 49 acres in the Pavlodar region of Eastern Kazakhstan. A work plan prepared by us was approved by the Kazakhstan government which established minimum work and spending commitments. The acquisition is a high risk, frontier exploration project. We do 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 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 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. 50 Undeveloped Kazakhstan Property ------------------------------- We do 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 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. During the quarter ended March 31, 2002 we impaired our Eland properties in anticipation of the sale of the properties. No impairment for 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:

Nine Months Ended Year Ended March 31, June 30, ----------------------------------------- --------------------------------------------------- 2002 2001 2001 2000 1999 ------------------- ------------------- ------------------- ------------------- ------- Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore Onshore ------- -------- ------- -------- ------- -------- ------- -------- ------- Average sales price: Net of forward contract sales Oil (per barrel) $21.70 $13.81 $28.30 $18.17 $27.10 $18.49 $25.95 $11.54 $10.24 Natural Gas (per Mcf) $ 2.41 $ - $ 6.54 $ - $ 6.27 - $ 2.62 - $ 1.97 Gross of forward contract sales Oil (per barrel) $21.84 $13.81 $28.30 $23.23 $27.30 $22.53 $25.95 $21.14 $10.24 Natural Gas (per Mcf) $ 2.41 $ - $ 6.54 $ - $ 6.27 - $ 2.62 - $ 1.97 Production costs (per Bbl equivalent) $ 4.12 $10.17 $ 4.37 $12.72 $ 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 51 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 Enron North America Corp. ("Enron"). After Enron filed bankruptcy, we terminated our fixed price contract. We expect to have a claim in bankruptcy, but do not expect to recover these claims. (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. 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/types of natural gas. (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: 52 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: 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 we had only a royalty interest. 53 (g) Present Drilling Activity ------------------------- We plan to participate in the drilling of between two and four new wells before the end of calendar 2002. LEGAL PROCEEDINGS On January 9, 2002, we and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of forty undeveloped federal leases, some of which are part of our Offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their Offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case that a 1990 amendment to the Coastal Zone Management Act required the Government to make a consistency determination prior to granting lease suspension requests in 1999 constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations. The forty undeveloped leases are located in the Offshore Santa Maria Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the Santa Barbara Channel off Santa Barbara and Ventura counties. None of these leases is currently impaired, but in the event that there is some future adverse ruling by the California Coastal Commission under the Coastal Zone Management Act and we decide not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear our appeal of any such ruling or ultimately makes a determination adverse to us, it is likely that some or all of these leases would become impaired and written off at that time. In addition, it should be noted that our pending litigation against the United States is predicated on the ruling of the lower court in California v. Norton. The United States has appealed the decision of the lower court to the 9th Circuit Court of Appeals. In the event that the United States is not successful in its appeal(s) of the lower court's decision in the Norton case and the pending litigation with us is not settled, it would be necessary for us to reevaluate whether the leases should be considered impaired at that time. As the ruling in the Norton case currently stands, the United States has been ordered to make a consistency determination under the Coastal Zone Management Act, but the leases are still valid. If through the appellate process the leases are found not to be valid for some reason, or if the United States is finally ordered to make a consistency determination and either does not do so or finds that development is inconsistent with the Coastal Zone Management Act, it would appear that the leases would become impaired even 54 though we would undoubtedly proceed with our litigation. It is also possible that other events could occur during the appellate process that would cause the leases to become impaired, and we will continuously evaluate those factors as they occur. The suit seeks compensation for the lease bonuses and rentals paid to the Federal Government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. Our claim for lease bonuses and rentals paid by us and our predecessors is in excess of $152,000,000. In addition, our claim for exploration costs and related expenses will also be substantial. COMMON EQUITY SECURITIES Market Information ------------------ Our 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. 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 December 31, 2001 3.94 2.38 March 31, 2002 4.53 3.35 June 30, 2002 4.73 3.52 On August 6, 2002, the reported closing price for our common stock on the Nasdaq Small-Cap Market was $3.30. Approximate Number of Holders of Common Stock. --------------------------------------------- The number of holders of record of our common stock at June 30, 2002 was approximately 1,000 which does not include an estimated 2,600 additional holders whose stock is held in "street name." 55 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.

Nine Months Ended March 31, Fiscal Years Ended June 30, ------------------------- -------------------------------------------------------------- 2002 2001 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- ---- ---- Total Revenues $ 5,290,000 9,509,000 12,877,000 3,576,000 1,695,000 2,164,000 1,812,000 Income/(Loss) from Operations $(2,559,000) 1,986,000 1,678,000 (2,080,000) (2,905,000) (1,010,000) (2,457,000) Income/(Loss) Per Share $ (.30) .09 .03 (0.46) (0.51) (0.18) (0.49) Total Assets $31,830,000 32,099,000 29,832,000 21,057,000 11,377,000 10,350,000 10,438,000 Total Liabilities $10,791,000 14,065,000 11,551,000 10,094,000 1,531,000 845,000 1,268,000 Stockholders' Equity $21,039,200 18,034,000 18,281,000 10,963,000 9,846,000 9,505,000 9,171,000 Total Long Term Debt $ 8,120,000 12,439,000 9,434,000 8,245,000 1,000,000 -0- -0-

MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION. Liquidity and Capital Resources ------------------------------- General ------- At March 31, 2002, we had a working capital deficit of $3,466,000 compared to a working capital deficit of $1,560,000 at June 30, 2001. This increase in working capital deficit is primarily due to net losses incurred resulting from 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 56 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 (with the exception of 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 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. Burdette A. Ogle, a consultant to us for our offshore California properties, has informed us that he believes the end-date of the 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. During this period the leases will be held by 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 57 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 were 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 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 which began 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 58 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 our 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 our 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 within the next year with the drilling of a delineation well at an estimated cost of approximately $13,000,000. Our share is estimated at $650,000. 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 our 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 59 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 our 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 our 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 appealed 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 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 a revised Development and Prroduction Plan since the MMS had temporarily stopped work on 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 60 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. Based on discussions with the MMS and operators of the properties, we currently believe that the MMS, in cooperation with the property interest owners, will provide the State of California with a consistency determination under the Coastal Zone Management Act that will allow exploration and development plans to be prepared. 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. We have also commenced litigation against the U.S. Government seeking damages in the event that we are not allowed to proceed. 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 March 31, 2002 and June 30, 2001 and that no impairment in the carrying value has occurred. Should the required regulatory approvals 61 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. See note 3 to the financial statements. 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 us (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. There continues to be ongoing drilling and workover activity and we anticipate that we will participate in the drilling of at least four new wells in fiscal 2003. 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. 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 our 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 62 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 $6.0 million for the year ended June 30, 2003. 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. Onshore Proved Undeveloped Properties ------------------------------------- The amount of our onshore proved undeveloped reserves appears to have significantly decreased when compared to our previous fiscal year. This change is primarily due to logistical constraints caused by a change in independent engineering firms between the two fiscal years. Our new engineering firm did not complete its review of all of our onshore proved undeveloped reserves before the issuance of our fiscal 2001 report. As a result, some of the proved undeveloped reserves that were present in our fiscal 2000 report are not present in our fiscal 2001 report even though we still own the properties and are continuing with development efforts. 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. We 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 us 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 our common stock at various exercise prices ranging from $3.50 to $5.00 per share to the 63 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 expenses. 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. 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. 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 64 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. 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 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, 65 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 we 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 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 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. 66 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. On February 19, 2002, we completed the acquisition of Piper Petroleum Company ("Piper"), a privately owned oil and gas company headquartered in Fort Worth, Texas. We issued 1,374,240 shares of restricted common stock for 100% of the shares of Piper. The 1,374,240 shares of restricted common stock were valued at approximately $5,244,000 based on the five-day average closing price surrounding the announcement of the merger. In addition, we issued 51,000 shares for the cancellation of certain debt of Piper. On May 31, 2002, we issued 9,566,000 shares of Common Stock to Castle Energy Corporation as part of the purchase price for our purchase of all of Castle's domestic oil and gas properties. We are entitled to repurchase up to 3,188,667 of our shares from Castle for $4.50 per share for a period of one year after closing. 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 our 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, we are not obligated to sell to Swartz all of the common stock referenced in the agreement nor do we intend to sell shares to the entity unless it is beneficial to us. 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. We have 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. 67 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 $400,000, $1,480,000, $1,378,000 and $356,000 during the nine months ended March 31, 2002 and years ended June 30, 2001 2000 and 1999, respectively. 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 68 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. On February 1, 2002, we sold interests in 20 producing wells, 5 injection wells and acreage located in the Eland and Stadium fields in Stark County, North Dakota for $2,750,000 to Sovereign Holdings, LLC, an unrelated entity. As a result of the sale, the Company recognized at December 31, 2001 an impairment of $102,000. 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 through February 28, 2002. 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 through February 28, 2002. Results of Operations --------------------- Three and Nine Months ended March 31, 2002 compared to Three and Nine Months ended March 31, 2001 ------------------------------------------------------ Income (loss). We reported a net loss for the three and nine months ended March 31, 2002 of $1,587,000 and $3,493,000 compared to net income of $331,000 and $893,000 for the three and nine months ended March 31, 2001. The net loss and net income for the three and nine months ended March 31, 2002 and 2001 were affected by numerous items, described in detail below. Revenue. Total revenues for the three and nine months ended March 31, 2002 were $1,058,000 and $5,290,000 compared to $3,702,000 and $9,509,000 for the three and nine months ended March 31, 2001. Oil and gas sales for the three and nine months ended March 31, 2002 were $1,138,000 and $5,317,000 compared to $3,661,000 and $9,352,000 for the three and nine months ended March 31, 2001. The decrease in oil and gas revenue is primarily attributed to the decrease in oil and gas prices and the sale of the Eland properties offset by additional production relating to certain acquisitions during fiscal 2001. Production volumes and average prices received for the three months ended March 31, 2002 and 2001 are as follows: 69 Three Months Ended March 31, 2002 2001 Onshore Offshore Onshore Offshore --------- -------- -------- -------- Production: Oil (barrels) 5,180 62,496 26,946 84,566 Gas (Mcf) 153,979 - 157,863 - Average Price: Net of forward contract sales Oil (per barrel) $17.26 $13.24 $29.04 $19.70 Gas (per Mcf) $ 1.43 - $ 7.62 - Gross of forward contract sales* Oil (per barrel) $17.26 $13.24 $29.04 $19.70 Gas (per Mcf) $ 1.43 - $ 7.62 - Production volumes and average prices received for the nine months ended March 31, 2002 and 2001 are as follows: Nine Months Ended March 31, 2002 2001 Onshore Offshore Onshore Offshore -------- -------- -------- -------- Production: Oil (barrels) 61,101 206,734 81,530 245,495 Gas (Mcf) 471,299 - 393,968 - Average Price: Net of forward contract sales Oil (per barrel) $21.70 $13.81 $28.30 $18.17 Gas (per Mcf) $ 2.41 - $ 6.54 - Gross of forward contract sales* Oil (per barrel) $21.84 $13.81 $28.30 $23.23 Gas (per Mcf) $ 2.41 - $ 6.54 - *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 received the benefit of 6,000 barrels per month from March 1, 2001 through October 31, 2001 at $27.31 per barrel under fixed price contracts with Enron North American Corp ("Enron"). After Enron filed bankruptcy, we terminated our fixed price contract. We expect to have a claim in bankruptcy, but do not expect to recover these claims. Other Revenue. Other revenue in fiscal 2001 includes amounts recognized from production of gas previously deferred pending determination of our interests in the properties. Lease Operating Expenses. Lease operating expenses were $865,000 and $2,679,000 for the three and nine months ended March 31, 2002 compared to $1,520,000 and $3,783,000 for the same period in 2001. On a barrel equivalent basis, lease operating expenses were $4.06 and $4.12 for the three and nine months ended March 31, 2002 compared to $3.23 and $4.37 for the same periods 70 in 2001 for onshore properties. On a barrel equivalent basis, lease operating expenses were $11.82 and $10.17 for the three and nine months ended March 31, 2002 compared to $15.89 and $12.72 for the same periods in 2001 for the offshore properties. The decrease in lease operating expense is attributed to lower offshore operating costs after the completion of an extensive workover program during fiscal 2001 and the sale of the Eland properties. Depreciation and Depletion Expense. Depreciation and depletion expense for the three and nine months ended March 31, 2002 was $587,000 and $2,249,000 compared to $600,000 and $1,556,000 for the same period in 2001. On a barrel equivalent basis, the depletion rates were $9.34 and $10.08 for the three and nine months ended March 31, 2002 and $7.80 and $6.49 for the same periods in 2001 for onshore properties. On a barrel equivalent basis, the depletion rates were $4.05 and $4.77 for the three and nine months ended March 31, 2002 compared to $2.44 and $2.17 for the same periods in 2001 for offshore properties. The decrease in depletion expense is attributed to the sale of the Eland properties. Exploration Expenses. We incurred exploration expenses of $16,000 and $125,000 for the three and nine months ended March 31, 2002 compared to $26,000 and $49,000 for the same period in 2001. Exploration expense increased from last year as we expanded our activity in South Dakota and offshore California. Dry Hole Costs. We incurred dry hole costs of $15,000 and $396,000 for the three and nine months ended March 31, 2002 relating to five dry holes. Abandoned and Impaired Properties. We impaired $60,000 relating to undeveloped properties in onshore California and $102,000 relating to our Eland and Stadium fields in Stark County, North Dakota, which were sold on February 1, 2002 during the quarter ended December 31, 2001. Professional Fees. Professional fees for the three and nine months ended March 31, 2002 were $284,000 and $954,000 compared to $348,000 and $815,000 for the same period in 2001. The increase during the nine months in professional fees was primarily attributed legal fees for representation in negotiations and discussions with various state and federal governmental agencies relating to our undeveloped offshore California leases. General and Administrative Expenses. General and administrative expenses for the three and nine months ended March 31, 2002 were $593,000 and $954,000 compared to $268,000 and $896,000 for the same periods in 2001. The increase in general and administrative expenses was attributable to the hiring of additional employees, moving expenses and bonuses. Stock Option Expense. Stock option expense has been recorded for the three and nine months ended March 31, 2002 of $20,000 and $53,000 compared to $45,000 and $334,000 for the same period in 2001, for options granted to non-employee directors at option prices below the market price at the date of grant. Other income. Other income during the nine months ended March 31, 2001 includes the sale of our unsecured claim in bankruptcy against our former parent, Underwriters Financial Group in the amount of $350,000. 71 Interest and Financing Costs. Interest and financing costs for the three and nine months ended March 31, 2002 were $274,000 and $947,000 compared to $504,000 and $1,495,000 for the same period in 2001. The decrease in interest expense can be attributed to lower interest rates established through traditional financing and the reduction of debt from the proceeds from the sale of the Eland properties. 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 was also impacted by the increase in oil and gas prices. If we had not 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 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 - 72 *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 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 our undeveloped offshore California leases. General and Administrative Expenses. General and administrative expenses for the year ended June 30, 2001 were $1,470,000 compared to $1,258,000 for 73 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. 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 was also impacted by the increase in oil and gas prices. If we had 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. 74 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 is a result of these forward sales contracts. 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 costs 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 75 $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 Commission 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 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 ------------------------------------------------------------------- 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 includ more disposal transactions. We are currently assessing the impact SFAS No. 144 will have on our financial condition and results of operations. 76 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. Name Age Positions Period of Service ---- --- --------- ----------------- Aleron H. Larson, Jr. 57 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 58 Director September 1996 to Present James P. Wallace 73 Director November 2001 to Present Kevin K. Nanke 37 Treasurer and Chief December 1999 Financial Officer to Present Joseph L. Castle, II 70 Director June 5, 2002 to Present Russell S. Lewis 47 Director June 5, 2002 to Present John P. Keller 63 Director June 5, 2002 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 57, 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, Secretary and Director of Amber Resources Company ("Amber"), a public oil and gas company which is our majority-owned subsidiary. 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 77 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. Subsequent to a change of control, Mr. Parker resigned from all positions with UFG effective March 31, 1993. Mr. Parker also serves as President, Chief Executive 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 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 58, 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 73, 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 National Market System. He received a B.S. Degree in Business Administration from the University of Southern California in 1951. KEVIN K. NANKE, age 37, Treasurer and 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 us, he was employed by KPMG LLP. He is a member of the Colorado Society of CPA's and the Council of Petroleum Accounting Society. 78 JOSEPH L. CASTLE II, age 70, has been a Director of Castle Energy Corporation ("Castle") since 1985. Mr. Castle is the Chairman of the Board of Directors and Chief Executive Officer of Castle, having served as Chairman from December 1985 through May 1992 and since December 20, 1993. Mr. Castle also served as President of Castle from December 1985 through December 20, 1993, when he reassumed his position as Chairman of the Board. Previously, Mr. Castle was Vice President of Philadelphia National Bank, a corporate finance partner at Butcher and Sherrerd, an investment banking firm, and a Trustee of The Reading Company. Mr. Castle has worked in the energy industry in various capacities since 1971. Mr. Castle is a director of Comcast Corporation and Charming Shoppes, Inc. Since May of 2000, Mr. Castle has served as the Chairman of the Board of Trustees of the Diet Drug Products Liability ("Phen-Fen") Settlement Trust. RUSSELL S. LEWIS, age 47, has been a director of Castle since April 2000. From 1994 to 1999, Mr. Lewis was the Chief Executive Officer of TransCore, Inc., a company which sells and installs electronic toll collection systems. Since 1999, Mr. Lewis has been the owner and President of Lewis Capital Group, a company investing in and providing consulting services to growth-oriented companies. Since March 2000, Mr. Lewis has also been Senior Vice President of Corporate Development at VeriSign, Inc. In February of 2002, Mr. Lewis jointed VeriSign full time as Executive Vice President and General Manager of VeriSign's Global Registry Services Group, which maintains the authoritative databases for all ".com," ".net" and ".org" domain names in the internet. JOHN P. KELLER, age 62, has been a director of Castle since April 1997. Since 1972, Mr. Keller has served as the President of Keller Group, Inc., a privately-held corporation with subsidiaries in Ohio, Pennsylvania and Virginia. In 1993 and 1994, Mr. Keller also served as the Chairman of the American Appraisal Associates, an appraisal company. Mr. Keller is also a director of A.M. Castle & Co. and Old Kent Financial Corporation. There is no family relationship among or between any of our officers and/or directors. Effective December 21, 2001, 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 2001 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 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. 79 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:

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. 80 (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, 2001. 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, 2001. 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. (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

81 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

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 elected to receive his compensation for the portion of the calendar year 2001 served (January 1, 2001 through November 15, 2001) in the form of options issued under our 2001 Incentive Plan. Incentive Compensation Plan --------------------------- On October 25, 2001, the Board of Directors adopted the 2002 Incentive Plan ("2002 Plan"), which was ratified by our shareholders at the annual meeting held on May 30, 2002. The maximum number of shares of Common Stock that may be issued under the 2002 Plan is 2,000,000 shares. 82 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 $180,000 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. 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 June 30, 2002: Name and Address Amount and Nature of of Beneficial Owner of Beneficial Percent Title of Class(1) Owner Ownership of Class(2) Common stock Aleron H. Larson, Jr. 1,404,801 shares(3) 5.85% (includes options 475 17th St., #1400 for common stock) Denver, CO 80202 83 Common stock Roger A. Parker 1,352,101 shares(4) 5.72% (includes options 475 17th St., #1400 for common stock) Denver, CO 80202 Common stock Castle Energy Corporation 9,948,289 shares 43.98% Suite 250 One Radnor Corporate Center Radnor, PA 19087 ------------------------------ (1) We have an authorized capital of 300,000,000 shares of $.01 par value Common Stock of which 22,617,959 shares were issued and outstanding as of June 30, 2002. 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 June 30, 2002 of 22,617,959. 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 8,000 shares owned by Mr. Larson directly, 2,211 shares owned by Mr. Larson's wife and 4,000 shares owned by his children; and 365,590 options to purchase 365,390 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 327,101 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. (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. 1,404,801 shares(3) 5.85% Common Stock Roger A. Parker 1,352,101 shares(4) 5.72% Common Stock Kevin K. Nanke 584,047 shares(5) 2.52% Common stock Jerrie F. Eckelberger 40,725 shares(6) .18% 84 Common stock James B. Wallace 32,500 shares(7) .14% Common stock Joseph L. Castle II 9,948,289 shares(8) 43.98% Common stock Russell S. Lewis 9,948,289 shares(8) 43.98% Common stock John P. Keller 9,948,289 shares(8) 43.98% Common stock Officers and Directors 13,362,463 shares(9) 52.12% as a Group (8 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) Consists of 25,000 shares of Common Stock owned directly by Mr. Nanke; options to purchase 34,047 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. (6) Includes options to purchase 725 shares of Common Stock at $2.98 per share until December 31, 2006; options to purchase 20,000 shares of Common Stock at $1.95 until September 10, 2011 and options to purchase 20,000 shares of Common Stock at $2.02 until February 5, 2012. (7) Includes 30,000 shares of Common Stock and options to purchase 2,500 shares at $2.02 per share until February 5, 2002. (8) Shares indicated are owned by Castle Energy Corporation which is deemed to be controlled by the person indicated. (9) 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 85 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 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 has 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 86 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 President and Chairman each the right to participate, on the same basis as Delta, 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 actual cost thereof. In addition, our Chief Financial Officer is given the right to participate, on the same basis as Delta, in up to a 2.5% working interest in these same types of drilling activities and is required to pay the actual 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 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 87 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 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 88 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, 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 89 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 22,617,959 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 29%. 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 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." 90 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 received shareholder approval to issue stock to Swartz under the Investment Agreement at our annual meeting held on May 30, 2002. 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 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: 91 - 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 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; - 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; and 92 - 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 - 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 93 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 - 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 94 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 applies 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 - 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." 95 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 table below includes information regarding ownership of our common stock by Swartz on March 31, 2002 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. (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 approximately 22% 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: 96 - 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. 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 97 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. DESCRIPTION OF SECURITIES COMMON STOCK We are authorized to issue 300,000,000 shares of our $.01 par value common stock, of which 22,617,959 shares were issued and outstanding as of June 30, 2002. 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 voting 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 Holder"). Swartz currently has 500,000 warrants, (for a further discussion see "Selling Security Holder" and Exhibit 10.1 of the "Investment Agreement"). 98 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, the Consolidated Financial Statements of Castle Exploration Corporation as of September 30, 2001 and 2000, and for each of the years in the three year period ended September 30, 2001 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 Graham Sawyer Terry & Moore, 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 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. 99 FINANCIAL STATEMENTS Financial Statements are included on Pages F-1 through F-124. The Table of Contents to the Financial Statements is as follows: DELTA PETROLEUM CORPORATION Report of Independent Certified Public Accountants KPMG LLP F-1 Consolidated Balance Sheets as of March 31, 2002 (Unaudited), June 30, 2000 and 1999 F-2 to F-3 Consolidated Statements of Operations for the Nine Months Ended March 31, 2002 and 2001 (Unaudited), 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 Nine Months Ended March 31, 2002 (Unaudited), and the Years ended June 30, 2001, 2000 and 1999 F-5 to F-6 Consolidated Statements of Cash Flows for the Nine Months Ended March 31 2002 and 2001 (Unaudited) and the Years Ended June 30, 2001, 2000 and 1999 F-7 Notes to Consolidated Financial Statements and Summary of Accounting Policies F-8 to F-44 Report of Independent Certified Public Accountants KPMG LLP F-45 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-46 Notes to New Mexico Properties Statements of Oil and Gas Revenue and Direct Lease Operating Expenses F-47 to F-49 Report of Independent Certified Public Accountants KPMG LLP F-50 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-51 Notes to Point Arguello Properties Statements of Oil and Gas Revenue and Direct Lease Operating Expenses F-52 to F-55 100 Report of Independent Certified Public Accountants KPMG LLP F-56 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-57 Notes to North Dakota Properties Statements of Oil and Gas Revenue and Direct Lease Operating Expenses F-58 to F-60 Unaudited Condensed Pro Forma Balance Sheet as of March 31, 2002 F-61 Unaudited Condensed Pro Forma Statement of Operations for the year ended June 30, 2001 F-62 Unaudited Condensed Pro Forma Statement of Operations for the nine months ended March 31, 2002 F-63 Notes to Condensed Pro Forma Financial Statements (Unaudited) F-64 to F-67 101 CASTLE ENERGY CORPORATION Report of Independent Certified Public Accountants KPMG LLP F-68 Consolidated Statement of Operations for the years ended September 30, 2001, 2000 and 1999 F-69 Consolidated Balance Sheets as of September 30, 2001 and 2000 F-70 Consolidated Statement of Cash Flows for the years ended September 30, 2001, 2000 F-71 to F-72 Consolidated Statement of Stockholders' Equity for the years ended September 30, 2001, 2000 and 1999 F-73 Notes to Consolidated Financial Statements F-74 Consolidated Balance Sheets as of March 31, 2002 and September 30, 2001 F-113 Consolidated Statements of Operations for the Three Months Ended March 31, 2002 and 2001 F-114 Consolidated Statements of Operations for the Six Months Ended March 31, 2002 and 2001 F-115 Consolidated Statement of Cash Flows for the Six Months Ended March 31, 2002 and 2001 F-116 Consolidated Statements of Stockholders' Equity and Other Comprehensive Income for the Year Ended September 30, 2001 and Six Months Ended March 31, 2002 F-117 Notes to Consolidated Financial Statements F-118 to F-124 102 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

March 31, June 30, June 30, 2002 2001 2000 ----------- ----------- ----------- (Unaudited) ASSETS Current Assets: Cash $ 274,000 $ 518,000 $ 302,000 Trade accounts receivable, net of allowance for doubtful accounts of $50,000 at March 31, 2002, June 2001 and 2000 824,000 1,673,000 614,000 Accounts receivable - related parties 118,000 272,000 144,000 Prepaid assets 953,000 594,000 373,000 Other current assets 222,000 538,000 198,000 ----------- ----------- ----------- Total current assets 2,391,000 3,595,000 1,631,000 ----------- ----------- ----------- Property and Equipment: Oil and gas properties, at cost (using the successful efforts method of accounting): 27,829,000 29,955,000 20,414,000 Less accumulated depreciation and depletion (5,267,000) (5,024,000) (2,538,000) ----------- ----------- ----------- Net property and equipment 22,562,000 24,931,000 17,876,000 ----------- ----------- ----------- Long term assets: Deferred financing costs 147,000 241,000 367,000 Investment in Bion Environmental 112,000 221,000 229,000 Partnership net assets 916,000 844,000 675,000 Asset held for sale 5,702,000 - - Deposit on purchase of oil and gas properties - - 280,000 ----------- ----------- ----------- Total long term assets 6,877,000 1,306,000 1,551,000 $31,830,000 $29,832,000 $21,058,000 =========== =========== ===========

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

March 31, June 30, June 30, 2002 2001 2000 ----------- ----------- ----------- (Unaudited) LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Current portion of long-term debt $ 3,186,000 3,038,000 $ 1,766,000 Accounts payable 2,626,000 2,071,000 1,637,000 Other accrued liabilities 45,000 46,000 154,000 Deferred revenue - - 59,000 ----------- ----------- ----------- Total current liabilities 5,857,000 5,155,000 3,616,000 ----------- ----------- ----------- Long-term debt, net 4,934,000 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 13,038,000 shares at March 31, 2002, 11,160,000 June 30, 2001 and 8,422,000 at June 30, 2000 130,000 112,000 84,000 Additional paid-in capital 47,042,000 40,700,000 33,747,000 Accumulated other comprehensive income (40,000) 69,000 77,000 Accumulated deficit (26,093,000) (22,600,000) (22,945,000) ----------- ----------- ----------- Total stockholders' equity 21,039,000 18,281,000 10,963,000 ----------- ----------- ----------- Commitments $31,830,000 $29,832,000 $21,058,000 =========== =========== ===========

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

Nine Months Ended Year Ended ------------------------- ------------------------------------- March 31, March 31, June 30, June 30, June 30, 2002 2001 2001 2000 1999 ----------- ----------- ----------- ----------- ----------- (Unaudited) (Unaudited) Revenue: Oil and gas sales $ 5,317,000 $ 9,352,000 $12,254,000 $ 3,356,000 $ 558,000 Gain (loss) on sale of oil and gas properties (107,000) - 458,000 75,000 957,000 Operating fee income 80,000 80,000 106,000 76,000 43,000 Other revenue - 44,000 59,000 69,000 137,000 ----------- ----------- ----------- ----------- ----------- Total revenue 5,290,000 9,476,000 12,877,000 3,576,000 1,695,000 Operating expenses: Lease operating expenses 2,679,000 3,783,000 4,698,000 2,405,000 210,000 Depreciation and depletion 2,249,000 1,556,000 2,533,000 888,000 229,000 Exploration expenses 125,000 49,000 89,000 47,000 75,000 Abandoned and impaired properties 162,000 - 798,000 - 273,000 Dry hole costs 396,000 90,000 94,000 - 226,000 Professional fees 954,000 815,000 1,108,000 519,000 372,000 General and administrative 1,231,000 896,000 1,470,000 1,258,000 1,133,000 Stock option expense 53,000 334,000 409,000 538,000 2,081,000 ----------- ----------- ----------- ----------- ----------- Total operating expenses 7,849,000 7,523,000 11,199,000 5,655,000 4,599,000 ----------- ----------- ----------- ----------- ----------- Income from operations (2,559,000) 1,953,000 1,678,000 (2,079,000) (2,904,000) Other income and expenses: Other income 13,000 435,000 528,000 90,000 23,000 Interest and financing costs (947,000) (1,495,000) (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 (934,000) (1,060,000) (1,333,000) (1,288,000) (94,000) Net income (loss) $(3,493,000) $ 893,000 $ 345,000 $(3,367,000) $(2,998,000) =========== =========== =========== =========== =========== Net income (loss) per common share: Basic $ (0.30) $ 0.09 $ (0.46) $ (0.51) $ (0.18) =========== =========== =========== =========== =========== Diluted $ (0.30)* $ 0.08 $ (0.46)* $ (0.51)* $ (0.18)* =========== =========== =========== =========== =========== *Potentially dilutive securities outstanding were anti-dilutive.

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 Nine Months Ended March 31, 2002

Accumulated other Common Stock Additional comprehensive -------------------- paid-in income Comprehensive Accumulated Shares Amount capital (loss) income (loss) deficit Total --------- -------- ----------- ------------- -------------- ------------ ---------- Balance, June 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 gain 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 loss, 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 and options 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 Nine Months Ended March 31, 2002 (Continued)

Accumulated other Common Stock Additional comprehensive -------------------- paid-in income Comprehensive Accumulated Shares Amount capital (loss) income (loss) deficit Total --------- -------- ----------- ------------- -------------- ------------ ---------- Comprehensive loss: Net lossme - - - 345,000 345,000 345,000 ---------- Other comprehensive loss, net of tax Unrealized gain on equity securities - - - (8,000) (8,000) (8,000) ---------- Comprehensive loss - - - 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 1,004,000 10,000 2,412,000 - - 2,422,000 commissions 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 - - - (3,493,000) (3,493,000) (3,493000) ---------- Other comprehensive loss, net of tax Unrealized loss on equity securities - - - (109,000) (109,000) (109,000) ---------- Comprehensive income - - - (3,602,000) ========== Stock options granted as compensation - - 53,000 - - 53,000 Shares issued for cash, net of 72,000 1,000 224,000 - - 225,000 commissions Shares issued for cash upon exercise of options 252,000 2,000 397,000 - - 399,000 Shares issued for services 14,000 - 48,000 - - 48,000 Shares issued for oil and gas properties 137,000 1,000 374,000 - - 375,000 Shares issued for all outstanding shares of Piper Petroleum Company 1,377,000 14,000 5,220,000 - - 5,234,000 Shares issued for debt 51,000 - 157,000 - - 157,000 Shares reacquired and retired (25,000) - (131,000) - - (131,000) ---------- -------- ---------- ------- ----------- ---------- Balance, March 31, 2002 (Unaudited) 13,038,000 $130,000 47,042,000 (40,000) (26,093,000) 21,039,000 ========== ======== ========== ======= =========== ==========

See accompanying notes to consolidated financial statements. F-6 DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS

Nine Months Ended Year Ended ------------------------- -------------------------------------- March 31, March 31, June 30, June 30, June 30, 2002 2001 2001 2000 1999 ----------- ----------- ----------- ----------- ----------- (Unaudited) (Unaudited) Cash flows operating activities: Net income (loss) $(3,493,000) $ 893,000 $ 345,000 $(3,367,000) $(2,998,000) Adjustments to reconcile net income (loss) to cash used in operating activities: Gain/(loss) on sale of oil and gas properties 107,000 - (458,000) (75,000) (957,000) Loss on sale of securities available for sale - - - 113,000 97,000 Depreciation and depletion 2,249,000 1,556,000 2,533,000 888,000 229,000 Stock option expense 53,000 445,000 520,000 500,000 2,081,000 Amortization of financing costs 417,000 370,000 506,000 467,000 - Abandoned and impaired properties 162,000 - 798,000 - 273,000 Common stock issued for services 48,000 - - - 16,000 Dry hold costs - - - - - Net changes in operating assets and operating liabilities: (Increase) decrease in trade accounts receivable 897,000 (941,000) (1,059,000) (533,000) 84,000 Increase in prepaid assets 32,000 (395,000) (221,000) (373,000) - (Increase) decrease in other current assets (7,000) 61,000 66,000 (63,000) - Increase (decrease) in accounts payable trade (1,010,000) (120,000) 222,000 1,243,000 (177,000) Increase (decrease) in other accrued liabilities (1,000) (292,000) (269,000) 144,000 - Deferred revenue - (44,000) (59,000) (69,000) (137,000) ----------- ----------- ------------ ----------- ----------- Net cash provided by (used in) operating activities $ (546,000) $ 1,533,000 $ 2,924,000 $(1,125,000) $ 1,489,000 ----------- ----------- ------------ ----------- ----------- Cash flows from investing activities: Additions to property and equipment, net (2,009,000) (9,542,000) (11,613,000) (7,760,000) (507,000) Deposit on purchase of oil and gas properties - - - (6,000) (1,000,000) Increase in oil and gas properties available for sale (22,000) - - - - Proceeds from sale of securities available for sale - - - 135,000 175,000 Proceeds from sale of oil and gas properties 3,398,000 - 3,700,000 75,000 1,384,000 Merger with Piper Petroleum Company 74,000 - - - - (Increase) decrease in long term assets (72,000) 125,000 (169,000) (675,000) - ----------- ----------- ------------ ----------- ----------- Net cash provided by (used in) investing activities 1,369,000 (9,417,000) (8,082,000) (8,231,000) 52,000 ----------- ----------- ------------ ----------- ----------- Cash flows from financing activities: Stock issued for cash upon exercise of options 399,000 994,000 1,480,000 1,378,000 160,000 Issuance of common stock for cash 225,000 2,422,000 2,422,000 1,024,000 356,000 Proceeds from borrowings 1,633,000 13,520,000 14,394,000 12,817,000 1,400,000 Repayment of borrowings (3,347,000) (8,825,000) (12,777,000) (5,640,000) (400,000) Decrease (increase) in accounts receivable from related parties 23,000 (115,000) (145,000) (20,000) 4,000 ----------- ----------- ------------ ----------- ----------- Net cash provided by (used in) financing activities (1,067,000) 7,996,000 5,374,000 9,559,000 1,520,000 ----------- ----------- ------------ ----------- ----------- Net increase in cash (244,000) 112,000 216,000 203,000 83,000 ----------- ----------- ------------ ----------- ----------- Cash at beginning of period 518,000 302,000 302,000 99,000 17,000 ----------- ----------- ------------ ----------- ----------- Cash at end of period $ 274,000 $ 414,000 $ 518,000 $ 302,000 $ 100,000 =========== =========== ============ =========== =========== Supplemental cash flow information - Cash paid for interest and financing costs $ 530,000 $ 1,398,000 $ 1,677,000 $ 741,000 $ 281,000 =========== =========== ============ =========== =========== Non-cash financing activities: Shares issued for all outstanding shares of Piper Petroleum Company $ 5,234,000 $ - $ - $ - $ - =========== =========== ============ =========== =========== Common stock issued for the purchase of oil and gas properties, net of return of deposited shares $ 375,000 $ 2,832,000 $ 2,954,000 $ 550,000 $ 20,000 =========== =========== ============ =========== =========== Common stock issued for note payable and accrued financing $ 157,000 $ 511,000 $ 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 $ - $ - $ - $ 273,000 $ 616,000 =========== =========== ============ =========== =========== Shares reacquired and retired for oil and gas properties and options exercised $ 131,000 $ 906,000 $ 906,000 $ - $ - =========== =========== ============ =========== ===========

See accompanying notes to consolidated financial statements. F-7 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002, June 30, 2001, 2000 and 1999 (Information as of and for the nine months ended March 31, 2002 and 2001 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 March 31, 2002 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 March 31, 2002, the Company had a working capital deficit of $3,466,000 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 the nine months ended March 31, 2002, fiscal 2001 and 2000, the Company has raised approximately $624,000, $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 March 31, 2002 (Unaudited), June 30, 2001, 2000 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 March 31, 2002 (Unaudited), 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 March 31, 2002, 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 March 31, 2002 (Unaudited), 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 $44,000 for the nine months ended March 31, 2002 and 2001 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 March 31, 2002 (Unaudited), 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 nine months ended March 31, 2002 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 approved for issuance SFAS No. 143, "Accounting for Asset Retirement Allocations." 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. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, that superseded SFAS No. 121 and APB Opinion No. 30. SFAS 144 provides guidance on differentiating between assets held and used, held for sale, and held for disposal other than by sale, and the required valuation of such assets. SFAS 144 is effective for fiscal years beginning after December 15, 2001. The adoption of SFAS No. 144 on January 1, 2002 did not have a material impact on the consolidated financial statements, and is not anticipated to have a material impact in the future. F-12 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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 nine months ended March 31, 2002. The cost and estimated market value of the Company's investment in Bion at March 31, 2002 (Unaudited), June 30, 2001 and 2000 are as follows: Estimated Unrealized Market Cost Gain/(Loss) Value March 31, 2002 $152,000 $ (40,000) $112,000 June 30, 2001 $152,000 $ 69,000 $221,000 June 30, 2000 $152,000 $ 77,000 $229,000 As of July 11, 2002, the estimated market value of the Company's investment in Bion, based on the quoted bid price of Bion's common stock, was approximately $50,000. F-13 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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 $9,372,000, $9,359,000 and $9,109,000, March 31, 2002, 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 March 31, 2002 (Unaudited), 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 March 31, 2002 (Unaudited), 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 March 31, 2002, 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. On January 9, 2002, Delta and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of forty undeveloped federal leases, some of which are part of Delta's Offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their Offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case that a 1990 amendment to the Coastal Zone Management Act required the Government to make a consistency determination prior to granting lease suspension requests in 1999 constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations. The forty undeveloped leases are located in the Offshore Santa Maria Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the Santa Barbara Channel off Santa Barbara and Ventura counties. None of these leases is currently impaired, but in the event that there is some future adverse ruling by the California Coastal Commission under the Coastal Zone Management Act and Delta decides not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear Delta DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), June 30, 2001, 2000 and 1999 (3) Oil and Gas Properties, Continued its litigation. It is also possible that other events could occur during the appellate process that would cause the leases to become impaired, and Delta will continuously evaluate those factors as they occur. The suit seeks compensation for the lease bonuses and rentals paid to the Federal Government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. Delta's claim (including the claim of its subsidiary Amber Resources Company) for lease bonuses and rentals paid by Delta and its predecessors is in excess of $152,000,000. In addition, its claim for exploration costs and related expenses will also be substantial. 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. 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%, F-17 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), June 30, 2001, 2000 and 1999 (3) Oil and Gas Properties, Continued 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. 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:

Nine Months Ended Year Ended March 31, (Unaudited) June 30, ------------------------- ------------------------- 2002 2001 2001 2000 Oil and gas sales $ 5,317,000 $9,644,000 $12,546,000 $ 8,314,000 =========== ========== =========== =========== Net income (loss) $(3,493,000) $1,164,000 $ 616,000 $ (786,000) =========== ========== =========== =========== Net income (loss) per common share: Basic $ (.30) $ .12 $ .06 $ (.11) =========== ========== =========== =========== Diluted $ (.30) $ .10 $ .05 $ (.11) =========== ========== =========== ===========

F-18 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), June 30, 2001, 2000 and 1999 (3) Oil and Gas Properties, Continued 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. On November 15, 2001, the Company acquired producing oil and gas interests in Texas from certain unrelated entities and an unrelated individual. The acquisition had a purchase price of approximately $788,000 consisting of $413,000 in cash and 137,000 shares of the Company's restricted common stock with a fair value of $375,000 based on the closing price on the date of closing. On February 19, 2002, Delta completed the acquisition of Piper Petroleum Company ("Piper"), a privately owned oil and gas company headquartered in Fort Worth, Texas. Delta issued 1,374,240 shares of restricted common stock for 100% of the shares of Piper. The 1,374,240 shares of restricted common stock was valued at approximately $5,234,000 based on the five-day average closing price surrounding the announcement of the merger. In addition, Delta issued 51,000 shares for the cancellation of certain debt of Piper. As a result of the acquisition, we acquired Piper's working and royalty interests in over 300 properties which are primarily located in Texas, Oklahoma and Louisiana along with a 5% working interest in the Comet Ridge coal bed methane gas project in Queensland, Australia. This project is classified as held for sale at March 31, 2002 at its estimated fair value of $5,272,000. On March 1, 2002, Delta completed the sale of 21 producing wells and acreage located primarily in the Eland and Stadium fields of Stark County, North Dakota, to Sovereign Holdings, LLC, a privately-held Colorado limited liability company, for cash consideration of $2,750,000 pursuant to a purchase and sale agreement dated February 1, 2002 and effective January 1, 2002. As a result of the sale, the Company recorded a loss of sale of oil and gas properties of $1,000. These properties accounted for approximately 9.45% of our total assets as of June 30, 2001 and also accounted for approximately 22.6% of our total revenues and approximately 11.9% of our total operating expenses during our past fiscal year. Approximately $1,300,000 of the proceeds from the sale were used to pay existing debt. On March 1, 2002, the Company sold the properties acquired on November 15, 2001, to Whiting Petroleum Corporation for $648,000. As a result of the Sale, the Company recorded a loss on sale of oil and gas properties of $106,000. Proceeds from the sale were used to pay existing debt. F-19 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), June 30, 2001, 2000 and 1999 (3) Oil and Gas Properties, Continued During the nine months ended March 31, 2002 and 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 (loss) on sale of oil and gas properties of $(107,000) and $458,000, $75,000 and $957,000 for the nine months ended March 31, 2002 and years ended June 30, 2001, 2000 and 1999, respectively. Subsequent Events On May 24, 2002 we completed the sale of our undivided interests in an Authority to Prospect (ATP) covering lands in Queensland, Australia, to Tipperary Corporation, in exchange for Tipperary's producing properties in the West Buna Field (Hardin and Jasper counties, Texas)which had a fair market value of approximately $4,100,000, $700,000 in cash, and 250,000 unregistered shares of Tipperary common stock. No gain or loss was recorded on this transaction. Net daily production from the West Buna Field approximates 900,000 cubic feet equivalent. On May 31, 2002, we acquired all of the domestic oil and gas properties of Castle Energy Corporation. The properties acquired from Castle consist of interests in approximately 525 producing wells located in fourteen (14) states, plus associated undeveloped acreage. We issued 9,566,000 shares of Common Stock to Castle Energy Corporation as part of the purchase price. We are entitled to repurchase up to 3,188,667 of our shares from Castle for $4.50 per share for a period of one year after closing. Our agreement with Castle was effective as of October 1, 2001 and the net operating revenues from the properties between the effective date and the May 31, 2002 closing date will be recorded as an adjustment to the purchase price. Also on May 31, 2002 we obtained a new $20 million credit facility with the Bank of Oklahoma and Local Oklahoma Bank, part of which was used to pay the remainder of the Castle purchase price. Approximately $19 million of the credit facility was utilized to close the Castle transaction and to pay off our existing loan with US Bank. Our total debt now approximates $25 million. A substantial portion of our oil and gas properties is pledged as collateral for our new loan and the terms of the Credit Agreement limit our flexibility to engage in many types of business activities without obtaining the consent of our lenders in advance. F-20 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), June 30, 2001, 2000 and 1999 (4) Long Term Debt March 31, June 30, 2002 2001 2000 ------------- ------------------------ (Unaudited) A $6,371,000 $7,337,000 $7,504,000 B 1,475,000 2,097,000 - C 274,000 - - D - - 741,000 ---------- ---------- ---------- $8,120,000 $9,434,000 $8,245,000 Current Portion 3,186,000 3,038,000 1,766,000 ---------- ---------- ---------- Long-Term Portion $4,934,000 $6,396,000 $6,479,000 ========== ========== ========== A. On December 1, 1999, the Company borrowed $8,000,000 at prime plus 1-1/2% from Kaiser-Francis Oil Company ("Lender"). 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 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). 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 is currently in compliance with the loan agreement. C. As a result of the merger with Piper on February 19, 2002, the Company established a note payable of $350,000 to John Wilson II, for amounts previously owed to him by Piper. The value of the note was $233,000 at March 31, 2002 and is due on May 19, 2002. The Company also assumed a note payable to Summit Bank which had a value of $40,000 at March 31, 2002 which was paid in full subsequent to March 31, 2002. D. 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-21 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002(Unaudited), 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-22 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002(Unaudited), 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-23 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-24 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-25 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-26 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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 March 20, 2002 the Company issued 71,429 shares of its restricted common stock, at a price of $3.15 per share, to an unrelated individual for net proceeds of $225,000. 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-27 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-28 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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. During the nine months ended March 31, 2002, the Company granted 507,500 options to its employees. 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 $53,000, $334,000, $110,000, $92,000 and $1,985,000, to employees for the nine months ended March 31, 2002 and 2001 and years ended June 30, 2001, 2000 and 1999, respectively, for options issued to the directors below market. F-29 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-30 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-31 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-32 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-33 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-34 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), June 30, 2001, 2000 and 1999 (8) Related Party Transactions, Continued Accounts Receivable Related Parties At March 31, 2002, the Company had $118,000 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 $53,000 and $334,000 for the nine months ended March 31, 2002 and 2001 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-35 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-36 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), June 30, 2001, 2000 and 1999 (9) Earnings Per Share The following table sets forth the computation of basic and diluted earnings per share:

Nine Months Ended March 31, (Unaudited) Year Ended June 30, --------------------------- ------------------------------------------ 2002 2001 2001 2000 1999 Numerator: Numerator for basic and diluted earnings per share - income available to common stockholders $ (3,493,000) $ 893,000 $ 345,000 $(3,367,000) $(2,998,000) ------------ ------------ ------------ ----------- ----------- Denominator: Denominator for basic earnings per share-weighted average shares outstanding 11,513,000 10,049,000 10,289,000 7,271,000 5,855,000 Effect of dilutive securities- stock options and warrants * 1,736,000 1,464,000 * * ------------ ------------ ------------ ----------- ----------- Denominator for diluted earnings per common shares 11,513,000 11,785,000 11,753,000 7,271,000 5,855,000 ============ ============ ============ =========== =========== Basic earnings per common share $ (.30) .09 .03 (.46) (.51) ============ ============ ============ =========== =========== Diluted earnings per common share (.30)* .08 .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. ("Enron") 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. After Enron filed bankruptcy, we terminated our fixed price contract. We expect to have a claim in bankruptcy, but do not expect to recover these claims. F-37 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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: March 31, June 30, 2002 2001 2000 ------------- ----------- ---------- (Unaudited) Unproved undeveloped offshore California properties* $ 9,372,000 $ 9,359,000 $9,109,000 Proved undeveloped offshore California properties 996,000 1,149,000 1,700,000 Undeveloped onshore domestic properties 1,541,000 1,616,000 452,000 Undeveloped foreign properties - - 624,000 Developed Offshore California properties 6,078,000 4,699,000 3,286,000 Developed onshore domestic properties 9,683,000 13,038,000 5,154,000 ----------- ----------- ---------- 27,670,000 29,861,000 20,325,000 Accumulated depreciation and depletion (5,180,000) (4,940,000) (2,457,000) ----------- ----------- ---------- $22,490,000 $24,921,000 $17,868,000 =========== =========== =========== * The unproved undeveloped offshore California properties have no proved reserves. F-38 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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:

March 31, (Unaudited) June 30, ------------------------------------------ ------------------------------------------------------------------- 2002 2001 2001 2000 1999 Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore -------- -------- ---------- ---------- ---------- ---------- --------- ---------- ---------- -------- Unproved property acquisition costs $ - $365,000 $1,332,000 $ 350,000 $1,332,000 $ 350,000 $ - $1,739,000 $1,034,000 $ - Proved property acquisition costs $ - $ - $6,605,000 $3,253,000 $7,480,000 $2,931,000 $2,756,000 $4,308,000 $ 17,000 $ - Development cost incurred on undeveloped reserves $106,000 $401,000 $ - $ - $ - $ 686,000 $ 39,000 $ 328,000 $ 62,000 $ - Development costs- other $578,000 $627,000 $ 663,000 $1,061,000 $ 592,000 $ 375,000 $ 73,000 $ 351,000 78,000 $ - Exploration costs $ 79,000 $ 46,000 $ 31,000 $ 18,000 $ 32,000 $ 57,000 $ 33,000 $ 14,000 $ 75,000 $ - $763,000 $1,393,000 $8,631,000 $4,682,000 $9,636,000 $4,399,000 $2,901,000 $6,740,000 $1,266,000 $ - Transferred amounts from undeveloped to developed properties $ 15,000 $153,000 $ - $ 510,000 $ - $ 510,000 $ - $ 55,000 $ 50,000 $ - Transferred from oil and gas properties to deferred financing costs $ - $ - $ - $ 130,000 $ - $ 330,000 $ - $ - $ - $ -

F-39 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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:

March 31, (Unaudited) June 30, ------------------------------------------ ----------------------------------------------------------------- 2002 2001 2001 2000 1999 Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- -------- Revenue: Oil and gas revenues $2,462,000 $2,855,000 $4,883,000 $4,469,000 $6,564,000 $5,690,000 $1,199,000 $2,157,000 $ 558,000 $ - Operating Income $ 80,000 $ - $ 80,000 $ - $ 106,000 $ - $ 76,000 $ - $ 43,000 $ - Gain (loss) on sale of oil and gas properties $ (107,000) $ - $ - $ - $ (1,000) $ 459,000 $ 75,000 $ - $ - $ - Expenses: Lease operating $ 576,000 $2,103,000 $ 602,000 $3,181,000 $ 805,000 $3,893,000 $ 345,000 $2,060,000 $ 210,000 $ - Depletion $1,408,000 $ 838,000 $ 956,000 $ 598,000 $1,691,000 $ 839,000 $ 325,000 $ 561,000 $ 229,000 $ - Exploration $ 79,000 $ 46,000 $ 31,000 $ 18,000 $ 32,000 $ 57,000 $ 33,000 $ 14,000 $ 75,000 $ - Abandonment and impaired properties $ 162,000 $ - $ - $ - $ 798,000 $ - $ - $ - $ 273,000 $ - Dry hole costs $ 396,000 $ - $ 90,000 $ - $ 94,000 $ - $ - $ - $ 226,000 $ - Results of operations of oil and gas producing activities $(186,000) $ (132,000) $3,284,000 $ 672,000 $3,249,000 $2,360,000 $ 647,000 $ (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-40 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-41 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-42 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-43 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2002 (Unaudited), 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-44 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 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 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 accounting principles generally accepted in the United States of America. /s/ KPMG LLP KPMG LLP Denver, Colorado December 29, 1999 F-45 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-46 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-47 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-48 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-49 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 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 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 accounting principles generally accepted in the United States of America. /s/ KPMG LLP KPMG LLP Denver, Colorado February 7, 2000 F-50 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-51 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-52 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-53 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-54 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-55 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 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 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 accounting principles generally accepted in the United States of America. /s/ KPMG LLP KPMG LLP Denver, Colorado November 28, 2000 F-56 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-57 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-58 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-59 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-60 DELTA PETROLEUM CORPORATION Unaudited Condensed Pro Forma Balance Sheet As of March 31, 2002 (000's Omitted)

Pro Forma Delta Adjustments Pro Forma Historical (Note B) Delta --------- ----------- --------- Current Assets: Cash $ 274 $ 974 (1) $ 1,248 Accounts receivable 942 942 Prepaid assets 953 953 Other current assets 222 222 -------- ------- -------- Total current assets 2,391 974 3,365 -------- ------- -------- Property and Equipment: Oil and gas properties, at cost, using the successful efforts method of accounting 27,829 43,846 (1) 71,675 Less accumulated depreciation and depletion (5,267) (5,267) -------- ------- -------- Net property and equipment 22,562 43,846 66,408 -------- ------- -------- Long term assets: Partnership net assets 916 916 Assets held for sale 5,702 5,702 Other long term assets 259 259 -------- ------- -------- Total long term assets 6,877 - 6,877 $ 31,830 44,820 76,650 ======== ======= ======== Current Liabilities: Current portion of long-term debt $ 3,186 $ 2,806 (1) $ 5,992 Accounts payable 2,626 2,626 Other accrued liabilities 45 45 -------- ------- -------- Total current liabilities 5,857 2,806 8,663 Long-term debt 4,934 15,430 (1) 20,364 -------- ------- -------- Stockholders' Equity: Preferred stock, $.10 par value - - Common stock, $.01 par value 130 96 (1) 226 Additional paid-in capital 47,042 29,374 (1) 76,416 Put option for Delta stock - (2,886)(1) (2,886) Accumulated other comprehensive loss (40) (40) Accumulated deficit (26,093) (26,093) -------- ------- -------- Total stockholders' equity 21,039 26,584 47,623 -------- ------- -------- Commitments $ 31,830 44,820 $ 76,650 ======== ======= ========

See accompanying notes to condensed pro forma financial statements. F-61 DELTA PETROLEUM CORPORATION Unaudited Condensed Pro Forma Statement of Operations Year Ended June 30, 2001 ("000's" Omitted)

Delta Delta Castle Historical Historical Historical Eland Properties Pro Forma Year Ended Year Ended Year Ended Adjustments Pro Forma June 30, 2001 September 30, 2001 June 30, 2001 (Note C) Delta ------------- ------------------ ---------------- ----------- --------- Revenue: Oil and gas sales $ 12,254 21,144 (2,916) (846)(1) $ 29,636 Gain on sale of oil and gas properties 458 - - 458 Other revenue 165 - - 165 -------- ------- ------ ------ -------- Total revenue 12,877 21,144 (2,916) (846) 30,259 Exploration and Production Lease operating expenses 4,787 9,227 (203) (369)(1) 13,442 Depreciation and depletion 2,533 3,470 (1,125) (3,470)(2) 5,594 4,186 (2) Abandoned and impaired properties 798 2,765 (2,765)(4) 798 Dry hole costs 94 - 94 -------- ------- ------ ------ -------- 8,212 15,462 (1,328) (2,418) 19,928 Corporate general and administrative 2,987 4,169 - 7,156 -------- ------- ------ ------ -------- Total operating expenses 11,199 19,631 (1,328) (2,418) 27,084 -------- ------- ------ ------ -------- Income (loss) from operations 1,678 1,513 (1,588) 1,572 3,175 Other income and expenses: Other income 528 683 (683)(6) 528 Other expense - (99) 99 (6) - Interest expense and financing costs (1,861) - (1,229)(3) (3,236) (146)(7) -------- ------- ------ ------ -------- Total other income and expenses (1,333) 584 - (1,959) (2,708) -------- ------- ------ ------ -------- Net income (loss) before tax effect $ 345 2,097 (1,588) (387) $ 467 Provision for income tax expense - (381) 381 (5) - -------- ------- ------ ------ -------- Net income 345 1,716 (1,588) (6) 467 ======== ======= ====== ====== ======== Income (loss) per share: Basic $ 0.03 $ 0.02 ======== ======== Diluted $ 0.03 $ 0.02 ======== ======== Weighted average number of common and potential dilutive shares outstanding: Basic 10,289 9,566 19,855 ======== ====== ======== Diluted 11,753 9,566 21,319 ======== ====== ========

See accompanying notes to condensed pro forma financial statements. F-62 DELTA PETROLEUM CORPORATION Unaudited Condensed Pro Forma Statement of Operations Nine Months Ended March 31, 2002 (000's Omitted)

Delta Castle Historical Delta Historical Historical Eland Properties Pro Forma Nine Months Ended Nine Months Ended Nine Months Ended Adjustments Pro Forma March 31, 2002 March 31, 2002 March 31, 2002 (Note C) Delta ----------------- ----------------- ----------------- ----------- --------- Revenue: Oil and gas sales $ 5,317 10,786 (1,030) (431)(1) $ 14,642 Loss on sale of oil and gas properties (107) - - (107) Other revenue 80 - - 80 -------- ------- ------- ------- --------- Total revenue 5,290 10,786 (1,030) (431) 14,615 Exploration and Production Lease operating expenses 2,804 5,365 (74) (215)(1) 7,880 Depreciation and depletion 2,249 3,618 (847) (3,618)(2) 4,734 3,332 (2) Abandoned and impaired properties 162 1,892 (1,892)(4) 162 Dry hole costs 396 - 396 -------- ------- ------- ------- --------- 5,611 10,875 (921) (2,393) 13,172 Corporate general and administrative 2,238 3,542 - 5,780 -------- ------- ------- ------- --------- Total operating expenses 7,849 14,417 (921) (2,393) 18,952 -------- ------- ------- ------- --------- Income (loss) from operations (2,559) (3,631) (109) 1,962 (4,337) Other income and expenses: Other income 13 122 (122)(6) 13 Other expense - (308) 308 (6) - Interest expense and financing costs (947) - (922)(3) (1,955) - (86)(7) -------- ------- ------- ------- --------- Total other income and expenses (934) (186) - (822) (1,942) -------- ------- ------- ------- --------- Net income (loss) before tax effect $ (3,493) (3,817) (109) 1,140 $ (6,279) Provision for income tax expense - 267 - (267)(5) - -------- ------- ------- ------- --------- Net income (3,493) (3,550) (109) 873 (6,279) ======== ======= ======= ======= ========= Income (loss) per share: Basic $ (0.30) $ (0.30) ======== ======== Diluted $ (0.30) $ (0.30) ======== ======== Weighted average number of common and potential dilutive shares outstanding: Basic 11,513 9,566 21,079 ======== ======== Diluted 11,513* 9,566 21,079 ======== ======== * Potentially dilutive securities outstanding were anti-dilutive

See accompanying notes to condensed pro forma financial statements. F-63 FINANCIAL STATEMENTS (UNAUDITED) A) BASIS OF PRESENTATION The accompanying unaudited condensed pro forma balance sheet assumes that the acquisition of oil and gas properties from Castle Energy Corporation referred to as ("the Castle Properties") occurred on March 31, 2002 and reflects the historical consolidated balance sheet of Delta Petroleum Corporation ("Delta") at that date giving pro forma effect to the proposed acquisition using the purchase method of accounting. The unaudited condensed pro forma balance sheet should be read in conjunction with the historical financial statements and related notes of Delta and Castle. The accompanying unaudited condensed pro forma statements of operations for the nine months ended March 31, 2002 and for the year ended June 30, 2001 assume that the acquisition of the Castle Properties occurred as of July 1, 2000. The year ended June 30, 2001 unaudited condensed pro forma statement of operations includes Delta's historical year ended June 30, 2001 and Castle's historical year ended September 30, 2001 statement of operations. It also assumes the sale of the Eland properties occurred on July 1, 2000 and eliminates the historical results of operations of the Eland Properties from the historical results of operations of Delta for the nine months ended March 31, 2002 and year ended June 30, 2001, and interest expense related to the long-term debt that was repaid with the proceeds. B) ACQUISITION OF CASTLE PROPERTIES AND SALE OF ELAND PROPERTIES - BALANCE SHEET On May 31, 2002, Delta acquired all of the domestic oil and gas properties of Castle Energy Corporation. The properties acquired from Castle consist of interests in approximately 525 producing wells located in fourteen (14) states, plus associated undeveloped acreage. Delta issued 9,566,000 shares of Common Stock to Castle Energy Corporation as part of the purchase price. Delta is entitled to repurchase up to 3,188,667 of its shares from Castle for $4.50 per share for a period of one year after closing. Delta's agreement with Castle was effective as of October 1, 2001 and the net operating revenues from the properties between the effective date and the May 31, 2002 closing date will be recorded as an adjustment to the purchase price. Also on May 31, 2002 Delta obtained a new $20 million credit facility with the Bank of Oklahoma and Local Oklahoma Bank, part of which was used to pay the remainder of the Castle purchase price. Approximately $19 million of the credit facility was utilized to close the Castle transaction and to pay off our existing loan with US Bank. Our total debt now approximates $25 million. A substantial portion of oil and gas properties is pledged as collateral for our new loan and the terms of the Credit Agreement limit our flexibility to engage in many types of business activities without obtaining the consent of our lenders in advance. As a part of the acquisition, upon closing, Delta has granted an option to acquire a 4% working interest in the properties acquired for a cost of $974,000 to BWAB Limited Liability Company ("BWAB"), a less than 10% shareholder of Delta. The difference between the $974,000 paid by BWAB which is less than fair value, and 4% of the cost of the Castle properties will be treated as an additional acquisition cost by Delta for their consultation and assistance related to the transaction. F-64 (1) The accompanying historical balance sheet of Delta at March 31, 2002 has been adjusted to record the purchase price of the Castle Properties by Delta, net of the interest that BWAB has acquired, assuming a stock price of $3.97 discounted by 30% according to a fair market appraisal of Delta's stock obtained from Snyder & Company, and additional debt incurred of $18,236,000 as follows ("000's" omitted): Cash (from BWAB) $ 974 Oil and gas properties, net of BWAB interest 43,846 ------- 44,820 ======= Current portion of long term debt 2,806 Long term debt 15,430 Common stock 96 Additional paid in capital 29,374 Put option for Delta stock (2,886) ------- $44,820 ======= C) ACQUISITION OF CASTLE PROPERTIES AND SALE OF ELAND PROPERTIES - STATEMENT OF OPERATIONS The accompanying unaudited condensed pro forma statements of operations for the nine months ended March 31, 2002 and for the year ended June 30, 2001 assume that the acquisition of the Castle Properties occurred as of July 1, 2000. The year ended June 30, 2001 unaudited condensed pro forma statement of operations includes Delta's historical year ended June 30, 2001 and Castle's historical year ended September 30, 2001 statement of operations. Delta utilizes the successful efforts method of accounting for its oil and gas properties while Castle utilizes the full cost method of accounting for its oil and gas properties. The pro forma financial statements have been converted from the full cost method of accounting to the successful efforts method of accounting. Based on our review of Castle oil and gas activities, no adjustments other than the ones included below are required to convert from the full cost method of accounting to the successful efforts method of accounting for the periods presented. Delta believes there are duplicative general and administrative costs that will be eliminated once this transaction is closed. As these amounts are not determinable, there has been no pro forma adjustment. The accompanying condensed pro forma statement of operations for the nine months ended March 31, 2002 and year ended June 30, 2001 have been adjusted to eliminate the historical revenue, direct lease operating expenses and depletion of the Eland Properties. In anticipation of the sale, Delta recorded an impairment of $162,000 for the nine months ended March 31, 2002. No impairment was recorded to the pro forma statement of operations for the year ended June 30, 2001 due to the additional reserves attributable to the properties. F-65 The following adjustments have been made to the accompanying condensed pro forma statements of operations for nine months ended March 31, 2002 and the year ended June 30, 2001: (1) To adjust revenue and direct lease operating expenses of the Castle properties to reflect the effect of the interest to be acquired by BWAB. (2) To remove Castle's depletion calculation and adjust Delta's depletion expense to reflect the pro forma depletion expense giving effect to the proposed acquisition of the Castle Properties. The depletion expense was calculated using estimated proved reserves by field and assumed 80% of the acquisition cost was allocable to the producing properties which represent the fair market value of producing oil and gas properties acquired. The pro forma depletion and the allocation to producing properties is based on the reserve report prepared by Delta in evaluating the Castle properties. (3) To record interest expense for interest associated with the debt incurred in connection with the acquisition of the Castle Properties at a rate of prime plus 1-1/2% per annum (current rate 6.5% per annum). A one-eighth change in interest rate would have a $154,000 annual impact on interest expense. (4) To eliminate abandoned and impaired properties expense incurred by Castle relating to foreign properties not acquired by Delta. (5) Taxes have been eliminated as a result of Delta's net operating loss carry forward position and income tax valuation or a pro forma statement of operation loss as a result of the acquisition of the Castle properties. (6) To adjust the unaudited pro forma statement of operations for Castle's other income and other expense. These items would not be applicable to Delta as Delta is only purchasing Castle's United States domestic oil and gas properties. (7) To adjust interest expense for interest associated with the debt incurred in connection with the Eland Properties at a rate of 8.8% for the nine months ended March 31, 2002 and 11.3% for the year ended June 30, 2001. (Rates are based on interest incurred during the respective periods presented.) A one-eighth change in interest rate would have a $1,625 annual impact on interest expense. D) ACQUISITION OF CASTLE PROPERTIES - RESERVE QUANTITIES AND STANDARIZED MEASURE OF DISCOUNTED FUTURE CASH FLOWS The accompanying pro forma combined reserve quantities and standardized measure of discounted future cash flows are as follows: The properties to be acquired from Castle ("Castle Properties") consist of interests in approximately 525 producing wells in fourteen (14) states, plus associated undeveloped acreage. F-66 Reserve Quantities (000's Omitted)

Delta Castle June 30, 2001 September 30, 2001 Combined ------------------ ------------------ ------------------ Oil Natural Gas Oil Natural Gas Oil Natural Gas (BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF) Proved developed and undeveloped reserves 1,557 4,682 3,360 30,692 4,917 35,374 Proved developed reserves 1,250 4,474 1,890 26,480 3,140 30,954 Standardized Measures of Discounted Future Cash Flows (000's Omitted) Delta Castle June 30, 2001 September 30, 2001 Combined ------------- ------------------ -------- Future cash flows $ 24,570 $138,594 $163,164 Future production costs (7,971) (41,193) (49,164) Future development costs (382) (8,655) (9,037) Future income tax expense - (13,102) (13,102) -------- -------- -------- Future net cash flows 16,217 73,549 89,766 Discounted factor of 10% for estimated timing of future cash flows (6,267) (37,269) (43,536) -------- -------- -------- Standardized measure of discounted future cash flows $ 9,950 $ 36,280 $ 46,230 ======== ======== ========

F-67 Independent Auditors' Report The Board of Directors Castle Energy Corporation: We have audited the accompanying consolidated balance sheets of Castle Energy Corporation and subsidiaries as of September 30, 2001 and 2000, and the related consolidated statements of operations, stockholders' equity and other comprehensive income, and cash flows for each of the years in the three year period ended September 30, 2001. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United State 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 misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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 Castle Energy Corporation and subsidiaries as of September 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 September 30, 2001 in conformity with accounting principles generally accepted in the United States of America. /s/ KPMG LLP KPMG LLP Houston, Texas December 18, 2001 F-68 CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS ("$000's" Omitted Except Share and Per Share Amounts)

Year Ended September 30, ------------------------ 2001 2000 1999 ---------- ---------- ---------- Revenues: Natural gas marketing and transmission: Gas sales $ 50,067 Exploration and production: Oil and gas sales $ 21,144 $ 17,959 6,712 ---------- ---------- ---------- 21,144 17,959 56,779 ---------- ---------- ---------- Expenses: Natural gas marketing and transmission: Gas purchases 31,062 General and administrative 35 Transportation 1,123 Depreciation and amortization 6,284 ---------- 38,504 ---------- Exploration and production: Oil and gas production 7,399 6,194 1,910 General and administrative 1,828 2,038 1,038 Depreciation, depletion and amortization 3,470 3,209 2,046 Impairment of foreign unproved properties 2,765 832 ---------- ---------- ----------- 15,462 12,273 4,994 ---------- ---------- ---------- Corporate general and administrative 4,169 3,717 4,112 ---------- ---------- ---------- 19,631 15,990 47,610 ---------- ---------- ---------- Operating income 1,513 1,969 9,169 ---------- ---------- ---------- Other income (expense): Interest income 641 784 1,701 Other income 42 25 352 Equity in loss of Networked Energy LLC (99) ---------- ---------- ---------- 584 809 2,053 ---------- ---------- ---------- Income before provision for (benefit of) income taxes 2,097 2,778 11,222 ---------- ---------- ---------- Provision for (benefit of) income taxes: State 11 (64) 79 Federal 370 (2,227) 2,877 ---------- ---------- ---------- 381 (2,291) 2,956 ---------- ---------- ---------- Net income $ 1,716 $ 5,069 $ 8,266 ========== ========== ========== Net income per share: Basic $ .26 $ .73 $ 1.01 ========== ========== ========== Diluted $ .25 $ .71 $ .99 ========== ========== ========== Weighted average number of common and potential dilutive shares outstanding: Basic 6,643,724 6,939,350 8,205,501 ========== ========== ========== Diluted 6,818,855 7,102,803 8,347,932 ========== ========== ==========

The accompanying notes are an integral part of these consolidated financial statements. F-69 CASTLE ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS ("$000's" Omitted Except Share and Per Share Amounts)

September 30, 2001 2000 -------- -------- ASSETS Current assets: Cash and cash equivalents $ 5,844 $ 11,525 Restricted cash 370 1,742 Accounts receivable 2,787 3,758 Marketable securities 6,722 10,985 Prepaid expenses and other current assets 277 251 Estimated realizable value of discontinued net refining assets 612 800 Deferred income taxes 1,879 2,256 -------- -------- Total current assets 18,491 31,317 Property, plant and equipment, net: Natural gas transmission 51 55 Furniture, fixtures and equipment 222 258 Oil and gas properties, net (full cost method): Proved properties 39,843 29,218 Unproved properties not being amortized 110 1,447 Investment in Networked Energy LLC 401 500 Note receivable - Penn Octane Corporation 500 -------- -------- Total assets $ 59,118 $ 63,295 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Dividend payable $ 331 $ 333 Accounts payable 3,543 2,433 Accrued expenses 292 265 Accrued taxes on appreciation of marketable securities 900 2,628 Stock subscription payable 150 Net refining liabilities retained 3,016 3,204 -------- -------- Total current liabilities 8,082 9,013 Long-term liabilities 9 6 -------- -------- Total liabilities 8,091 9,019 -------- -------- Commitments and contingencies Stockholders' equity: Series B participating preferred stock; par value - $1.00; 10,000,000 shares authorized; no shares issued Common stock; par value - $0.50; 25,000,000 shares authorized; 11,503,904 shares issued at September 30, 2001 and 2000 5,752 5,752 Additional paid-in capital 67,365 67,365 Accumulated other comprehensive income - unrealized gains on marketable securities, net of taxes 1,600 4,671 Retained earnings 42,816 42,422 -------- -------- 117,533 120,210 Treasury stock at cost - 4,871,020 shares at September 30, 2001 and 4,791,020 shares at September 30, 2000 (66,506) (65,934) -------- -------- Total stockholders' equity 51,027 54,276 -------- -------- Total liabilities and stockholders' equity $ 59,118 $ 63,295 ======== ========

The accompanying notes are an integral part of these consolidated financial statements. F-70 CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS ("$000's" Omitted Except Share and Per Share Amounts)

Year Ended September 30, ------------------------ 2001 2000 1999 -------- -------- -------- Cash flows from operating activities: Adjustments to reconcile net income to cash provided by operating activities: Depreciation, depletion and amortization 3,470 3,209 8,330 Impairment of foreign unproved properties 2,765 832 Deferred income taxes (benefit) 377 (2,256) 2,765 Unrealized gain on marketable securities (481) Impairment of Penn Octane preferred stock 423 Equity in loss of Networked Energy LLC 99 Changes in assets and liabilities: (Increase) decrease in restricted cash 1,372 (972) (157) Decrease in accounts receivable 971 1,414 3,209 Decrease in prepaid transportation 1,123 (Increase) decrease in prepaid expenses and other current assets (26) 343 (301) Decrease in other assets 29 Decrease in prepaid gas purchases 852 Increase (decrease) in accounts payable 1,110 (436) (5,740) Increase (decrease) in accrued expenses 27 (537) (861) Increase in other long-term liabilities 3 6 -------- -------- -------- Total adjustments 10,168 1,632 9,162 -------- -------- -------- Net cash flow provided by operating activities 11,884 6,701 17,428 -------- -------- -------- Cash flows from investment activities: Investment in note receivable - Penn Octane Corporation (500) Investment in marketable securities (34) (269) Proceeds from sale of oil and gas assets 48 1,427 Realization from (liquidation of) discontinued net refining assets 900 Acquisition of AmBrit oil and gas properties (20,170) Investment in other oil and gas properties (15,449) (11,226) (3,794) Investment in Networked Energy LLC (150) (350) Purchase of furniture, fixtures and equipment (82) (173) (98) Other (35) -------- -------- -------- Net cash used in investing activities (15,667) (10,857) (23,431) -------- -------- --------

(continued on next page) The accompanying notes are an integral part of these consolidated financial statements. F-71 CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS ("$000's" Omitted) (continued from previous page)

Year Ended September 30, ------------------------ 2001 2000 1999 -------- -------- -------- Cash flows from financing activities: Acquisition of treasury stock (572) (5,208) (6,919) Dividends paid to stockholders (1,326) (1,363) (1,681) Proceeds from exercise of stock options 255 -------- -------- -------- Net cash (used in) financing activities (1,898) (6,571) (8,345) -------- -------- -------- Net (decrease) in cash and cash equivalents (5,681) (10,727) (14,348) Cash and cash equivalents - beginning of period 11,525 22,252 36,600 -------- -------- -------- Cash and cash equivalents - end of period $ 5,844 $ 11,525 $ 22,252 ======== ======== ======== Supplemental disclosures of cash flow information are as follows: Cash paid during the period: Income taxes $ 11 $ 188 $ 108 ======== ======== ======== Accrued dividends $ 331 $ 333 $ 368 ======== ======== ======== Conversion of Penn Octane Corporation note and accrued interest receivable to marketable securities $ 521 $ 1,000 ======== ======== ======== Unrealized gain (loss) on investment in available-for-sale marketable securities ($ 3,071) $ 2,275 $ 2,396 ======== ======== ======== Exchange of oil/gas properties for Delta Petroleum Company common stock $ 1,937 ========

The accompanying notes are an integral part of these consolidated financial statements. F-72 CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND OTHER COMPREHENSIVE INCOME ("$000's" Omitted Except Per Share Amounts)

Year Ended September 30, 2001, 2000 and 1999 --------------------------------------------------------------------------------------------- Accumulated Addi- Other Common Stock tional Compre- Compre- Treasury Stock ------------------ Paid-In hensive hensive Retained ------------------- Shares Amount Capital Income Income (Loss) Earnings Shares Amount Total ---------- ------- ------- ------- ------------- -------- --------- --------- ------- Balance-September 30, 1998 6,803,646 $3,402 $67,122 $34,836 3,862,917 ($53,807) $51,553 Stock acquired 419,300 (6,919) (6,919) Options exercised 25,000 12 243 255 Dividends declared ($.25 per share) (2,048) (2,048) Comprehensive income Net income $ 8,266 8,266 8,266 Other comprehensive income Unrealized gain (loss) on marketable securities, net of tax 2,396 $2,396 2,396 ------- $10,662 ========== ====== ======= ======= ====== ======= ========= ======= ======= Balance-September 30, 1999 6,828,646 3,414 67,365 2,396 41,054 4,282,217 (60,726) 53,503 Stock split ratio retroactively applied 4,675,258 2,338 (2,338) ---------- ------ ------- Balance-September 30, 1999 -restated 11,503,904 5,752 67,365 2,396 38,716 4,282,217 (60,726) 53,503 Stock acquired 508,803 (5,208) (5,208) Dividends declared ($.20 per share) (1,363) (1,363) Comprehensive income Net income $ 5,069 5,069 5,069 Other comprehensive income: Unrealized gain on marketable securities, net of tax 2,275 2,275 2,275 ======= ------ $ 7,344 ---------- ------ ------- ------- ------ ------- --------- ------- ------- Balance-September 30, 2000 11,503,904 5,752 67,365 4,671 42,422 4,791,020 (65,934) 54,276 Stock acquired 80,000 (572) (572) Dividends declared ($.20 per share) (1,322) (1,322) Comprehensive income Net income $1,716 1,716 1,716 Other comprehensive income (loss): Unrealized gain (loss) on marketable securities, net of tax (3,071) (3,071) (3,071) ====== ($1,355) ---------- ------ ------- ======= ------ ------- --------- ------- ------- Balance-September 30, 2001 11,503,904 $5,752 $67,365 $1,600 $42,816 4,871,020 ($66,506) $51,027 ========== ====== ======= ====== ======= ========= ======= =======

The accompanying notes are an integral part of these consolidated financial statements. F-73 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) NOTE 1 - BUSINESS AND ORGANIZATION Business Castle Energy Corporation (the "Company") is a public company incorporated in Delaware. Mr. Joseph L. Castle II, Chairman of the Board and Chief Executive Officer, and his wife own approximately twenty-three percent (23%) of the Company's outstanding common stock at September 30, 2001. The Company's only line of business at September 30, 2001 and at present is oil and gas exploration and production. The Company's operations are conducted in the United States and in Romania. Prior to September 30, 1995, several of the Company's subsidiaries and former subsidiaries were involved in the refining business. These subsidiaries discontinued refining operations effective September 30, 1995; however, several contingencies related to closure of these refining assets are still outstanding. From December 1992 to May 31, 1999, several of the Company's subsidiaries were involved in the natural gas marketing business and from December 1992 to May 1997, another subsidiary was involved in the gas transmission business. In May 1997, the Company sold its gas transmission pipeline. All of the related long-term gas sales and gas purchase contracts applicable to the Company's natural gas marketing business expired by their terms on May 31, 1999. On December 11, 2001, the Company entered into a letter of intent to sell all of its domestic oil and gas properties to another public oil and gas exploration company. See Note 21. References to the Company mean Castle Energy Corporation, the parent, and/or one or more of its subsidiaries. Such references are used for convenience and are not intended to describe legal relationships. Oil and Gas Exploration and Production In June 1999, the Company acquired all of the oil and gas assets of AmBrit Energy Corp. ("AmBrit"). The AmBrit oil and gas assets included interests in approximately 180 wells located in eight states. The proved oil and gas reserves associated with the AmBrit acquisition were estimated to be approximately 12.5 billion cubic feet of natural gas and 2,000,000 barrels of crude oil or approximately one hundred and fifty percent (150%) of the Company's proved reserves before such acquisition. See Note 4. During fiscal 2000, the Company participated in the drilling of nine exploratory wells in south Texas pursuant to two drilling ventures with other exploration and production companies. Eight of the wells drilled resulted in dry holes while the ninth well was completed as a producing well. During fiscal 2000 and 2001, the Company participated in the drilling of five wildcat wells in Romania. Four of the wells drilled resulted in dry holes. The fifth well produced some volumes of natural gas when tested. The Company considered participating in a four well drilling program offsetting the fifth well but F-74 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) has currently decided not to do so because of the current low prices obtainable for production and the potential costs of constructing a pipeline to transport production to potential purchasers. The Company has also agreed to participate in the drilling of a sixth well in the Black Sea in the spring or early summer of 2002. In December 1999, the Company acquired majority interests in twenty-six (26) offshore Louisiana wells. The Company then sold these wells to Delta Petroleum Company ("Delta"), a public company involved in oil and gas exploration and development, in September 2000. In April 2001, the Company consummated the purchase of twenty-one (21) operated producing East Texas oil and gas properties from a private company. See Note 4. Natural Gas Marketing In December 1992, the Company acquired a long-term natural gas sales contract with Lone Star Gas Company ("Lone Star Contract"). The Company also entered into a gas sales contract and one gas purchase contract with MG Natural Gas Corp. ("MGNG"), a subsidiary of MG Corp. ("MG"), which, in turn, is a United States subsidiary of Metallgesellschaft A.G. ("MGAG"), a German conglomerate. In May 1997, the Company sold its Rusk County, Texas natural gas pipeline to a subsidiary of UPRC and thus exited the gas transmission business while still conducting gas marketing operations. Effective May 31, 1999, the aforementioned gas sales and gas purchases contracts expired by their own terms and were not replaced by other third party gas marketing business. Refining IRLP The Company indirectly entered the refining business in 1989 when one of its subsidiaries acquired the operating assets of an idle refinery located in Lawrenceville, Illinois (the "Indian Refinery"). The Indian Refinery was subsequently operated by one of the Company's subsidiaries, Indian Refining I Limited Partnership ("IRLP"), until September 30, 1995 when it was shut down. On December 12, 1995, IRLP sold the Indian Refinery assets to American Western Refining, L.P. ("American Western"). American Western subsequently filed for bankruptcy and sold the Indian Refinery to an outside party which has substantially dismantled it. American Western subsequently filed a Plan of Liquidation which it expects to be confirmed by the governing bankruptcy court in January 2002. If the Plan is confirmed, IRLP expects to receive $612 which it would then distribute to its vendors. F-75 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) Powerine In October 1993, a former subsidiary of the Company purchased Powerine Oil Company ("Powerine"), the owner of a refinery located in Santa Fe Springs, California (the "Powerine Refinery"), from MG. On September 29, 1995, Powerine sold substantially all of its refining plant to Kenyen Projects Limited ("Kenyen"). On January 16, 1996, Powerine merged into a subsidiary of Energy Merchant Corp. ("EMC"), an unaffiliated entity, and EMC acquired the refinery from Kenyen. EMC subsequently sold the refinery to an outside party which, we are informed, continues to seek financing to restart it. As a result of the transactions with American Western, Kenyen and EMC, the Company's refining subsidiaries disposed of their interests in the refining business. The results of refining operations were shown as discontinued operations in the Consolidated Statement of Operations for the year ended September 30, 1995 and retroactively. Discontinued refining operations have not impacted operations since fiscal 1995. Amounts on the balance sheet reflect the remaining assets and liabilities that are pending final resolution of related contingencies. Investment In Networked Energy LLC In August 2000, the Company purchased thirty-five percent (35%) of the membership interests of Networked Energy LLC ("Network") for $500. Network is a private company engaged in the operation of energy facilities that supply power, heating and cooling services directly to retail customers. NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES General The significant accounting policies discussed are limited to those applicable to the business segments in which the Company operated during the fiscal years ended September 30, 2001, 2000 and 1999 - natural gas marketing and transmission and exploration and production. References should be made to previous Forms 10-K for summaries of accounting principles applicable to the discontinued refining segment. Principles of Consolidation The consolidated financial statements presented include the accounts of the Company and all of its subsidiaries. All intercompany transactions have been eliminated in consolidation. Revenue Recognition Natural Gas Marketing Revenues were recorded when deliveries were made. Essentially all of the Company's deliveries were made under two long-term gas sales contracts, the Lone Star Contract and a gas sales contract with MGNG. These contracts expired May 31, 1999. F-76 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) Exploration and Production Oil and gas revenues are recorded under the sales method when oil and gas production volumes are delivered to the purchaser. Reimbursement of costs from well operations is netted against the related oil and gas production expenses. Cash and Cash Equivalents The Company considers all highly liquid investments, such as time deposits and money market instruments, purchased with a maturity of three months or less, to be cash equivalents. Natural Gas Transmission Natural gas transmission assets included gathering systems and pipelines and were depreciated on a straight-line basis over fifteen years, their estimated useful life. Marketable Securities The Company currently classifies its investment securities as available-for-sale securities. Pursuant to Statement of Financial Accounting Standards No. 115 ("SFAS 115"), such securities are measured at fair market value in the financial statements with unrealized gains or losses recorded in other comprehensive income until the securities are sold or otherwise disposed of. At such time gain or loss is included in earnings. Prior to July 1, 1999, the Company classified its investment securities as trading securities and included the difference between cost and fair market value in earnings. Prepaid Gas Purchases Prepaid gas purchases represented payments made by one of the Company's subsidiaries for gas that the subsidiary was required to take but did not. All prepaid gas purchases related to gas purchases from MGNG. Under the terms of the related gas purchase contracts, the subsidiary was entitled to and did make up the prepaid gas, i.e., to take it and not pay for it, once it had taken the required minimum contract volume for the contract year. Prepaid gas purchase costs were expensed as the subsidiary took delivery of the prepaid gas. Furniture, Fixtures and Equipment Furniture, fixtures and equipment are depreciated on a straight-line basis over the estimated useful lives of the assets. Furniture, fixtures and equipment are depreciated on a straight-line basis over periods of three to ten years and rolling stock is depreciated on a straight-line basis over four to five years. F-77 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) Oil and Gas Properties The Company follows the full-cost method of accounting for oil and gas properties and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the acquisition, exploration and development of oil and gas reserves are capitalized. Capitalized costs are amortized on a composite unit-of-production method by country using estimates of proved reserves. Capitalized costs which relate to unevaluated oil and gas properties are not amortized until proved reserves are associated with such costs or impairment of the related property occurs. Management and drilling fees earned in connection with the transfer of oil and gas properties to a joint venture and proceeds from the sale of oil and gas properties are recorded as reductions in capitalized costs unless such sales are material and involve a significant change in the relationship between the cost and the value of the remaining proved reserves, in which case a gain or loss is recognized. None of the joint ventures in which the Company participates are legal entities. The Company accounts for all unincorporated entities involved in oil and gas exploration and production using proportionate gross financial statement presentation. Under the proportionate gross basis, the Company records its shares of assets and liabilities on the balance sheet and related operating data in its income statement. Expenditures for repairs and maintenance of wellhead equipment are expensed as incurred. Net capitalized costs, less related deferred income taxes, in excess of the present value of net future cash inflows (oil and gas sales less production expenses) from proved reserves, tax-effected and discounted at 10%, and the cost of properties not being amortized, if any, are charged to current expense. Amortization and excess capitalized costs, if any, are computed separately for the Company's investment in Romania. Environmental Costs The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future expected economic benefit to the Company. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Environmental liabilities are accrued on an undiscounted basis unless the aggregate amount of the obligation and the amount and timing of the cash payments are fixed and reliably determined for that site. F-78 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) Impairment of Long-Term Assets The Company reviewed its long-term assets other than oil and gas properties for impairment whenever events or changes in circumstances indicated that the carrying amount of an asset may not be recoverable. If the sum of the expected future cash flows expected to result from the use of the asset and its eventual disposition were less than the carrying amount of the asset, an impairment loss would have been recognized. Measurement of an impairment loss would be based on the fair market value of the asset. Impairment for oil and gas properties is computed in the manner described above under "Oil and Gas Properties." The Company currently has no significant long-term assets except for its oil and gas properties, for which impairment is recorded pursuant to full cost accounting as described above. Hedging Activities Natural Gas Marketing The Company used hedging strategies to hedge its future natural gas purchase requirements for its gas sales contracts with Lone Star and MGNG (see Note 1). The Company hedged future commitments using natural gas swaps, which were accounted for on a settlement basis. Gains and losses from hedging activities were included in the item being hedged, the cost of gas purchased for the Lone Star Contract or for the contract with MGNG. In order to qualify as a hedge, the change in fair market value of the hedging instrument had to be highly correlated with the corresponding change in the hedged item. Exploration and Production The Company used hedging strategies to hedge a significant portion of its crude oil and natural gas production through July 31, 2000. The Company used futures contracts to hedge such production. Gains and losses from hedging activities were deferred and debited or credited to the item being hedged, oil and gas sales, when they occurred. In order to qualify as a hedge the change in fair market value of the hedging instrument was highly correlated with the corresponding change in the hedged item. When the hedging instrument ceased to qualify as a hedge, changes in fair value were charged against or credited to earnings. Gas Contracts The purchase price allocated to the Lone Star Contract was capitalized and amortized over the term of the related contract, 6.5 years. Gas Balancing Gas balancing activities have been immaterial during the periods reported. F-79 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) Investment In Networked The Company's investment in Network (the Company owns 35% of Network) is recorded on the equity method. Under this method, the Company records its share of Network's income or loss with an offsetting entry to the carrying value of the Company's investment. Cash distributions, if any, are recorded as reductions in the carrying value of the Company's investment. The Company's investment in Network exceeded the fair value of the Company's share of Network's assets by $350. Such excess (goodwill) is being amortized on a straight-line method over forty (40) years. Comprehensive Income Comprehensive income includes net income and all changes in an enterprise's other comprehensive income including, among other things, unrealized gains and losses on certain investments in debt and equity securities. Stock Based Compensation SFAS 123, "Accounting for Stock-Based Compensation," allows an entity to continue to measure compensation costs in accordance with Accounting Principle Board Opinion No. 25 ("APB 25"). The Company has elected to continue to measure compensation cost in accordance with APB 25 and to comply with the required disclosure-only provisions of SFAS 123. Income Taxes The Company follows Statement of Financial Accounting Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes." SFAS 109 is an accounting approach that requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company's financial statements and tax returns. In estimating future tax consequences, SFAS 109 generally considers all expected future events other than anticipated enactments of changes in the tax law or tax rates. SFAS 109 also requires that deferred tax assets, if any, be reduced by a valuation allowance based upon whether realization of such deferred tax asset is or is not more likely than not. (See Note 17) Earnings Per Share Basic earnings per common share are based upon the weighted average number of common shares outstanding. Diluted earnings per common share are based upon maximum possible dilution calculated using average stock prices during the year. Reclassifications Certain reclassifications have been made to make the periods presented comparable. F-80 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) Use of Estimates The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures 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. New Accounting Pronouncements Statement of Financial Accounting Standards No. 133, as amended, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133"), was issued by the Financial Accounting Standards Board in June 1998. Subsequently, SFAS No. 138 "Accounting for Certain Derivative Instruments" ("SFAS No. 138"), an amendment of SFAS No. 133, was issued. SFAS 133 and SFAS 138 standardize the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. Under the standard, entities are required to carry all derivative instruments in the statement of financial position at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether such instrument has been designated and qualifies as part of a hedging relationship and, if so, depends on the reason for holding it. If certain conditions are met, entities may elect to designate a derivative instrument as a hedge of exposures to changes in fair values, cash flows, or foreign currencies. If the hedged exposure is a fair value exposure, the gain or loss on the derivative instrument is recognized in earnings in the period of change together with the offsetting loss or gain on the hedged item attributable to the risk being hedged. If the hedged exposure is a cash flow exposure, the effective portion of the gain or loss on the derivative instrument is reported initially as a component of other comprehensive income (not included in earnings) and subsequently reclassified into earnings when the forecasted transaction affects earnings. Any amounts excluded from the assessment of hedge effectiveness, as well as the ineffective portion of the gain or loss, is reported in earnings immediately. Accounting for foreign currency hedges is similar to the accounting for fair value and cash flow hedges. If the derivative instrument is not designated as a hedge, the gain or loss is recognized in earnings in the period of change. The Company adopted SFAS No. 133 and SFAS No. 138 effective October 1, 2000. The Company ceased hedging its oil and gas production in July 2000. At September 30, 2001 and 2000, the Company had no freestanding derivative instruments in place and had no embedded derivative instruments. As a result, the Company's adoption of SFAS No. 133 and SFAS No. 138 had no impact on its results of operations or financial condition. Statement of Financial Accounting Standards No. 141, "Business Combinations" ("SFAS No. 141") and Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142") were issued in July 2001. SFAS No. 141 requires that all business combinations entered into subsequent to June 30, 2001 be accounted for under the purchase method of accounting and that certain acquired intangible assets in a business F-81 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) combination be recognized and reported as assets apart from goodwill. SFAS No. 142 requires that amortization of goodwill be replaced with periodic tests of the goodwill's impairment at least annually in accordance with the provisions of SFAS No. 142 and that intangible assets other than goodwill be amortized over their useful lives. The Company adopted SFAS No. 141 in July 2001 and will adopt SFAS No. 142 in the first quarter of fiscal 2003. The Company does not believe that its future adoption of SFAS No. 142 will have a material effect on its results of operations. In June 2001, the FASB issued Statement No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143"), which provides accounting requirements for retirement obligations associated with tangible long-lived assets, including: 1) the timing of liability recognition; 2) initial measurement of the liability; 3) allocation of asset retirement cost to expense; 4) subsequent measurement of the liability; and 5) financial statement disclosures. SFAS No. 143 requires that asset retirement cost be capitalized as part of the cost of the related long-lived asset and subsequently allocated to expense using a systematic and rational method. Any transition adjustment resulting from the adoption of SFAS No. 143 would be reported as a cumulative effect of a change in accounting principle. The Company will adopt the statement effective October 1, 2002. At this time, the Company cannot reasonably estimate the effect of the adoption of this statement on either its financial position or results of operations. In August 2001, the FASB issued Statement No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"), which will be effective for financial statements issued for fiscal years beginning after December 15, 2001 and interim periods within those fiscal years. SFAS No. 144 requires that long-lived assets to be disposed of by sale be measured at the lower of the carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations. SFAS No. 144 broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. After its effective date, SFAS No. 144 will be applied to those transactions where appropriate. The Company will adopt SFAS No 144 effective October 1, 2002. At this time the Company is unable to determine what the future impact of adopting this statement will have on its financial position or results of operations. NOTE 3 - DISCONTINUED REFINING OPERATIONS Effective September 30, 1995, the Company's refining subsidiaries discontinued their refining operations. An analysis of the assets and liabilities related to the refining segment for the period October 1, 1998 to September 30, 2001 is as follows: F-82 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts)

Estimated Realizable Value of Discontinued Net Refining Net Refining Assets Liabilities Retained ------------------- -------------------- Balance - October 1, 1998 $ 3,623 $ 5,129 Reduction in estimated MG SWAP litigation recovery (129) (129) Collection of MG SWAP litigation proceeds (575) (575) Additional recovery in connection with the Powerine Arbitration 900 Reduction in estimated recoverable value of note receivable from American Western (2,119) Adjustment of vendor liabilities (2,119) Other (1) ------- -------- Balance - September 30, 1999 800 3,205 Cash transactions (153) Adjustment of vendor liabilities 152 ------- -------- Balance - September 30, 2000 800 3,204 Cash transactions (80) Adjustment of vendor liabilities 80 Adjustments resulting from American Western's Plan of Liquidation (188) (188) ------- -------- Balance - September 30, 2001 $ 612 $ 3,016 ======= =======

As of September 30, 2001, the estimated realizable value of discontinued net refining assets consists of $612 of estimated recoverable proceeds from the American Western note. The estimated value of net refining liabilities retained consisted of net vendor liabilities of $1,281 and accrued costs related to discontinued refining operations of $2,155, offset by cash of $420. "Estimated realizable value of discontinued net refining assets" is based on the transactions consummated by the Company with American Western and transactions consummated by American Western and IRLP subsequently with others and includes management's best estimates of the amounts expected to be realized upon the complete disposal of the refining segment. "Net refining liabilities retained" includes management's best estimates of amounts expected to be paid and amounts expected to be realized on the settlement of this net liability. The amounts the Company ultimately realizes or pays could differ materially from such amounts. See Notes 12 and 13. F-83 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) NOTE 4 - ACQUISITIONS AND DISPOSITIONS On June 1, 1999, the Company consummated the purchase of all of the oil and gas properties of AmBrit. The oil and gas properties purchased include interests in approximately 180 oil and gas wells in Alabama, Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Texas and Wyoming, as well as undrilled acreage in several of these states. The effective date of the sale for purposes of determining the purchase price was January 1, 1999. The adjusted purchase price after accounting for all transactions between the effective date, January 1, 1999, and the closing date was $20,170. The entire adjusted purchase price was allocated to "Oil and Gas Properties - Proved Properties". Based upon reserve reports initially prepared by the Company's petroleum reservoir engineers, the proved reserves (unaudited) associated with the AmBrit oil and gas assets approximated 2,000,000 barrels of crude oil and 12,500,000 mcf (thousand cubic feet) of natural gas, which, together, approximated 150% of the Company's oil and gas reserves before the acquisition. In addition, the production acquired initially increased the Company's consolidated production by approximately 425%. The results of operations on a pro-forma basis as though the oil and gas properties of AmBrit had been acquired as of the beginning of the periods indicated are as follows: Year Ended September 30, 1999 ----------------------------- (Unaudited) Revenues $62,719 Net income $ 7,958 Net income per share $ .95 Shares outstanding (diluted) 8,347,932 These proforma results are presented for comparative purposes only and are not necessarily indicative of the results which would have been obtained had the acquisition been consummated as presented. Operations related to the AmBrit oil and gas properties have been included in the Company's Consolidated Statements of Operations since June 1, 1999, the closing date of the AmBrit acquisition. Investment in Drilling Joint Ventures In fiscal 1999, the Company entered into two drilling ventures to participate in the drilling of up to sixteen exploratory wells in south Texas. F-84 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) During fiscal 2000, the Company participated in the drilling of nine exploratory wells pursuant to the related joint venture operating agreements. Eight wells drilled resulted in dry holes and one well was completed as a producer. The Company has no further drilling obligations under these joint ventures and has terminated participation in each drilling venture. The total cost incurred to participate in the drilling of the exploratory wells was $6,003. Offshore Louisiana Property Acquisition In December 1999, a subsidiary of the Company purchased majority interests in twenty-six offshore Louisiana wells from Whiting Petroleum Company ("Whiting"), a public company engaged in oil and gas exploration and development. The adjusted purchase price was $890. In September 2000, the subsidiary of the Company sold its interests in the offshore Louisiana wells to Delta. The effective date of the sale was July 1, 2000. The adjusted purchase price of $3,059 consisted of $1,122 cash plus 382,289 shares of Delta's common stock valued at the market price or $1,937 (see Note 8). Investment in Romanian Concessions In April 1999, the Company purchased an option to acquire a fifty percent (50%) interest in three oil and gas concessions granted to a subsidiary of Costilla Energy Corporation ("Costilla"), a public oil and gas exploration and production company, by the Romanian government. The Company paid Costilla $65 for the option. In May 1999, the Company exercised the option. As of September 30, 2001, the Company had participated in the drilling of five onshore wildcat wells. Four of those wells resulted in dry holes. Although the fifth well produced some volumes of natural gas when tested, the Company has not been able to obtain a sufficiently high gas price to justify future production and has elected at the present not to undertake an offset drilling program where the fifth well was drilled. As a result, the Company recorded impairment provisions of $2,765 and $832 for the years ended September 30, 2001 and 2000, respectively, for costs incurred for the five onshore wells. The Company has agreed to participate in the drilling of a sixth well, offshore, in the Black Sea in the spring or early summer of 2002. See Note 10. Other Exploration and Production Investments In November and December 1999, the Company acquired additional outside interests in several Alabama and Pennsylvania wells, which it operates, for $2,580. F-85 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) East Texas Property Acquisition On April 30, 2001, the Company consummated the purchase of several East Texas oil and gas properties from a private company. The effective date of the purchase was April 1, 2001. These properties included majority interests in twenty-one (21) operated producing oil and gas wells and interests in approximately 6,500 gross acres in three counties in East Texas. The Company estimates the proved reserves acquired were approximately 12.5 billion cubic feet of natural gas and 191,000 barrels of crude oil. The consideration paid, net of purchase price adjustments, was $10,040. The Company used its own internally generated funds to make the purchase. NOTE 5 - RESTRICTED CASH Restricted cash consists of the following:

September 30, ------------- 2001 2000 ---- ------ Funds supporting letters of credit for offshore Louisiana wells $1,519 Drilling deposits in escrow - Romania $ 7 4 Funds supporting letters of credit issued for operating bonds 209 219 Funds escrowed for litigation settlement 154 ----- ------ $ 370 $1,742 ===== ======

The drilling deposits in escrow in Romania are to be used only to conduct exploratory drilling activities in Romania and cannot be withdrawn or used for other purposes by the Company. The funds escrowed for litigation settlement pertain to Larry Long Litigation (see Note 13). NOTE 6 - ACCOUNTS RECEIVABLE Based upon past customer experiences, the limited number of customer accounts receivable relationships, and the fact that the Company's subsidiaries can generally offset unpaid accounts receivable against an outside owner's share of oil and gas revenues, management believes substantially all receivables are collectible. All of the Company's accounts receivable at September 30, 2001 and 2000 consisted of exploration and production trade receivables. F-86 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) NOTE 7 - NOTE RECEIVABLE - PENN OCTANE In January 2000, the Company invested $500 in a note due from Penn Octane Corporation ("Penn Octane"), a public company involved in the sale of liquid propane gas into Mexico. The note was originally due on December 15, 2000 and bore interest at 9%, payable quarterly. In December 2000, the Company agreed to extend the note until June 15, 2002. In return, Penn Octane increased the interest rate on the note to 13.5% and issued to the Company warrants to acquire an additional 62,500 shares of Penn Octane common stock at $3.00 per share. Subsequently, the interest rate was increased to 16.5% and the exercise price on the 62,500 options issued was reduced to $2.50 per share. Effective September 14, 2001, the Company exercised options to acquire 275,933 shares of common stock of Penn Octane by exchanging its $500 note plus $21 of accrued interest for the shares. NOTE 8 - MARKETABLE SECURITIES The Company's investment in marketable securities consists of common shares of Penn Octane, Delta and Chevron/Texaco. At September 30, 1998, the Company accounted for its investment as trading securities. In March 1999, the Company began to account for its investment as available-for-sale securities. The Company's investments in Penn Octane, Delta and Chevron/Texaco common stock and options to buy Penn Octane stock were as follows: Common Stock ------------ Penn Octane Delta Chevron/Texaco Total ----------- ----- -------------- ----- September 30, 2001: Cost $2,271 $1,937 $14 $ 4,222 Unrealized gain (loss) 3,308 (808) 2,500 ------ ------ --- ------- Book value (market value) $5,579 $1,129 $14 $ 6,722 ====== ====== === ======= September 30, 2000: Cost $1,750 $1,937 $ 3,687 Unrealized gain 7,298 7,298 ------ ------ ------- Book value (market value) $9,048 $1,937 $10,985 ====== ====== ======= The fair market values of Penn Octane, Delta and Chevron/Texaco shares were based on one hundred percent (100%) of the closing price on September 28, 2001, the last trading day in the Company's fiscal year ending September 30, 2001. F-87 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) At September 30, 2001 and 2000, the fair market values of the Penn Octane shares include $164 and $1,641, respectively, related to options to acquire Penn Octane common stock held by the Company. The value of such options was computed using the Black-Scholes method (see Note #16). The Company owned 1,343,600 shares of Penn Octane, 382,289 shares of Delta and 177 shares of Chevron/Texaco at September 30, 2001. Of these 501,000 shares of Penn Octane and all 177 shares of Chevron/Texaco were registered. The remaining shares are either in the process of being registered or the Company has registration rights with respect to such shares. At September 30, 2001, the Company also owned options to purchase 74,067 common shares of Penn Octane common stock at $2.50 per share. At September 30, 2000, the Company owned 1,067,667 shares of Penn Octane and 382,289 shares of Delta, as well as options to purchase 454,167 common shares of Penn Octane at exercise prices of $1.75 to $6.00 per share. NOTE 9 - FURNITURE, FIXTURES AND EQUIPMENT Furniture, fixtures and equipment are as follows: September 30, ----------------- 2001 2000 ---- ---- Cost: Furniture and fixtures $ 693 $ 660 Automobile and trucks 269 222 ----- ----- 962 882 Accumulated depreciation (740) (624) ----- ----- $ 222 $ 258 ===== ===== F-88 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) NOTE 10 - OIL AND GAS PROPERTIES (Unaudited) Oil and gas properties consist of the following:

September 30, 2001 ------------------ United States Romania Total ------ ------- ------- Proved properties $56,100 $56,100 Less: Accumulated depreciation, depletion and amortization (16,257) (16,257) ------- ------- Proved properties 39,843 39,843 Unproved properties not being amortized $ 3,707 3,707 Impairment of unproved properties ------- (3,597) (3,597) ------- ------- $39,843 $ 110 $39,953 ======= ====== =======

September 30, 2000 ------------------ United States Romania Total ------ ------- ------- Proved properties $42,127 $42,127 Less: Accumulated depreciation, depletion and amortization (12,909) (12,909) ------- ------- Proved properties 29,218 29,218 Unproved properties not being amortized $2,279 2,279 Impairment of unproved properties (832) (832) ------- ------ ------- $29,218 $1,447 $30,665 ======= ====== =======

F-89 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) Capital costs incurred by the Company in oil and gas activities are as follows:

Year Ended September 30, ------------------------ 2001 2000 ---- ---- United United States Romania Total States Romania Total ------ ------- ----- ------ ------- ----- Acquisition of properties: Proved properties $10,002 $10,002 $ 3,642 $ 3,642 Unproved properties 346 346 678 $ 999 1,677 Exploration 1,560 $1,428 2,988 2,966 346 3,312 Development 2,113 2,113 2,595 2,595 ------- ------ ------- ------- ------- ------- $14,021 $1,428 $15,449 $ 9,881 $ 1,345 $11,226 ======= ====== ======= ======= ======= =======

September 30, 1999 ------------------ United States Romania Total ------ ------- ------- Acquisition of properties Proved properties $21,029 $21,029 Unproved properties 928 $ 934 1,862 Development 1,073 1,073 ------- ------ ------- $23,030 $ 934 $23,964 ======= ====== =======

For the years ended September 30, 1999, 2000 and 2001, the Company incurred development costs related to booked proved undeveloped reserves of $733, $2,324 and $1,347 respectively. F-90 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) Results of operations, excluding corporate overhead and interest expense, from the Company's oil and gas producing activities are as follows:

Year Ended September 30, ------------------------ 2001 2000 1999 ---- ---- ---- Revenues: Crude oil, condensate, natural gas liquids and natural gas sales $21,144 $17,959 $6,712 ------- ------- ------ Costs and expenses: Production costs $ 7,399 $ 6,194 1,910 Depreciation, depletion and amortization 3,348 2,990 1,937 Impairment of foreign unproved properties 2,765 832 ------- ------- ------ Total costs and expenses 13,512 10,016 3,847 ------- ------- ------ Income tax provision (benefit) 1,387 (6,553) 753 ------- ------- ------ Income from oil and gas producing activities $ 6,245 $16,569 $2,112 ======= ======= =======

The income tax provision is computed at the effective tax rate for the related fiscal year. F-91 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) Assuming conversion of oil and gas production into common equivalent units of measure on the basis of energy content, depletion rates per equivalent MCF (thousand cubic feet) of natural gas were as follows: Year Ended September 30, ------------------------ 2001 2000 1999 ---- ---- ---- Depletion rate per equivalent MCF of natural gas $0.72 $0.57 $0.71 ====- ===== ===== The increase in the depletion rate in fiscal 2001 resulted primarily because the Company's reserves qualitites decreased significantly as a result of lower oil and gas prices at September 30, 2001. The decrease in reserve quantities without a similar decrease in related costs resulted in a higher depletion rate. In addition, in fiscal 2001, the Company acquired significant East Texas reserves at a higher cost per mcfe than the cost for the Company's existing reserves at the time of the acquisition (see Note 4). The decrease in the depletion rate in fiscal 2000 resulted primarily because the Company's reserve quantities increased significantly as a result of higher oil and gas prices at September 30, 2000. The increase in reserve quantities without a similar increase in costs resulted in the lower depletion rate. Under the full cost method of accounting, the net book value of oil and gas properties less related deferred income taxes (the "costs to be recovered"), may not exceed a calculated "full cost ceiling." The ceiling limitation is the discounted estimated after-tax future net revenues from oil and gas properties. The ceiling is imposed separately by country. In calculating future net revenues, current prices and costs are generally held constant indefinitely. The costs to be recovered are compared to the ceiling on a quarterly basis. If the costs to be recovered exceed the ceiling, the excess is written off as an expense, except as discussed in the following paragraph. If, subsequent to the end of the reporting period, but prior to the applicable financial statements being published, prices increase to levels such that the ceiling would exceed the costs to be recovered, a write down otherwise indicated at the end of the reporting period is not required to be reported. A write down indicated at the end of a reporting period is also not required if the value of additional reserves proved up on properties after the end of the reporting period, but prior to the publishing of the financial statements, would result in the ceiling exceeding the costs to be recovered, as long as the properties were owned at the end of the reporting period. F-92 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period. Based on oil and natural gas cash market prices as of September 30, 2001, the Company's costs to be recovered for its domestic reserves exceeded the related ceiling values by $437. However, the cash market prices of natural gas subsequently increased significantly. Based on cash market prices of oil and natural gas as at December 18, 2001, the Company determined that there was no impairment of its domestic oil and gas properties. Accordingly, the Company did not record a reduction in the carrying value of its domestic oil and gas properties at September 30, 2001. See Note 21. NOTE 11 - PROVED OIL AND GAS RESERVES AND RESERVE VALUATION (UNAUDITED) Reserve estimates are based upon subjective engineering judgements made by the Company's independent petroleum reservoir engineers, Huntley & Huntley and Ralph E. Davis Associates, Inc. and may be affected by the limitations inherent in such estimations. The process of estimating reserves is subject to continuous revisions as additional information is made available through drilling, testing, reservoir studies and production history. There can be no assurance such estimates will not be materially revised in subsequent periods. Estimated quantities of proved reserves and changes therein, all of which are domestic reserves, are summarized below: F-93 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) ("000's" Omitted) Oil (BBLS) Natural Gas (MCF) ---------- ----------------- Proved developed and undeveloped reserves: As of October 1, 1998 255 15,324 Acquisitions 2,021 12,529 Revisions of previous estimates (122) 2,520 Production (124) (1,971) ------ ------- As of September 30, 1999 2,030 28,402 Acquisitions 1,063 6,639 Divestitures (974) (236) Discoveries 1 317 Revisions of previous estimates 2,894 12,728 Production (279) (3,547) ------ ------- As of September 30, 2000 4,735 44,303 Acquisitions 266 10,183 Revisions of previous estimates (1,730) (20,711) Production (262) (3,083) ------ ------- As of September 30, 2001 3,009 30,692 ====== ======= Proved developed reserves: September 30, 1998 162 13,589 ====== ======= September 30, 1999 1,788 23,547 ====== ======= September 30, 2000 2,963 35,815 ====== ======= September 30, 2001 1,890 26,480 ====== ======= Although the Company has participated in the drilling of five exploratory wells in Romania, no proved reserves have yet been assigned to any of these wells. As a result, all of the Company's proved oil and gas reserves are located in the United States. The following is a standardized measure of discounted future net cash flows and changes therein relating to estimated proved oil and gas reserves, as prescribed in Statement of Financial Accounting Standards No. 69. The standardized measure of discounted future net cash flows does not purport to present the fair market value of the Company's oil and gas properties. An estimate of fair value would also take into account, among other factors, the likelihood of future recoveries of oil and gas in excess of proved reserves, anticipated future changes in prices of oil and gas and related development and production costs, a discount factor based on market interest rates in effect at the date of valuation and the risks inherent in reserve estimates. F-94 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts)

September 30, ------------- 2001 2000 1999 -------- -------- -------- Future cash inflows $130,289 $371,784 $118,794 Future production costs (41,193) (87,162) (42,934) Future development costs (8,585) (12,620) (4,229) Future income tax expense (10,892) (84,445) (8,538) -------- -------- -------- Future net cash flows 69,619 187,557 63,093 Discount factor of 10% for estimated timing of future cash flows (33,599) (96,438) (21,849) -------- -------- -------- Standardized measure of discounted future cash flows $ 36,020 $ 91,119 $ 41,244 ======== ======== ========

The future cash flows were computed using the applicable year-end prices and costs that related to then existing proved oil and gas reserves in which the Company has interests. The estimates of future income tax expense are computed at the blended rate (Federal and state combined) of 36%. The following were the sources of changes in the standardized measure of discounted future net cash flows:

September 30, 2001 2000 1999 -------- -------- -------- Standardized measure, beginning of year $ 91,119 $ 41,244 $ 9,946 Sale of oil and gas, net of production costs (13,745) (11,083) (4,324) Net changes in prices (62,271) 45,757 2,163 Sale of reserves in place (1,457) Purchase of reserves in place 7,662 6,757 22,215 Changes in estimated future development costs 1,518 (5,039) 2,405 Development costs incurred during the period that reduced future development costs 2,113 2,595 1,073 Revisions in reserve quantity estimates (27,596) 76,355 1,438 Discoveries of reserves 963 Net changes in income taxes 31,054 (32,031) 745 Accretion of discount 9,112 4,286 995 Other: Change in timing of production (944) (36,168) 12,055 Other factors (2,002) (1,060) (7,467) -------- -------- -------- Standardized measure, end of year $ 36,020 $ 91,119 $ 41,244 ======== ======== ========

The Company estimates that it will spend approximately $5,678, $35 and $0 to develop booked proved undeveloped reserves in the fiscal years ended September 30, 2002, 2003 and 2004, respectively. F-95 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) NOTE 12 - CONTINGENT ENVIRONMENTAL LIABILITY In December 1995, IRLP, an inactive subsidiary of the Company, sold its refinery, the Indian Refinery, to American Western, an unaffiliated party. As part of the related purchase and sale agreement, American Western assumed all environmental liabilities and indemnified IRLP with respect thereto. Subsequently, American Western filed for bankruptcy and sold the Indian Refinery to an outside party pursuant to a bankruptcy proceeding. The outside party has substantially dismantled the Indian Refinery. American Western recently filed a Plan of Liquidation. American Western anticipates that the Plan of Liquidation will be confirmed in January 2002. During fiscal 1998, the Company was informed that the United States Environmental Protection Agency ("EPA") had investigated offsite acid sludge waste found near the Indian Refinery and had investigated and remediated surface contamination on the Indian Refinery property. Neither the Company nor IRLP was initially named with respect to these two actions. In October 1998, the EPA named the Company and two of its inactive refining subsidiaries as potentially responsible parties for the expected clean-up of the Indian Refinery. In addition, eighteen other parties were named including Texaco Refining and Marketing, Inc. ("Texaco"), the refinery operator for over 50 years. A subsidiary of Texaco had owned the refinery until December of 1988. The Company subsequently responded to the EPA indicating that it was neither the owner nor the operator of the Indian Refinery and thus not responsible for its remediation. In November 1999, the Company received a request for information from the EPA concerning the Company's involvement in the ownership and operation of the Indian Refinery. The Company responded to the EPA information request in January 2000. On August 7, 2000, the Company received notice of a claim against it and two of its inactive refining subsidiaries from Texaco and its parent. Texaco had made no previous claims against the Company although the Company's subsidiaries had owned the refinery from August 1989 until December 1995. In its claim, Texaco demanded that the Company and its former subsidiaries indemnify Texaco for all liability resulting from environmental contamination at and around the Indian Refinery. In addition, Texaco demanded that the Company assume Texaco's defense in all matters relating to environmental contamination at and around the Indian Refinery, including lawsuits, claims and administrative actions initiated by the EPA and indemnify Texaco for costs that Texaco has already incurred addressing environmental contamination at the Indian Refinery. Finally, Texaco also claimed that the Company and two of its inactive subsidiaries are liable to Texaco under the Federal Comprehensive Environmental Response Compensation and Liability Act as owners and operators of the Indian Refinery. The Company responded to Texaco disputing the factual and theoretical basis for Texaco's claims against the Company. The Company's management and special counsel subsequently met with representatives of Texaco but the parties disagreed concerning Texaco's claims. F-96 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) The Company and its special counsel, Reed Smith, LLP, believe that Texaco's claims are utterly without merit and the Company intends to vigorously defend itself against Texaco's claims and any lawsuits that may follow. In addition to the numerous defenses that the Company has against Texaco's contractual claim for indemnity, the Company and its special counsel believe that by the express language of the agreement which Texaco construes to create an indemnity, Texaco has irrevocably elected to forgo all rights of contractual indemnification it might otherwise have had against any person, including the Company. In September 1995, Powerine sold the Powerine Refinery to Kenyen Resources ("Kenyen"), an unaffiliated party. In January 1996, Powerine merged into a subsidiary of Energy Merchant Corp. ("EMC"), an unaffiliated party, and EMC assumed all environmental liabilities. In August 1998, EMC sold the Powerine Refinery to a third party, which, we are informed, continues to seek financing to restart the Powerine Refinery. In July of 1996, the Company was named a defendant in a class action lawsuit concerning emissions from the Powerine Refinery. In April of 1997, the court granted the Company's motion to quash the plaintiff's summons based upon lack of jurisdiction and the Company is no longer involved in the case. Although the environmental liabilities related to the Indian Refinery and Powerine Refinery have been transferred to others, there can be no assurance that the parties assuming such liabilities will be able to pay them. American Western, owner of the Indian Refinery, filed for bankruptcy and is in the process of liquidation. EMC, which assumed the environmental liabilities of Powerine, sold the Powerine Refinery to an unrelated party, which we understand is still seeking financing to restart that refinery. Furthermore, as noted above, the EPA named the Company as a potentially responsible party for remediation of the Indian Refinery and has requested and received relevant information from the Company. Estimated gross undiscounted clean up costs for this refinery are at least $80,000 - $150,000 according to third parties. If the Company were found liable for the remediation of the Indian Refinery, it could be required to pay a percentage of the clean-up costs. Since the Company's subsidiary only operated the Indian Refinery five years, whereas Texaco and others operated it over fifty years, the Company would expect that its share of remediation liability would be proportional to its years of operation, although such may not be the case. Furthermore, as noted above, Texaco has claimed that the Company indemnified it for all environmental liabilities related to the Indian Refinery. If Texaco were to sue the Company on this theory and prevail in court, the Company could be held responsible for the entire estimated clean up costs of $80,000-$150,000 or more. In such a case, this cost would be far in excess of the Company's financial capability. An opinion issued by the U.S. Supreme Court in June 1998 in the comparable matter of United States v. Bestfoods, 524 U.S. 51, 118 S.Ct 1876 (1998), and a recent opinion by the U.S. Appeals Court for the Fifth Circuit in Aviall Services, Inc. v. Cooper Industries, Inc. 263 F.3rd 134 (5th Cir. 2001) vacated and reh'g granted 278 F.3rd 416 (Dec. 19, 2001) support the Company's positions. Nevertheless, if funds for environmental clean-up are not provided F-97 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) by these former and/or present owners, it is possible that the Company and/or one of its former refining subsidiaries could be named parties in additional legal actions to recover remediation costs. In recent years, government and other plaintiffs have often sought redress for environmental liabilities from the party most capable of payment without regard to responsibility or fault. Whether or not the Company is ultimately held liable in such a circumstance, should litigation involving the Company and/or IRLP occur, the Company would probably incur substantial legal fees and experience a diversion of management resources from other operations. Although the Company does not believe it is liable for any of its subsidiaries' clean-up costs and intends to vigorously defend itself in such regard, the Company cannot predict the ultimate outcome of these matters due to inherent uncertainties. NOTE 13 - COMMITMENTS, CONTINGENCIES AND LINE OF CREDIT Operating Lease Commitments The Company has the following noncancellable operating lease commitments and noncancellable sublease rentals at September 30, 2001: Lease Sublease Year Ending September 30, Commitments Rentals ------------------------- ----------- -------- 2002 $ 473 $ 65 2003 470 66 2004 240 2005 76 --------- ------- 2006 $ 1,259 $ 131 ========= ======= Rent expense for the years ended September 30, 2001, 2000 and 1999 was $456, $412 and $386, respectively. Severance/Retention Obligations The Company has severance agreements with substantially all of its employees, including five of its officers, that provide for severance compensation in the event substantially all of the Company's or its subsidiaries' assets are sold and the employees are terminated as a result of such sale. Such termination severance commitments aggregated $1,101 at September 30, 2001. No severance obligations were owed to employees at September 30, 2001. F-98 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) Letters of Credit At September 30, 2001, the Company had issued letters of credit of $209 for oil and gas drilling, operating and plugging bonds. The letters of credit are renewed semi-annually or annually. Line of Credit See Note 21. Legal Proceedings Contingent Environmental Liabilities See Note 12. General Long Trusts Lawsuit In November 2000, the Company and three of its subsidiaries were defendants in a jury trial in Rusk County, Texas. The plaintiffs in the case, the Long Trusts, are non-operating working interest owners in wells previously operated by Castle Texas Production Limited Partnership ("CTPLP"), an inactive exploration and production subsidiary of the Company. The wells were among those sold to Union Pacific Resources Corporation ("UPRC") in May 1997. The Long Trusts claimed that CTPLP did not allow them to sell gas from March 1, 1996 to January 31, 1997 as required by applicable joint operating agreements, and they sued CTPLP and the other defendants, claiming (among other things) breach of contract, breach of fiduciary duty, conversion and conspiracy. The plaintiffs sought actual damages, exemplary damages, pre-judgment and post-judgment interest, attorney's fees and court costs. CTPLP counterclaimed for approximately $150 of unpaid joint interests billings, interest, attorneys' fees and court costs. After a three-week trial, the District Court in Rusk County submitted 36 questions to the jury which covered all of the claims and counterclaims in the lawsuit. Based upon the jury's answers, the District Court entered judgement granting plaintiffs' claims against the Company and its subsidiaries, as well as CTPLP's counterclaim against the plaintiffs. The District Court issued an amended judgement on September 5, 2001, which became final in December 2001. The net amount awarded to the plaintiffs was approximately $2,700. The Company and its subsidiaries have filed a notice of appeal with the Tyler Court of Appeals and will continue to vigorously contest this matter. Jenkens and Gilchrest, special counsel to the Company does not consider an unfavorable outcome to this lawsuit probable. The Company's management and special counsel believe that several of the plaintiffs' primary F-99 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) legal theories are contrary to established Texas law and that the Court's charge to the jury was fatally defective. They further believe that any judgment for plaintiffs based on those theories or on the jury's answers to certain questions in the charge cannot stand and will be reversed on appeal. As a result, the Company has not accrued any liability for this litigation. Nevertheless, to pursue the appeal, the Company and its subsidiaries will be required to post a bond to cover the net amount of damages awarded to the plaintiffs and to maintain that bond until the resolution of the appeal (which may take several years). The Company has included the letter of credit to support the bond, estimated at approximately $3,000, in its line of credit with a major energy bank. See Note 21. Larry Long Litigation In May 1996, Larry Long, representing himself and allegedly "others similarly situated," filed suit against the Company, three of the Company's natural gas marketing and transmission and exploration and production subsidiaries, Atlantic Richfield Company ("ARCO"), B&A Pipeline Company, a former subsidiary of ARCO ("B&A"), and MGNG in the Fourth Judicial District Court of Rusk County, Texas. The plaintiff originally claimed, among other things, that the defendants underpaid non-operating working interest owners, royalty interest owners and overriding royalty interest owners with respect to gas sold to Lone Star pursuant to the Lone Star Contract. Although no amount of actual damages was specified in the plaintiff's initial pleadings, it appeared that, based upon the volumes of gas sold to Lone Star, the plaintiff may have been seeking actual damages in excess of $40,000. After some initial discovery, the plaintiff's pleadings were significantly amended. Another purported class representative, Travis Crim, was added as a plaintiff, and ARCO, B&A and MGNG were dropped as defendants. Although it is not completely clear from the amended petition, the plaintiffs apparently limited their proposed class of plaintiffs to royalty owners and overriding royalty owners in leases owned by the Company's exploration and production subsidiary limited partnership. In amending their pleadings, the plaintiffs revised their basic claim to seeking royalties on certain operating fees paid by Lone Star to the Company's natural gas marketing subsidiary limited partnership. In April 2000, Larry Long withdrew as a named plaintiff and in September 2000, the Company and the remaining named plaintiff agreed to settle the case for a payment of $250 by the Company. In July 2001, the Company deposited $250 plus accrued interest of $9 in a litigation settlement account. As of September 30, 2001, $106 had been disbursed from the account. See Note 21. F-100 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) MGNG Litigation On May 4, 1998, CTPLP, a subsidiary of the Company, filed a lawsuit against MGNG and MG Gathering Company ("MGC"), two subsidiaries of MG, in the district court of Harris County, Texas. One of the Company's exploration and production subsidiaries sought to recover gas measurement and transportation expenses charged by the defendants in breach of a certain gas purchase contract. Improper charges exceeded $750 before interest. In October of 1998, MGNG and MGC filed a suit in Harris County, Texas. This suit sought indemnification from two of the Company's subsidiaries in the event CTPLP won its lawsuit against MGNG and MGC. The MG entities cited no basis for their claim of indemnification. The management of the Company and special counsel retained by the Company believe that the Company's subsidiary is entitled to at least $750 plus interest and that the Company's two subsidiaries have no indemnification obligations to MGNG or MGC. The parties participated in mediation but were not able to resolve the issue. In October 1999, MGNG filed a second lawsuit against the Company and three of its subsidiaries claiming $772 was owed to MGNG under a gas supply contract between one of the Company's subsidiaries and MGNG. The suit was filed in the district court of Harris County, Texas. The Company and its subsidiaries believed that they do not owe $772 and were entitled to legally offset some or all of the $772 claimed against amounts owed to CTPLP by MGNG for improper gas measurement and transportation deductions. The Castle entities answered this suit denying MGNG's claims based partially on the right of offset. In September 2000, the parties agreed to settle all lawsuits. Under the terms of the settlement the amount claimed by MGNG under a gas supply contract was reduced by $325 and the net amount payable to MGNG was set at $400 and the parties signed mutual releases. See Note 21. Pilgreen Litigation As part of the AmBrit purchase, Castle Exploration Company, Inc. ("CECI") acquired a 10.65% overriding royalty interest ("ORRI") in the Pilgreen #2ST gas well in Texas. Because of title disputes, AmBrit and other interest owners had previously filed claims against the operator of the Pilgreen well, and CECI acquired post January 1, 1999 rights in that litigation. Although revenue attributed to the ORRI has been suspended by the operator since first production, because of recent related appellate decisions and settlement negotiations, the Company believes that revenue attributable to the ORR should be released to CECI in the near future. As of September 30, 2001, approximately $415 attributable to CECI's share of the ORRI revenue was suspended. The Company's policy is to recognize the suspended revenue only when and if it is received. F-101 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) GAMXX On February 27, 1998, the Company entered into an agreement with Alexander Allen, Inc. ("AA") concerning amounts owed to the Company by AA and its subsidiary, GAMXX Energy, Inc. ("GAMXX"). The Company had made loans to GAMXX through 1991 in the aggregate amount of approximately $8,000. When GAMXX was unable to obtain financing, the Company recorded a one hundred percent loss provision on its loans to GAMXX in 1991 and 1992 while still retaining its lender's lien against GAMXX. Pursuant to the terms of the GAMXX Agreement, the Company was to receive $1,000 cash in settlement for its loans when GAMXX closed on its financing. GAMXX expected such closing not later than May 31, 1998 but failed to do so. As a result, the Company elected to terminate the GAMXX Agreement. Pursuant to the Agreement, GAMXX agreed to assist the Company in selling GAMXX's assets or the Company's investment in GAMXX. The Company is currently seeking to dispose of its lender's interest in GAMXX and recover some of the loan to GAMXX. The Company has carried its loans to GAMXX at zero for the last eight years. The Company will record any proceeds as "other income" if and when it collects such amount. Hedging Activities Until June 1, 1999, the Company's natural gas marketing subsidiary utilized natural gas swaps to reduce its exposure to changes in the market price of natural gas. Effective May 31, 1999 all natural gas marketing contracts terminated by their own terms. As a result of these hedging transactions, the cost of gas purchases increased $609 for the year ended September 30, 1999. On June 1, 1999, the Company acquired all of the oil and gas assets of AmBrit (see Note 4) and thereafter commenced hedging sales of the related oil and gas production. As of September 30, 1999, the Company had hedged approximately 54% of its anticipated consolidated crude oil production and approximately 39% of its anticipated consolidated natural gas production for the period from October 1, 1999 to September 30, 2000. The Company used futures contracts to hedge such production. The average hedged prices for crude oil and natural gas, which are based upon futures price on the New York Mercantile Exchange, were $19.85 per barrel of crude oil and $2.66 per mcf of gas. The Company accounted for these futures contracts as hedges and the differences between the hedged price and the exchange price increased or decreased the oil and gas revenues resulting from the sale of production by the Company. Oil and gas production was not hedged after July 2000 production. As a result of these hedging transactions, oil and gas sales decreased $1,528 and $150 for the fiscal years ended September 30, 2000 and 1999, respectively. F-102 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) At September 30, 2001 and December 14, 2001, the Company had not hedged its anticipated future oil and gas production. NOTE 14 - EMPLOYEE BENEFIT PLAN 401(K)plan On October 1, 1995, the Company adopted a 401(k) plan (the "Plan") for its employees and those of its subsidiaries. All employees are eligible to participate. Employees participating in the Plan can authorize the Company to contribute up to 15% of their gross compensation to the Plan. The Company matches such voluntary employee contributions up to 3% of employee gross compensation. Employees' contributions to the Plan cannot exceed thresholds set by the Secretary of the Treasury. Vesting of Company contributions is immediate. During the years ended September 30, 2001, 2000 and 1999, the Company's contributions to the Plan aggregated $50, $46 and $37, respectively. Post-Retirement Benefits Neither the Company nor its subsidiaries provide any other post-retirement plans for employees. NOTE 15 - STOCKHOLDERS' EQUITY On December 29, 1999, the Company's Board of Directors declared a stock split in the form of a 200% stock dividend applicable to all stockholders of record on January 12, 2000. The additional shares were paid on January 31, 2000 and the Company's shares first traded at post-split prices on February 1, 2000. The stock split applied only to the Company's outstanding shares on January 12, 2000 (2,337,629 shares) and did not apply to treasury shares (4,491,017 shares) on that date. As a result of the stock split, 4,675,258 additional shares were issued and the Company's common stock book value was increased $2,338 to reflect additional par value applicable to the additional shares issued to effect the stock split. All share changes, including those affecting the recorded book value of common stock, have been recorded retroactively. From November 1996 until September 30, 2001, the Company's Board of Directors authorized the Company to purchase up to 5,267,966 of its outstanding shares of common stock on the open market. As of September 30, 2001, 4,871,020 shares (13,973,054 shares before taking into account the 200% stock dividend effective January 31, 2000) had been repurchased at a cost of $66,506. The repurchased shares are held in treasury On June 30, 1997, the Company's Board of Directors approved a dividend policy of $.20 per share per year, payable quarterly. The dividend policy remains in effect until rescinded or changed by the Board of Directors. Quarterly dividends of $.05 per share have subsequently been paid. See Note 21 F-103 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) NOTE 16 - STOCK OPTIONS AND WARRANTS Option and warrant activities during each of the three years ended September 30, 2001 are as follows (in whole units):

Incentive Plan Options Options Total --------- ------- --------- Outstanding at October 1, 1998 195,000 20,000 215,000 Issued 15,000 15,000 Exercised (25,000) (25,000) Repurchased (10,000) (10,000) --------- ------- --------- Outstanding at September 30, 1999 175,000 20,000 195,000 Effect of 200% stock dividend (see Note 15) 350,000 40,000 390,000 Issued 105,000 105,000 --------- ------- --------- Outstanding at September 30, 2000 630,000 60,000 690,000 Issued 60,000 60,000 --------- ------- --------- Outstanding at September 30, 2001 690,000 60,000 750,000 Exercisable at September 30, 2001 690,000 60,000 750,000 ========= ======= ========= Reserved at September 30, 2001 1,687,500 60,000 1,747,500 ========= ======= ========= Reserved at September 30, 2000 1,687,500 60,000 1,747,500 ========= ======= ========= Reserved at September 30, 1999 1,687,500 60,000 1,747,500 ========= ======= ========= Exercise prices at: September 30, 2001 $3.42- $3.79 $8.58 September 30, 2000 $3.42- $3.79 $8.58 September 30, 1999 $3.42- $3.79 $5.75 Exercise Termination Dates 5/17/2003- 4/23/2007 5/17/2003- 1/02/2011 1/02/2011

In fiscal 1993, the Company adopted the 1992 Executive Equity Incentive Plan (the "Incentive Plan"). The purpose of the Incentive Plan is to increase the ownership of common stock of the Company by those non-union key employees (including officers and directors who are officers) and outside directors who contribute to the continued growth, development and financial success of the Company and its subsidiaries, and to attract and retain key employees and reward them for the Company's profitable performance. F-104 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) The Incentive Plan provides that an aggregate of 1,687,500 shares (after taking into account the 200% stock dividend effective January 31, 2000) of common stock of the Company will be available for awards in the form of stock options, including incentive stock options and non-qualified stock options generally at prices at or in excess of market prices at the date of grant. The Incentive Plan also provides that each outside director of the Company will annually be granted an option to purchase 15,000 shares of common stock at fair market value on the date of grant. The Company applies Accounting Principles Board Opinion Number 25 in accounting for options and warrants and accordingly recognizes no compensation cost for its stock options and warrants for grants with an exercise price equal to the current fair market value. The following reflect the Company's pro-forma net income and net income per share had the Company determined compensation costs based upon fair market values of options and warrants at the grant date pursuant to SFAS 123 as well as the related disclosures required by SFAS 123. A summary of the Company's stock option and warrant activity from October 1, 1998 to September 30, 2001 is as follows: Weighted Average Options Price ------- ------ Outstanding - October 1, 1998 215,000 $12.96 Issued 15,000 17.25 Exercised (25,000) 10.25 Repurchased (10,000) 10.75 ------- ------ Balance - September 30, 1999 195,000 13.75 Effect of 200% stock dividend (see Note 15) 390,000 (9.17) Issued 105,000 7.89 ------- ------ Outstanding - September 30, 2000 690,000 5.09 Issued 60,000 7.00 ------- ------ Outstanding - September 30, 2001 750,000 $5.24 ======= ====== At September 30, 2001, exercise prices for outstanding options ranged from $3.42 to $8.58. The weighted average remaining contractual life of such options was 5.6 years. F-105 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) The per share weighted average fair values of stock options issued during fiscal 2001, 2000 and fiscal 1999 were $2.41, $3.29 and $4.56, respectively, on the dates of issuance using the Black-Scholes option pricing model with the following weighted average assumptions: average expected dividend yield - 3.0% in 2001, 3.0% in 2000 and 3.5% in 1999; risk free interest rate - 3.50% in 2001, 5.54% in 2000 and 6.32% in 1999; expected life of 10 years in 2001, 2000 and 1999 and volatility factor of .38 in 2001, .44 in 2000, and .22 in 1999. The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. Proforma net income and earnings per share had the Company accounted for its options under the fair value method of SFAS 123 is as follows: Year Ending September 30, --------------------------- 2001 2000 1999 ------ ------ ------ Net income as reported $1,716 $5,069 $8,266 Adjustment required by SFAS 123 (145) (346) (152) ------ ------ ------ Pro-forma net income $1,571 $4,723 $8,114 ====== ====== ====== Pro-forma net income per share: Basic $ 0.24 $ .68 $ .99 ------ ------ ------ Diluted $ 0.23 $ .66 $ .97 ------ ------ ------ F-106 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) NOTE 17 - INCOME TAXES Provisions for (benefit of) income taxes consist of:

September 30, ------------- 2001 2000 1999 ----- ----- ----- Provision for (benefit of) income taxes: Current: Federal $ 4 ($ 35) $ 193 State (2) Deferred: Federal 786 922 2,209 State 22 26 68 Adjustment to the valuation allowance for deferred taxes: Federal (419) (3,115) 475 State (12) (89 13 ----- ------ ------ $ 381 ($2,291) $2,956 ===== ------ ======

Deferred tax assets (liabilities) are comprised of the following at September 30, 2001 and 2000: September 30, ------------- 2001 2000 ------ ------ Operating losses and tax credit carryforwards $4,715 $4,993 Statutory depletion carryovers 3,903 3,689 Depletion accounting (5,341) (3,602) Discontinued net refining operations 866 866 Losses in foreign subsidiaries 1,295 300 ------ ------ 5,438 6,246 Valuation allowance (3,559) (3,990) ------ ------ $1,879 $2,256 ====== ====== Deferred tax assets - current $1,879 $2,256 ------ ------ $1,879 $2,256 ====== ====== F-107 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) At September 30, 2001, the Company determined that a portion of the deferred tax asset would more likely than not be realized based upon estimates of future taxable income and upon the projected taxable income resulting from the anticipated sale of its oil and gas assets to Delta and accordingly decreased the valuation allowance by $431 to $3,559. If recent decreases in oil and gas prices continue and if the sale of the Company's oil and gas assets to Delta is not consummated, the Company may be required to increase its valuation allowance. See Note 21. At September 30, 2000, the Company determined that it was more likely than not that a portion of the deferred tax assets would be realized, based on current projections of taxable income due to higher commodity prices at September 30, 2000, and the valuation allowance was decreased by $3,204 to a total valuation allowance of $3,990. The income tax provision (benefit) differs from the amount computed by applying the statutory federal income tax rate to income before income taxes as follows: Year Ended September 30, ------------------------ 2001 2000 1999 ----- ------ ------ Tax at statutory rate $734 $ 972 $3,928 State taxes, net of federal benefit 7 (42) 51 Revision of tax estimates and contingencies 50 (151) Statutory depletion (1,330) Increase (decrease) in valuation allowance (431) (3,204) 489 Other 21 (17) (31) ----- ------ ------ $ 381 ($2,291) $2,956 ===== ====== ====== At September 30, 2001, the Company had the following tax carryforwards available: Federal Tax ----------- Alternative Minimum Regular Tax -------- ----------- Net operating loss $ 2,674 $24,021 Alternative minimum tax credits $ 3,752 N/A Statutory depletion $ 10,841 $ 440 F-108 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) The net operating loss carryforwards expire from 2001 through 2010. On September 9, 1994, the Company experienced a change of ownership for tax purposes. As a result of such change of ownership, the Company's net operating loss carryforward became subject to an annual limitation of $7,845. At September 30, 2001 all net operating loss carryforwards of the Company were no longer subject to the annual limitation. The Company also has approximately $58,688 in individual state tax loss carryforwards available at September 30, 2001. Approximately $47,287 of such carryforwards are primarily available to offset taxable income apportioned to certain states in which the Company has no operations and currently has no plans for future operations. As a result, it is probable most of such state tax carryforwards will expire unused. NOTE 18 - RELATED PARTIES In June 1999, the Company repurchased 24,700 (74,100 after stock split) shares of the Company's common stock from an officer of the Company. Such shares were repurchased at the closing stock price on the date of sale less $.125, resulting in a payment of $434 to the officer. The shares were repurchased pursuant to the Company's share repurchase program. Another officer of the Company is a 10% shareholder in an unaffiliated company that is entitled to receive 12.5% of the Company's share of net cash flow from its Romanian joint venture after the Company has recovered its investment in Romania. NOTE 19 - BUSINESS SEGMENTS As of September 30, 1995, the Company had disposed of its refining segment of the energy business (see Note 3) and operated in only two business segments - natural gas marketing and transmission and exploration and production. In May 1997, the Company sold its pipeline (natural gas transmission) to a subsidiary of UPRC (see Note 4). As a result, the Company was no longer in the natural gas transmission segment but continued to operate in the natural gas marketing and exploration and production segments. On May 31, 1999, the Company's long-term gas sales and gas supply contracts expired by their own terms and the Company exited the natural gas marketing business. The Company does not allocate interest income, interest expense or income tax expense to these segments. F-109 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts)

Year Ended September 30, 2001 ---------------------------------------------------------------------- Natural Gas Oil & Gas Eliminations Marketing Exploration and and and Refining Corporate Transmission Production (Discontinued) Items Consolidated ------------ ---------- -------------- ------------ ------------ Revenues $ 21,144 $ 21,144 Operating income (loss) $ 5,682 ($ 4,169) $ 1,513 Identifiable assets $67,702* $ 105,238 ($113,822) $ 59,118 Capital expenditures $ 15,531 $ 15,531 Depreciation, depletion and amortization $ 3,468 $ 2 $ 3,470 Year Ended September 30, 2000 ---------------------------------------------------------------------- Natural Gas Oil & Gas Eliminations Marketing Exploration and and and Refining Corporate Transmission Production (Discontinued) Items Consolidated ------------ ---------- -------------- ------------ ------------ Revenues $ 17,959 $ 17,959 Operating income (loss) $ 5,686 ($ 3,717) $ 1,969 Identifiable assets $67,727* $ 92,229 ($ 96,661) $ 63,295 Capital expenditures $ 11,399 $ 11,399 Depreciation, depletion and amortization $ 3,207 $ 2 $ 3,209 Year Ended September 30, 1999 ---------------------------------------------------------------------- Natural Gas Oil & Gas Eliminations Marketing Exploration and and and Refining Corporate Transmission Production (Discontinued) Items Consolidated ------------ ---------- -------------- ------------ ------------ Revenues $50,067 $ 7,190 $ 57,257 Operating income (loss) $11,563 $ 1,718 ($ 4,112) $ 9,169 Identifiable assets $79,026* $ 67,720 ($ 87,208) $ 59,538 Capital expenditures $ 24,065 $ 24,065 Depreciation, depletion and amortization $6,284 $ 2,046 $ 8,330 *Consists primarily of intracompany receivables.

F-110 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) For the year ended September 30, 1999, sales by the Company's natural gas marketing subsidiary to Lone Star Gas Company under the Lone Star Contract aggregated $46,802. These amounts constituted approximately 82% of consolidated revenues for the year ended September 30, 1999. The Lone Star contract terminated in May 1999. At the present time, the Company's consolidated revenues consist entirely of oil and gas sales. Three purchasers of the Company's oil and gas production currently account for approximately 43% of consolidated production. Sales derived from these three purchasers for the year ended September 30, 2001 aggregated $2,871, $2,611 and $2,603. NOTE 20 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS Cash and Cash Equivalents -- the carrying amount is a reasonable estimate of fair value. Marketable securities are related solely to the Company's investment in Penn Octane, Delta and Chevron/Texaco common stock and options to buy Penn Octane stock and are recorded at fair market value. Market value for common stock is computed to equal the closing share price at year end times the number of shares held by the Company. Fair market value for options is computed using the Black - Scholes option valuation model. Other Current Assets and Current Liabilities - the Company believes that the book values of other current assets and current liabilities approximate the market values. NOTE 21 - SUBSEQUENT EVENTS Subsequent to September 30, 2001, the Company disbursed the remaining $153 from the Larry Long Litigation settlement account (see Note 13). Subsequent to September 30, 2001, the Company paid MGNG $400 in settlement of the MGNG Litigation (see Note 13). In November 2001, the Company entered into an agreement for a line of credit of up to $40,000 with an energy bank. Pursuant to the related agreement the energy bank agreed to make available to the Company loans and letters of credit not to exceed a borrowing base determined by the value of the Company's oil and gas reserves using parameters set by the bank. Such borrowing based will be determined no less than semi-annually. The loans and letters of credit will be secured by the Company's oil and gas properties to the extent the amount outstanding under the facility exceeds $10,000. Interest under the facility will accrue at the bank's prime rate or at a LIBOR rate - the choice of rates being determined by the Company. Letters of credit issued under the facility will accrue interest at 2.25% annually. Loans outstanding under the facility will be repaid pursuant to a schedule set by the bank but redetermined at each borrowing base determination date. In F-111 Castle Energy Corporation Notes to Consolidated Financial Statements ("$000's" Omitted Except Per Share Amounts) addition, the Company is subject to typical financial covenants including minimum tangible net worth, debt service coverage, interest coverage and current ratio limitations, limitations on annual and quarterly dividends the Company may pay to shareholders and other limitations governing capital expenditures. The facility is scheduled to terminate November 30, 2003. The facility also includes a provision to provide letters of credit of up to $3,000 as may be required for the Long Trusts Lawsuit litigation (see Note 13). On December 11, 2001, the Company entered into a letter of intent to sell all of its domestic oil and gas assets to Delta for $20,000 and 9,566,000 shares of commons stock of Delta. The effective date of the proposed sale is October 1, 2001 and the expected closing date is April 30, 2002 or later. The sale is subject to execution of a definitive purchase and sale agreement by both parties, approval of the transaction by both Delta's and the Company's directors and approval of the issuance of the shares to Castle by Delta's shareholders. If the sale to Delta is not consummated, the Company could continue to operate as it does currently or pursue other alternative strategies. NOTE 22 - QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

First Second Third Fourth Quarter Quarter Quarter Quarter (December 31) (March 31) (June 30) (September 30) ------------- ---------- --------- -------------- Year Ended September 30, 2001: Revenues $5,394 $6,316 $5,347 $4,087 Operating income (loss) $1,533 $2,174 $ 511 ($2,705) Net income (loss) $1,110 $1,531 $ 397 ($1,322) Net income per share (diluted) $ .16 $ .22 $ .06 ($ .20) First Second Third Fourth Quarter Quarter Quarter Quarter (December 31) (March 31) (June 30) (September 30) ------------- ---------- --------- -------------- Year Ended September 30, 2000: Revenues $4,085 $3,318 $4,945 $5,611 Operating income (loss) $ 32 ($ 387) $ 835 $1,489 Net income (loss) $ 259 ($ 277) $1,024 $4,063 Net income (loss) per share (diluted) $ .04 ($ .04) $ .15 $ .58

For the year ended September 30, 2000 revenues from well operations have been retroactively reclassified as reductions of oil and gas production costs. The sums of the quarterly per share amounts differ from the annual per share amounts primarily because the stock purchases made by the Company were not made in equal amounts and at corresponding times each quarter. F-112 CASTLE ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS ("000's" Omitted Except Share Amounts)

March 31, September 30, 2002 2001 ------------------------- ASSETS Unaudited) Current assets: Cash and cash equivalents $ 4,254 $ 5,844 Restricted cash 210 370 Accounts receivable 2,247 2,787 Marketable securities 6,836 6,722 Prepaid expenses and other current assets 288 277 Estimated realizable value of discontinued net refining assets 612 Deferred income taxes 2,276 1,879 --------- -------- Total current assets 16,111 18,491 Property, plant and equipment, net: Oil and gas properties - subject to a plan of sale 37,986 Natural gas transmission 49 51 Furniture, fixtures and equipment 171 222 Oil and gas properties, net (full cost method): Proved properties 39,843 Unproved properties not being amortized 314 110 Estimated realizable value of discontinued net refining assets 612 Investment in Networked Energy LLC 469 401 --------- -------- Total assets $ 55,712 $ 59,118 ========= ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Dividend payable $ 331 Accounts payable $ 1,379 3,543 Accrued expenses 149 292 Accrued taxes on appreciation of marketable securities 1,014 900 Net refining liabilities retained 3,016 --------- -------- Total current liabilities 2,542 8,082 Net refining liabilities retained 3,016 Long-term liabilities 10 9 --------- -------- Total liabilities 5,568 8,091 --------- -------- Commitments and contingencies Stockholders' equity: Series B participating preferred stock; par value - $1.00; 10,000,000 shares authorized; no shares issued Common stock; par value - $0.50; 25,000,000 shares authorized; 11,503,904 shares issued at March 31, 2002 and September 30, 2001 5,752 5,752 Additional paid-in capital 67,365 67,365 Accumulated other comprehensive income - unrealized gains on marketable securities, net of taxes 1,804 1,600 Retained earnings 41,729 42,816 --------- -------- 116,650 117,533 Treasury stock at cost - 4,871,020 shares at March 31, 2002 and September 30, 2001 (66,506) (66,506) --------- -------- Total stockholders' equity 50,144 51,027 --------- -------- Total liabilities and stockholders' equity $ 55,712 $ 59,118 ========= ========

F-113 CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS ("000's" Omitted Except Share Amounts) (Unaudited) Three Months Ended March 31, 2002 2001 ---------------------------- Revenues: Oil and gas sales $ 3,258 $ 6,316 ------------ ------------ Expenses: Oil and gas production 1,359 1,998 General and administrative 1,227 1,416 Depreciation, depletion and amortization 1,172 728 ------------ ------------ 3,758 4,142 ------------ ------------ Operating income (loss) (500) 2,174 ------------ ------------ Other income (expense): Interest income 10 232 Other income 2 Equity in loss of Networked Energy LLC (48) (17) Impairment provision - marketable securities (204) ------------ ------------ (242) 217 ------------ ------------ Income (loss) before provision for income taxes (742) 2,391 ------------ ------------ Provision for (benefit of) income taxes: State (8) 24 Federal (259) 836 ------------ ------------ (267) 860 ------------ ------------ Net income (loss) ($ 475) $ 1,531 ============ ============ Net income (loss) per share: Basic ($ .07) $ .23 ============ ============ Diluted ($ .07) $ .22 ============ ============ Weighted average number of common and potential dilutive common shares outstanding: Basic 6,632,884 6,634,204 ============ ============ Diluted 6,760,235 6,814,491 ============ ============ F-114 CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS ("000's" Omitted Except Share Amounts) (Unaudited) Six Months Ended March 31, 2002 2001 -------------------------- Revenues: Oil and gas sales $ 6,699 $ 11,710 ----------- ---------- Expenses: Oil and gas production 2,613 3,402 General and administrative 2,598 3,174 Depreciation, depletion and amortization 2,414 1,427 ----------- ---------- 7,625 8,003 ----------- ---------- Operating income (loss) (926) 3,707 ----------- ---------- Other income (expense): Interest income 43 444 Other income 1 8 Equity in loss of Networked Energy LLC (82) (33) Impairment provision - marketable securities (204) ----------- ---------- (242) 419 ----------- ---------- Income (loss) before provision for income taxes (1,168) 4,126 ----------- ---------- Provision for (benefit of) income taxes: State (12) 41 Federal (409) 1,444 ----------- ---------- (421) 1,485 ----------- ---------- Net income (loss) ($ 747) $ 2,641 ----------- ---------- Net income (loss) per share: Basic ($ .11) $ .40 ----------- ---------- Diluted ($ .11) $ .39 ----------- ---------- Weighted average number of common and potential dilutive common shares outstanding: Basic 6,632,884 6,654,524 ----------- ---------- Diluted 6,756,927 6,855,192 ----------- ---------- F-115 CASTLE ENERGY CORPORATION CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS ("000's" Omitted) (Unaudited)

Six Months Ended March 31, 2002 2001 -------------------------- Net cash flow provided by (used in) operating activities ($ 61) $ 4,466 Cash flows from investing activities: Investment in furniture, fixtures and equipment (5) (27) Investment in oil and gas properties (703) (2,104) Investment in Networked Energy LLC (150) --------- --------- Net cash used in investing activities (858) (2,131) --------- --------- Cash flows from financing activities: Dividends paid to stockholders (671) (664) Acquisition of treasury stock 572 --------- --------- Net cash used in financing activities (671) (1,236) --------- --------- Net increase (decrease) in cash and cash equivalents (1,590) 1,099 Cash and cash equivalents - beginning of period 5,844 11,525 --------- --------- Cash and cash equivalents - end of period $ 4,254 $ 12,624 ========= =========

F-116 CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND OTHER COMPREHENSIVE INCOME ("000's" Omitted Except Share Amounts)

Accumu- lated Other Common Stock Additional Compre- Compre- Treasury Stock ------------------- Paid-In hensive hensive Retained ----------------- Shares Amount Capital Income Income Earnings Shares Amount Total ------ ------ ---------- ------- ------- -------- ------ ------- ------- Balance-October 1, 2001 11,503,904 $5,752 $67,365 $4,671 $42,422 4,791,020 ($65,934) $54,276 Stock acquired 80,000 (572) (572) Dividends declared (.20 per share) (1,322) (1,322) Comprehensive income (loss): Net income $1,716 1,716 1,716 Other comprehensive income: Unrealized (loss) on marketable securities, net of tax (3,071) (3,071) (3,071) ------ ------ ($1,355) ---------- ------ ------- ====== ------ ------- --------- ------- ------- Balance-September 30, 2001 11,503,904 5,752 67,365 1,600 42,816 4,871,020 (66,506) 51,027 Dividend adjustment (9) (9) Dividends declared ($.20 per share) (331) (331) Comprehensive income (loss): Net (loss) ($ 747) (747) (747) Other comprehensive income (loss): Unrealized (loss) on marketable securities, net of tax 204 204 204 ($543) ---------- ------ ------- ====== ------ ------- --------- ------- ------- Balance-March 31, 2002 11,503,904 $5,752 $67,365 $1,804 $41,729 4,871,020 ($66,506) $50,144 ========== ====== ======= ====== ======= ========= ======= =======

F-117 Note 1 - Basis of Preparation The unaudited consolidated financial statements of Castle Energy Corporation (the "Company") included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain reclassifications have been made to make the periods presented comparable. Although certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations, the Company believes that the disclosures included herein are adequate to make the information presented not misleading. Operating results for the three-month and six-month periods ended March 31, 2002 are not necessarily indicative of the results that may be expected for the fiscal year ending September 30, 2002 or subsequent fiscal periods. These unaudited consolidated financial statements should be read in conjunction with the financial statements and the notes thereto included in the Company's Annual Report on Form 10-K for the fiscal year ended September 30, 2001. In the opinion of the Company, the unaudited consolidated financial statements contain all adjustments necessary for a fair statement of the results of operations for the three month and six month periods ended March 31, 2002 and 2001 and for a fair statement of financial position at March 31, 2002. Note 2 - September 30, 2001 Balance Sheet The amounts presented in the balance sheet as of September 30, 2001 were derived from the Company's audited consolidated financial statements which were included in its Annual Report on Form 10-K for the fiscal year ended September 30, 2001. Note 3 - Discontinued Operations From August 1989 to September 30, 1995, several of the Company's subsidiaries conducted refining operations. By December 12, 1995, the Company's refining subsidiaries had sold all of their refining assets and the purchasers had assumed all related liabilities, including contingent environmental liabilities. In addition, in 1996, Powerine Oil Company ("Powerine"), one of the Company's former refining subsidiaries, merged into a subsidiary of the purchaser of the refining assets sold by Powerine and is no longer a subsidiary of the Company. The Company's remaining refining subsidiaries own no refining assets, have been inactive for over six years, and are inactive and in the process of liquidation. As a result, the Company has accounted for its refining operations as discontinued operations. Such discontinued refining operations have not impacted the Company's operations since September 30, 1995, although they may impact the Company's future operations. Note 4 - Contingencies/Litigation Contingent Environmental Liabilities In December 1995, Indian Refining I Limited Partnership ("IRLP"), an inactive subsidiary of the Company, sold its refinery, the Indian Refinery, to American Western Refining L.P. ("American Western"), an unaffiliated party. As part of the related purchase and sale agreement, American Western assumed all environmental liabilities and indemnified IRLP with respect thereto. Subsequently, American Western filed for bankruptcy and sold the Indian Refinery to an outside party pursuant to a bankruptcy proceeding. The outside party has substantially dismantled the Indian Refinery. American Western F-118 filed a Plan of Liquidation in 2001. American Western anticipated that the Plan of Liquidation would be confirmed in January 2002 but confirmation has been delayed because of legal challenges by ChevronTexaco, the parent of Texaco Refining and Marketing ("Texaco"), the operator of the Indian Refinery for over 50 years. During fiscal 1998, the Company was informed that the United States Environmental Protection Agency ("EPA") had investigated offsite acid sludge waste found near the Indian Refinery and had investigated and remediated surface contamination on the Indian Refinery property. Neither the Company nor IRLP was initially named with respect to these two actions. In October 1998, the EPA named the Company and two of its inactive refining subsidiaries as potentially responsible parties for the expected clean-up of the Indian Refinery. In addition, eighteen other parties were named including Texaco. A subsidiary of Texaco had owned the refinery until December of 1988. The Company subsequently responded to the EPA indicating that it was neither the owner nor the operator of the Indian Refinery and thus not responsible for its remediation. In November 1999, the Company received a request for information from the EPA concerning the Company's involvement in the ownership and operation of the Indian Refinery. The Company responded to the EPA information request in January 2000. On August 7, 2000, the Company received notice of a claim against it and two of its inactive refining subsidiaries from Texaco and its parent. Texaco had made no previous claims against the Company although the Company's subsidiaries had owned the refinery from August 1989 until December 1995. In its claim, Texaco demanded that the Company and its former subsidiaries indemnify Texaco for all liability resulting from environmental contamination at and around the Indian Refinery. In addition, Texaco demanded that the Company assume Texaco's defense in all matters relating to environmental contamination at and around the Indian Refinery, including lawsuits, claims and administrative actions initiated by the EPA, and indemnify Texaco for costs that Texaco has already incurred addressing environmental contamination at the Indian Refinery. Finally, Texaco also claimed that the Company and two of its inactive subsidiaries are liable to Texaco under the Federal Comprehensive Environmental Response Compensation and Liability Act ("CERCLA") as owners and operators of the Indian Refinery. The Company responded to Texaco disputing the factual and theoretical basis for Texaco's claims against the Company. The Company's management and special counsel subsequently met with representatives of Texaco but the parties disagreed concerning Texaco's claims. In October 2001, Texaco merged with Chevron and the merged Company was named ChevronTexaco. The Company's general counsel has subsequently corresponded with ChevronTexaco but no progress has been made in resolving ChevronTexaco's claims. The Company and its special counsel, Reed Smith LLP, believe that ChevronTexaco's claims are utterly without merit and the Company intends to vigorously defend itself against ChevronTexaco's claims and any lawsuits that may follow. In addition to the numerous defenses that the Company has against ChevronTexaco's contractual claim for indemnity, the Company and its special counsel believe that by the express language of the agreement which ChevronTexaco construes to create an indemnity, ChevronTexaco has irrevocably elected to forgo all rights of contractual indemnification it might otherwise have had against any person, including the Company. The Company and its special counsel also believe that ChevronTexaco's only claim against the F-119 Company is limited to liabilities arising under CERCLA and that ChevronTexaco's indemnification claims against the Company are contrary to CERCLA. In September 1995, Powerine sold the Powerine Refinery to Kenyen Resources ("Kenyen"), an unaffiliated party. In January 1996, Powerine merged into a subsidiary of Energy Merchant Corp. ("EMC"), an unaffiliated party, and EMC assumed all environmental liabilities of Powerine. In August 1998, EMC sold the Powerine Refinery, which it had subsequently acquired from Kenyen, to a third party. In July of 1996, the Company was named a defendant in a class action lawsuit concerning emissions from the Powerine Refinery. In April of 1997, the court granted the Company's motion to quash the plaintiff's summons based upon lack of jurisdiction and the Company is no longer involved in the case. Although any environmental liabilities related to the Indian Refinery and Powerine Refinery have been transferred to others, there can be no assurance that the parties assuming such liabilities will be able to pay them. American Western, owner of the Indian Refinery, filed for bankruptcy and is in the process of liquidation. EMC, which assumed the environmental liabilities of Powerine, sold the Powerine Refinery to an unrelated party, which we understand is still seeking financing to restart that refinery. Furthermore, as noted above, the EPA named the Company as a potentially responsible party for remediation of the Indian Refinery and has requested and received relevant information from the Company. Estimated gross undiscounted clean-up costs for this refinery are at least $80,000- $150,000 according to public statements by Texaco and third parties. If the Company were found liable for the remediation of the Indian Refinery, it could be required to pay a percentage of the clean-up costs. Since the Company's subsidiary only operated the Indian Refinery five years, whereas Texaco and others operated it over fifty years, the Company would expect that its share of remediation liability would be proportional to its years of operation, although such may not be the case. Furthermore, as noted above, ChevronTexaco has claimed that the Company indemnified it for all environmental liabilities related to the Indian Refinery. If ChevronTexaco were to sue the Company on this theory and prevail in court, the Company could be held responsible for the entire estimated clean up costs of $80,000-$150,000 or more. In such a case, this cost would be far in excess of the Company's financial capability. An opinion issued by the U.S. Supreme Court in June 1998 in the comparable matter of United States v. Bestfoods, 524 U.S. 51, 118 S.Ct. 1876 (1998), and a recent opinion by the U.S. Appeals Court for the Fifth Circuit in Aviall Services, Inc. v. Cooper Industries Inc., 263 F.3rd 134 (5th Cir. 2001) vacated and reh'g granted, 278 F.3d 416 (Dec. 19, 2001) support the Company''s positions. Nevertheless, if funds for environmental clean-up are not provided by these former and/or present owners, it is possible that the Company and/or one of its former refining subsidiaries could be named parties in additional legal actions to recover remediation costs. In recent years, government and other plaintiffs have often sought redress for environmental liabilities from the party most capable of payment without regard to responsibility or fault. Whether or not the Company is ultimately held liable in such a circumstance, should litigation involving the Company and/or IRLP occur, the Company would probably incur substantial legal fees and experience a diversion of management resources from other operations. Although the Company does not believe it is liable for any of its subsidiaries' clean-up costs and intends to vigorously defend itself in such regard, the Company cannot predict the ultimate outcome of these matters due to inherent uncertainties. F-120 Litigation Long Trusts Lawsuit In November 2000, the Company and three of its subsidiaries were defendants in a jury trial in Rusk County, Texas. The plaintiffs in the case, the Long Trusts, are non-operating working interest owners in wells previously operated by Castle Texas Production Limited Partnership ("CTPLP"), an inactive exploration and production subsidiary of the Company. The wells were among those sold to Union Pacific Resources Corporation ("UPRC") in May 1997. The Long Trusts claimed that CTPLP did not allow them to sell gas from March 1, 1996 to January 31, 1997 as required by applicable joint operating agreements, and they sued CTPLP and the other defendants, claiming (among other things) breach of contract, breach of fiduciary duty, conversion and conspiracy. The plaintiffs sought actual damages, exemplary damages, pre-judgment and post- judgment interest, attorney's fees and court costs. CTPLP counterclaimed for approximately $150 of unpaid joint interests billings plus interest, attorneys' fees and court costs. After a three-week trial, the District Court in Rusk County submitted 36 questions to the jury which covered all of the claims and counterclaims in the lawsuit. Based upon the jury's answers, the District Court entered judgement granting plaintiffs' claims against the Company and its subsidiaries, as well as CTPLP's counterclaim against the plaintiffs. The District Court issued an amended judgement on September 5, 2001 which became final December 19, 2001. The net amount awarded to the plaintiffs was approximately $2,700. The Company and its subsidiaries and the plaintiffs subsequently filed notices of appeal and each party submitted legal briefs with the Tyler Court of Appeals in April 2002. The Company and its special counsel expect that the Tyler Court of Appeals will hear the appeal case during the fall of 2002. Special counsel to the Company, Jenkens & Gilchrist, does not consider an unfavorable outcome to this lawsuit probable. The Company's management and special counsel believe that several of the plaintiffs' primary legal theories are contrary to established Texas law and that the Court's charge to the jury was fatally defective. They further believe that any judgment for plaintiffs based on those theories or on the jury's answers to certain questions in the charge cannot stand and will be reversed on appeal. As a result, the Company has not accrued any liability for this litigation. Nevertheless, to pursue the appeal, the Company and its subsidiaries were required to post a bond to cover the gross amount of damages awarded to the plaintiffs and to maintain that bond until the resolution of the appeal, which may take several years. Originally, the Company and its subsidiaries anticipated posting a bond of approximately $3,000 based upon the net amount of damages but the Company and its subsidiaries later decided to post a bond of $3,886 based upon the gross damages in order to avoid on-going legal expenses and to expeditiously move the case to the Tyler Court of Appeals. The letter of credit supporting this bond was provided by the Company's lender pursuant to the Company's $40,000 line of credit with that lender. Pilgreen Litigation As part of the oil and gas properties acquired from AmBrit Energy Corp. ("AmBrit") in June 1999, Castle Exploration Company, Inc., a wholly- owned subsidiary of the Company ("CECI") acquired a 10.65% overriding royalty interest ("ORRI") in the Simpson lease in south Texas, including the Pilgreen #2ST gas well. CECI subsequently transferred that interest to Castle Texas Oil and Gas Limited Partnership ("CTOGLP"), an indirect wholly-owned subsidiary. Because the operator suspended revenue attributed to the ORRI F-121 since first production due to title disputes, AmBrit had previously filed claims against the operator of the Pilgreen well, and CTOGLP acquired rights in that litigation with respect to the period after January 1, 1999. The Company now believes that operator will release approximately two thirds of the suspended revenue attributable to CTOGLP's ORRI in the Pilgreen #2ST well in the near future. Because of a claim by Dominion Oklahoma Texas Exploration and Production, Inc. ("Dominion") (see below), a working interest owner in the same well, that CTOGLP's ORRI in the Simpson lease should be deemed burdened by 3.55% overriding royalty interest, there is still a title dispute as to approximately 33% of the suspended CTOGLP Pilgreen production proceeds. The Company has named Dominion as a defendant in a legal action to seeking a declaratory judgment that the Company is entitled to its full 10.65% overriding royalty interest in Pilgreen well. The Company believes that Dominion's title exception to CTOGLP's overriding royalty interest is erroneous and notes that several previous title opinions have confirmed the validity of CTOGLP's interest. CTOGLP has also been informed that production proceeds from an additional well on the Simpson lease in which CTOGLP has a 5.325% overriding royalty interest have been suspended by the court because of title disputes. The Company intends to contest this matter vigorously. At the present time, the amount held in escrow applicable to the Company's interests in both wells is approximately $512. The Company's policy with respect to the $512 of potential recovery is to record any amounts recovered as income only when and if such amounts are actually received. Dominion Litigation In March 18, 2002, Dominion, operator of the Mitchell and Migl- Mitchell wells in the Southwest Speaks field in south Texas and a working interest owner in the Pilgreen #2ST well, filed suit in Texas against CTOGLP seeking declaratory judgement in a title action that the overriding royalty interest held by CTOGLP in these wells should be deemed to be burdened by certain other overriding royalty interests and therefore be reduced from 10.65% to 7.10%. Dominion is also seeking an accounting and refund of payments for overriding royalty to CTOGLP in excess of the 7.10% since April 2000. The Company preliminarily estimates the amount in controversy to be approximately $1,180, including $136 of the $512 held in escrow under the Pilgreen litigation (see above). Dominion has threatened to suspend all revenue payable to the Company from the Mitchell and Migl-Mitchell to offset their claim. The Company believes that Dominion's title exception to CTOGLP's overriding royalty interest is erroneous and notes that several previous title opinions have confirmed the validity of CTOGLP's interest. The Company intends to contest this matter vigorously and has accordingly made no provision for Dominion's claim in its March 31, 2002 financial statements. Note 5 - Information Concerning Reportable Segments For the periods ended March 31, 2001 and 2002, the Company operated in only one segment of the energy industry, oil and gas exploration and production. Until May 31, 1999, the Company also operated in the natural gas marketing segment of the energy industry. Note 7 - Sale of Domestic Exploration and Production Assets On January 15, 2002, the Company entered into an agreement to sell its domestic oil and gas properties to Delta Petroleum Company, a public exploration and production company headquartered in Denver, Colorado ("Delta"). The purchase price is $20,000 plus 9,566,000 shares of Delta's common stock, which would result in the Company owning approximately 43% of F-122 Delta. The effective date of the sale is October 1, 2001. Pursuant to the terms of the purchase and sale agreement, the cash portion of the purchase price will be reduced by the cash flow from the properties between the effective date and the closing date. Each party is subject to penalties for failure to close the transaction. In addition, Delta may repurchase up to 3,188,667 of its shares from Castle for $4.50 per share for a period of one year after closing and Delta agreed to nominate three additional directors selected by the Company to Delta's Board of Directors, which is currently comprised of four directors. The agreement also includes a provision whereby Delta may pay a portion of the cash purchase price with a 270 day note bearing interest of 8% if Delta is unable to fund the entire cash portion of the purchase price. The note plus accrued interest is payable in cash or Delta's common stock (at $3.00/share) at Delta's option. Pursuant to an amendment to the purchase and sale agreement the Company agreed that it would not acquire more than 49.9% of Delta in the event that Delta paid a portion of the purchase price with a 270 day note and then subsequently was unable to pay off the note in cash. In such case the unpaid portion of the note would continue beyond 270 days until such time as it was repaid in cash or in Delta stock so long as the Company interest in Delta did not exceed 49.9% of Delta's outstanding shares. As the result of this provision and other provisions in the purchase and sale agreement, the management of both the Company and Delta strongly believe that Delta will be the acquiring entity for purposes of generally accepted accounting principles. If, nevertheless, Delta were deemed the acquired entity, the Company would account for the transaction as the Company's acquisition of Delta using the purchase method of accounting and would accordingly include the financial results of Delta in its consolidated financial statements. Closing of the Delta transaction is subject to approval by Delta's shareholders. Delta recently sent proxies to its stockholders to approve the transaction and the Company and Delta expect to close the sale on May 31, 2002, assuming approval by Delta's shareholders. The Company currently expects that the proceeds from the sale will exceed the current carrying value of the oil and gas properties to be sold. Any resultant gain recorded by the Company upon sale will be dependent to a large extent upon the market price of Delta's common stock at the time the transaction closes and the nature of the proceeds received. It is anticipated that the fair value of Delta's option to repurchase the 3,188,667 shares at $4.50 will be recorded as a reduction of the sales proceeds. (At May 7, 2002, Delta's stock price was approximately $4.00/share.) Given the volatility of oil and gas prices, the fact that Delta shareholders have still not approved the transaction and other factors, there can be no assurance that the transaction will close as planned or that the Company will recognize a gain on the transaction in its financial statements. Portions of any gain recorded will be deferred due to the Company's indirect retention of interest in the properties sold as a result of its ownership interest in Delta after the sale. If at any time prior to the completion of the sale the Company estimates that it would record a loss on disposition, the loss would be recorded when estimated in accordance with Statement of Financial Accounting Standards No. 121. After the sale, the Company expects to hold approximately 43% of Delta's outstanding stock which would be recorded on the equity method. Under this method the Company records its share of Delta's income or loss with an offsetting entry to the carrying value of the Company's investment. Cash distributions, if any, are recorded as a reduction in the carrying value of the Company's investment. Furthermore, the Company expects that its resulting investment in Delta will be substantially in excess of the Company's proportionate share of Delta's equity and that such excess will be recorded as goodwill on the Company's consolidated balance sheets subsequent to closing. F-123 Such goodwill will be accounted for in accordance with Statement of Financial Accounting Standards No. 142 ("SFAS 142"). Pursuant to the provisions of SFAS 142, the Company will be required to evaluate the recoverability of such goodwill periodically and write off or reduce it if it is no longer deemed recoverable commencing October 1, 2002. The net cash flow (oil and gas sales less oil and gas production expenses) from the Company's oil and gas properties from October 1, 2001 to the expected closing of the Delta transaction will reduce the cash portion of the purchase price the Company expects to receive from the sale of its domestic oil and gas properties to Delta. Accordingly, the net cash flow for the six months ended March 31, 2002 of $4,086, subject to some minor adjustments, will ultimately accrue to Delta's account rather than to the Company's account if the sale to Delta is ultimately consummated as planned. F-124 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) II-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) 10.42 Credit Agreement dated May 31, 2002, by and among Delta Petroleum Corporation, Delta Exploration Company, Inc., Piper Petroleum Company and Bank of Oklahoma, N.A. Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated May 24, 2002. (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. II-10 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) 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 the Securities Act of 1933, the Company has caused this Amendment No. 5 to the Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Denver and State of Colorado on the 8th day of August, 2002. DELTA PETROLEUM CORPORATION By: /s/ Roger A. Parker --------------------------------- Roger A. Parker, Chief Executive Officer By: /s/ Kevin K. Nanke --------------------------------- Kevin K. Nanke, Chief Financial Officer Pursuant to the requirements of the Securities Act of 1933, this Amendment No. 4 to the Registration Statement has been signed below by the following persons on our behalf and in the capacities and on the dates indicated. Signature and Title Date ------------------- ---- /s/ Aleron H. Larson, Jr. August 8, 2002 ---------------------------------- Aleron H. Larson, Jr., Director /s/ Roger A. Parker August 8, 2002 ---------------------------------- Roger A. Parker, Director /s/ James B. Wallace August 8, 2002 ---------------------------------- James B. Wallace, Director /s/ Jerrie F. Eckelberger August 8, 2002 ---------------------------------- Jerrie F. Eckelberger, Director /s/ Joseph L. Castle, II August 8, 2002 ---------------------------------- Joseph L. Castle, II, Director /s/ Russell S. Lewis August 8, 2002 ---------------------------------- Russell S. Lewis, Director /s/ John P. Keller August 8, 2002 ---------------------------------- John P. Keller, Director