S-1/A 1 deltas1.txt DELTA PETROLEUM CORPORATION S-1 AMEND 1 As Filed With the Securities and Exchange Commission on July 3, 2001 Registration Statement No.333-59898 ============================================================================= UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 -------- FORM S-1/A AMENDMENT NO. 1 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 DELTA PETROLEUM CORPORATION (Name of small business issuer in its charter) Colorado 1311 84-1060803 (State or jurisdiction (Primary Standard (I.R.S. Employer of incorporation or Industrial Code Number) Identification Number) organization) 555 17th Street, Suite 3310 Denver, Colorado 80202 (303) 293-9133 (Address and telephone number of issuer's principal executive offices) Roger A. Parker, President/CEO 555 17th Street, Suite 3310 Denver, Colorado 80202 (303) 293-9133 (Name, address and telephone number of agent for service) Approximate date of proposed sale to public: As soon as the registration statement is effective. If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. [x] If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. [ ] If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. [ ] The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine. CALCULATION OF REGISTRATION FEE ============================================================================= Proposed Estimated Maximum Title of Each offering Aggregate Amount of Class of Securities Amount to be Price Offering Registration to be Registered Registered(1) Per Unit(2) Price Fee ----------------------------------------------------------------------------- Common Stock, $.01 par value 6,000,000 $4.575 $27,450,000 $6,862.50 Common Stock 500,000 $4.575 $ 2,287,500 $ 571.88 underlying Selling Shareholder Warrants TOTAL $7,434.38(3) ============================================================================= (1) In the event of a stock split, stock dividend or similar transaction involving our common stock, in order to prevent dilution, the number of shares registered shall automatically be increased to cover the additional shares in accordance with Rule 416(a) under the Securities Act of 1933, as amended (the "Securities Act"). (2) In accordance with Rule 457(c), the aggregate offering price of our stock is estimated solely for calculating the registration fees due for this filing. This estimate is based on the average of the high and low sales price of our stock reported by the Nasdaq Small-Cap Market on April 27, 2001, which was $4.575 per share. In accordance with Rule 457(g), the shares issuable upon the exercise of outstanding warrants are determined by the higher of (I) the exercise price of the warrants and options, (ii) the offering price of the common stock in the registration statement, or (iii) the average sales price of the common stock as determined by 457 (c). (3) Filing fees of $17,819.45 were paid by Delta Petroleum Corporation in connection with a Form S-1 Registration Statement, file number 333-47414, which was amended on March 20, 2001, to become a Form S-3 Registration Statement and to remove the securities included in this Registration Statement. Pursuant to Rule 457(p), the filing fee is being paid by applying a portion of the $17,819.45 paid in connection with the prior Form S-1 Registration Statement. PROSPECTUS SUBJECT TO COMPLETION DATED _______, 2001 ---------------------------------------------------------------------------- Up to 6,500,000 Shares Delta Petroleum Corporation Common Stock ---------------------------- Swartz Private Equity LLC may use this prospectus in connection with sales of up to 6,500,000 shares of our common stock. Trading Symbol NASDAQ Small Cap Market "DPTR" ----------------------------------------------------------------------------- Consider carefully the risk factors beginning on page 5 in this prospectus. ----------------------------------------------------------------------------- Swartz may sell the common stock at prices and on terms determined by the market, in negotiated transactions or through underwriters. Swartz, in addition to being a selling shareholder, is also considered an "underwriter" within the meaning of the Securities Act in connection with its sales of our common stock. We will receive proceeds from Swartz under the Amended and Restated Investment Agreement. 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 _________ ___, 2001 Table of Contents Part I Table of Contents...................................................... 2 Prospectus Summary .................................................... 3 Risk Factors........................................................... 4 Use of Proceeds ....................................................... 10 Determination of Offering Price ....................................... 10 Information with Respect to Delta ..................................... 10 Description of Business ......................................... 13 Description of Property ......................................... 18 Legal Proceedings ............................................... 34 Common Equity Securities ........................................ 34 Financial Data .................................................. 35 Management's Discussion and Analysis or Plan of Operation ....... 36 Directors, Executive Officers, Promoters and Control Persons .... 51 Executive Compensation .......................................... 54 Security Ownership of Certain Beneficial Owners and Management .. 57 Certain Relationships and Related Party Transactions ............ 59 Selling Security Holder ............................................... 64 Plan of Distribution .................................................. 70 Description of Securities ............................................. 72 Interests of Named Experts and Counsel ................................ 72 Commission Position on Indemnification for Securities Act Liabilities ........................................... 73 Financial Statements .................................................. 75 2 PROSPECTUS SUMMARY The following is a summary of the pertinent information regarding this offering. This summary is qualified in its entirety by the more detailed information and financial statements and related notes appearing elsewhere in this prospectus. This prospectus should be read in its entirety, as this summary does not constitute a complete recitation of facts necessary to make an investment decision. Delta ----- We are a Colorado corporation organized on December 21, 1984. We maintain our principal executive offices at Suite 3310, 555 Seventeenth Street, Denver, Colorado 80202, and our telephone number is (303) 293-9133. Our common stock is listed on Nasdaq Small-Cap Market under the symbol DPTR. We are engaged in the acquisition, exploration, development and production of oil and gas properties. During the nine months ended March 31, 2001, we had total revenue of $9,475,596, operating expenses of $7,522,595 and net income for the nine months of $893,453. During the year ended June 30, 2000, we had total revenues of $3,575,524, operating expenses of $5,655,288 and a net loss for fiscal 2000 of $3,367,050. During the year ended June 30, 1999, we had total revenue of $1,694,925, operating expenses of $4,600,131 and a net loss for fiscal 1999 of $2,998,755. As of June 30, 2000, we had varying interests in 112 gross (27.20 net) productive wells located in six states. We have undeveloped properties in six states, and interests in five federal units and one lease offshore California near Santa Barbara. We operate 25 of the wells and the remaining wells are operated by independent operators. The Offering ------------ Selling Security Holder Swartz Private Equity, LLC. Securities Offered A total of 6,500,000 including the following: 6,000,000 shares of common stock, plus an additional 500,000 shares issuable upon exercise of commitment warrants. Offering Price The shares being offered by this prospectus are being offered by Swartz from time to time at the then current market price. Common Stock to be 17,408,600 shares; including all of the shares Outstanding after issuable upon the exercise of warrants Offering Offering held by Swartz. We currently only have a total of 10,908,600 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 37.3%. 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. NASDAQ rules require shareholder approval in 3 connection with a transaction other than a public offering involving the sale by the issuer of common stock at a price less than the greater of book or market value which, together with sales by officers, directors or substantial shareholders of the issuer, equals 20% or more of common stock. We plan to call a meeting of our shareholders within 90 days of the date of this prospectus to consider the approval of these issuances. We currently do not intend to issue any shares to Swartz under the Investment Agreement until we obtain shareholder approval. Dividend Policy We do not anticipate paying dividends on our common stock in the foreseeable future. Use of Proceeds The shares offered by this prospectus are being sold by Swartz and we will receive proceeds from Swartz under the Investment Agreement. We intend to use all such proceeds for working capital, property and equipment, capital expenditures and general corporate purposes. (See "Use of Proceeds"). RISK FACTORS Prospective investors should consider carefully, in addition to the other information in this prospectus, the following: 1. We have substantial debt obligations and shortages of funding could hurt our future operations. As the result of debt obligations that we have incurred in connection with purchases of oil and gas properties, we are obligated to make substantial monthly payments to our lender on a loan which encumbers the production revenue from 11 onshore wells and the offshore Rocky Point and Point Arguello Units. Although we intend to seek outside capital to either refinance the debt or provide a cushion, at the present time we are almost totally dependent upon the revenues that we receive from our oil and gas properties to service the debt. In the event that oil and gas prices and/or production rates drop to a level that we are unable to pay the $150,000 principal and interest minimum payment per month that is required by the debt agreements, it is likely that we would lose our interest in the properties that we recently purchased. In addition, our level of oil and gas activities, including exploration and development of existing properties, and additional property acquisition, 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, prior to fiscal 2001, and at March 31, 2001 we had an accumulated deficit of $22,051,956. During the nine months ended March 31, 2001, we had total revenue of $9,475,596, operating expenses of $7,522,595 and net income of $893,453. During the year ended June 30, 2000, we had total 4 revenues of $3,575,524, operating expenses of $5,655,288 and a net loss for the fiscal year of $3,367,050. During the year ended June 30, 1999, we had total revenues of $1,694,925, operating expenses of $4,600,131 and a net loss for the year of $2,998,755. 3. The substantial cost to develop certain of our offshore California properties could result in a reduction in our interest in these properties or penalize us. Certain of our offshore California undeveloped properties, in which we have ownership interests ranging from 2.49% to 75%, are attributable to our interests in four of our five federal units (plus one additional lease) located offshore California near Santa Barbara. The cost to develop these properties will be very substantial. The cost to develop all of these offshore California properties in which we own a minority interest, including delineation wells, environmental mitigation, development wells, fixed platforms, fixed platform facilities, pipelines and power cables, onshore facilities and platform removal over the life of the properties (assumed to be 38 years), is estimated to be in excess of $3 billion. Our share of such costs, based on our current ownership interest, is estimated to be over $200 million. Operating expenses for the same properties over the same period of time, including platform operating costs, well maintenance and repair costs, oil, gas and water treating costs, lifting costs and pipeline transportation costs, are estimated to be approximately $3.5 billion, with our share, based on our current ownership interest, estimated to be approximately $300 million. There will be additional costs of a currently undetermined amount to develop the Rocky Point Unit. Each working interest owner will be required to pay its proportionate share of these costs based upon the amount of the interest that it owns. If we are unable to fund our share of these costs or otherwise cover them through farmouts or other arrangements then we could either forfeit our interest in certain wells or properties or suffer other penalties in the form of delayed or reduced revenues under our various unit operating agreements. 4. The development of the offshore units could be delayed or halted. The California offshore federal units have been formally approved and are regulated by the Minerals Management Service of the federal government ("MMS"). While the federal government has recently attempted to expedite the process of obtaining permits and authorizations necessary to develop the properties, there can be no assurance that it will be successful in doing so. The MMS initiated the California Offshore Oil and Gas Energy Resources (COOGER) study at the request of the local regulatory agencies of the affected Tri-Counties. The COOGER study was completed in January of 2000 and seeks to present a long-term regional perspective of potential onshore constraints that should be considered when developing existing undeveloped offshore leases. COOGER will project the economically recoverable oil and gas production from offshore leases which have not yet been developed. These projections will be utilized to assist in identifying a potential range of scenarios for developing these leases. The "worst" case scenario is that no new development of existing offshore leases would occur. If this scenario were ultimately to be adopted by governmental decision makers and the industry as the proper course of action for development, our offshore California properties would in all likelihood have little or no value. We would seek to cause the Federal government to reimburse us for all money spent by us and our predecessors for leasing and other costs and/or for the value of the oil and gas reserves found on the leases through our exploration activities and those of our predecessors. Moreover, on June 22, 2001 a Federal Court ordered the MMS to 5 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. The milestones have not as yet been suspended and no decision has as yet been made by the MMS as to whether or not it will appeal this decision. The ultimate outcome and effects of this litigation are not certain at the present time. 5. We will have to incur substantial costs in order to develop our reserves and we may not be able to secure funding. Relative to our financial resources, we have significant undeveloped properties in addition to those in offshore California discussed above that will require substantial costs to develop. During the year ended June 30, 2000, we participated in the drilling and completion or recompletion of four gas wells and seven non-productive wells. So far during our current fiscal year we have participated in the drilling of three offshore wells at a cost to us of approximately $450,000, and nine onshore wells at a cost to us of approximately $580,000. The cost of these wells either has been or will be paid out of our cash flow. All of the wells that we have drilled so far this year have been successfully completed except for two of the onshore wells which were dry holes. Although it is possible that we will participate in the drilling of additional wells during the remainder of our current fiscal year and we believe that we will participate in the drilling of additional wells during our next fiscal year, our level of oil and gas activity, including exploration and development and property acquisitions, will be to a significant extent dependent upon our ability to successfully conclude funding transactions. We expect to continue incurring costs to acquire, explore and develop oil and gas properties, and management predicts that these costs (together with general and administrative expenses) will be in excess of funds available from revenues from properties owned by us and existing cash on hand. It is anticipated that the source of funds to carry out such exploration and development will come from a combination of our sale of working interests in oil and gas leases, production revenues, sales of our securities, and funds from any funding transactions in which we might engage. 6. Current and future governmental regulations will affect our operations. Our activities are subject to extensive federal, state, and local laws and regulations controlling not only the exploration for and sale of oil, but also the possible effects of such activities on the environment. Present as well as future legislation and regulations could cause additional expenditures, restrictions and delays in our business, the extent of which cannot be predicted, and may require us to cease operations in some circumstances. In addition, the production and sale of oil and gas are subject to various governmental controls. Because federal energy policies are still uncertain and are subject to constant revisions, no prediction can be made as to the ultimate effect on us of such governmental policies and controls. 7. We hold only a minority interest in certain properties and, therefore, generally will not control the timing of development. 6 We currently operate only a small portion of the wells in which we own an interest and we are dependent upon the operator of the wells that we do not operate to make most decisions concerning such things as whether or not to drill additional wells, how much production to take from such wells, or whether or not to cease operation of certain wells. Further, we do not act as operator of and, with the exception of Rocky Point, we do not own a controlling interest in any of our offshore California properties. While we, as a working interest owner, may have some voice in the decisions concerning the wells, we are not the primary decision maker concerning them. As a result, we will generally not control the timing of either the development of most of our properties or the expenditures for development. Because we are not in control, we may not be able to cause wells to be drilled even though we may have the funds with which to pay our proportionate share of the expenses of such drilling, or, alternatively, we may incur development expenses at a time when funds are not available to us. We hold only a minority interest in and do not operate many of our properties and, therefore, generally will not control the timing of development. 8. We are subject to the general risks inherent in oil and gas exploration and operations. Our business is subject to risks inherent in the exploration, development and operation of oil and gas properties, including but not limited to environmental damage, personal injury, and other occurrences that could result in our incurring substantial losses and liabilities to third parties. In our own activities, we purchase insurance against risks customarily insured against by others conducting similar activities. Nevertheless, we are not insured against all losses or liabilities which may arise from all hazards because such insurance is not available at economic rates, because the operator has not purchased such insurance, or because of other factors. Any uninsured loss could have a material adverse effect on us. 9. We have no long-term contracts to sell oil and gas. We do not have any long-term supply or similar agreements with governments or authorities for which we act as a producer. We are therefore dependent upon our ability to sell oil and gas at the prevailing well head market price. There can be no assurance that purchasers will be available or that the prices they are willing to pay will remain stable. 10. Our business is not diversified. Since all of our resources are devoted to one industry, purchasers of our common stock will be risking essentially their entire investment in a company that is focused only on oil and gas activities. 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." 7 12. We do not expect to pay dividends. There can be no assurance that our proposed operations will result in sufficient revenues to enable us to operate at profitable levels or to generate a positive cash flow. For the foreseeable future, it is anticipated that any earnings which may be generated from our operations will be used to finance our growth and that dividends will not be paid to holders of common stock. See "DESCRIPTION OF COMMON STOCK." 13. We may be unable to obtain sufficient funds from the Investment Agreement with Swartz to meet our liquidity needs. Because of our current debt structure, there may be circumstances when we might need to obtain sufficient funds from the Investment Agreement with Swartz. However, the future market price and volume of trading of our common stock limits the rate at which we can obtain money under the equity line agreement with Swartz. Further, we may be unable to satisfy the conditions contained in the Investment Agreement, which would result in our inability to draw down money on a timely basis, or at all. If the price of our common stock declines, or trading volume in our common stock is low, we may be unable to obtain sufficient funds from Swartz to meet our liquidity needs. 14. The exercise of our put rights may substantially dilute the interests of other security holders. We will issue shares to Swartz upon exercise of our Put rights at a price equal to the lesser of: - the market price for each share of our common stock minus $.25; or - 91% of the market price for each share of our common stock. Accordingly, the repeated exercise of our rights to sell shares to Swartz under the Investment Agreement may result in substantial dilution to the interests of the other holders of our common stock. Depending on the price per share of our common stock during the three year period of the Investment Agreement, we may need to register additional shares for resale to access the full amount of financing available. Registering additional shares could have a further dilutive effect on the value of our common stock. If we are unable to register the additional shares of common stock, we may experience delays in, or be unable to, access some of the $20 million available under our agreement with Swartz. 15. The sale of material amounts of our common stock could reduce the price of our common stock and encourage short sales. If and when we exercise our rights under the Investment Agreement and sell shares of our common stock to Swartz, if and to the extent that Swartz sells the common stock, our common stock price may decrease due to the additional shares in the market. If the price of our common stock decreases, and if we decide to exercise our right to put shares to Swartz, we must issue more shares of our common stock for any given dollar amount invested by Swartz, subject to a designated minimum put price that we specify. This may encourage short sales, which could place further downward pressure on the price of our common stock. 8 16. We depend on key personnel. We currently only have three employees that serve in management roles, and the loss of any one of them could severely harm our business. In particular, Roger Parker is responsible for the operation of our oil and gas business, Aleron H. Larson, Jr. is responsible for other business and corporate matters, and Kevin Nanke is our chief financial officer. We don't have key man insurance on the lives of any of these individuals. 17. We allow our key personnel to purchase working interests on the same terms as us. In the past we have occasionally allowed our key employees to purchase working interests in our oil and gas properties on the same terms as us in order to provide a meaningful incentive to the employees and to align their own personal financial interests with ours in making decisions affecting the properties in which they own an interest. Specifically, on February 12, 2001, our Board of Directors permitted Aleron H. Larson, Jr., our Chairman, Roger A. Parker, our President, and Kevin Nanke, our CFO, to purchase working interests of 5% each for Messrs. Larson and Parker and 2-1/2% for Mr. Nanke in our Cedar State gas property located in Eddy County, New Mexico and in our Ponderosa Prospect consisting of approximately 52,000 gross acres in Harding and Butte Counties, South Dakota held for exploration. These officers were authorized to purchase these interests on or before March 1, 2001 at a purchase price equivalent to the amounts paid by us for each property as reflected upon our books by delivering to us shares of Delta common stock at the February 12, 2001 closing price of $5.125 per share. Messrs. Larson and Parker each delivered 31,310 shares and Mr. Nanke delivered 15,655 shares in exchange for their interests in these properties. Also on February 12, 2001, we granted to Messrs. Larson and Parker and Mr. Nanke the right to participate in the drilling of the Austin State #1 well in Eddy County, New Mexico by having them commit to us on February 12, 2001 (prior to any bore hole knowledge or information relating to the objective zone or zones) to pay 5% each by Messrs. Larson and Parker and 2-1/2% by Mr. Nanke of our working interest costs of drilling and completion or abandonment costs, which costs may be paid in either cash or in Delta common stock at $5.125 per share. All of these officers committed to participate in the well and will be assigned their respective working interests in the well and associated spacing unit after they have been billed and paid for the interests as required. To the extent that key employees are permitted to purchase working interests in wells that are successful, they will receive benefits of ownership that might otherwise have been available to us. Conversely, to the extent that key employees purchase working interests in wells that are ultimately not successful, such purchases may result in personal financial losses for our key employees that could potentially divert their attention from our business. 18. We may choose not to exercise our put rights under the investment agreement with Swartz. If we do not Put at least $2,000,000 worth of common stock to Swartz during each one year period following the effective date of the Investment Agreement, we must pay Swartz an annual non-usage fee. This fee equals the difference between $200,000 and 10% of the value of the shares of common stock we Put to Swartz during the one year period. The fee is due and payable on the last business day of each one year period. Each annual non-usage fee is 9 payable to Swartz, in cash, within five (5) business days of the date it accrued. We are not required to pay the annual non-usage fee to Swartz in years we have met the Put requirements. We are also not required to deliver the non-usage fee payment until Swartz has paid us for all Puts that are due. If the investment agreement is terminated, we must pay Swartz the greater of (i) the non-usage fee described above, or (ii) the difference between $200,000 and 10% of the value of the shares of common stock Put to Swartz during all Puts to date. We may terminate our right to initiate further Puts or terminate the investment agreement at any time by providing Swartz with written notice of our intention to terminate. However, any termination will not affect any other rights or obligations we have concerning the investment agreement or any related agreement. USE OF PROCEEDS The proceeds from the sale of the shares of common stock offered by this prospectus will be received directly by Swartz and we will not receive any proceeds from the sale of these shares. We will, however, receive proceeds from the sale of our common stock to Swartz. We intend to use the proceeds from the sale of common stock to Swartz and from the exercise of warrants by Swartz for working capital, property and equipment, capital expenditures and general corporate purposes. DETERMINATION OF OFFERING PRICE The shares being registered herein are being sold by Swartz, and not by us, and are therefore being sold at the market price as of the date of sale. Our common stock is traded on the Nasdaq Small-Cap Market under the symbol "DPTR." On June 7, 2001, the reported closing price for our common stock on the Nasdaq Small-Cap Market was $5.50. 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. 10 We believe the factors discussed below are important factors that could cause actual results to differ materially from those expressed in a forward- looking statement made herein or elsewhere by us or on our behalf. The factors listed below are not necessarily all of the important factors. Unpredictable or unknown factors not discussed herein could also have material adverse effects on actual results of matters that are the subject of forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises. We advise our shareholders that they should (1) be aware that important factors not described below could affect the accuracy of our forward-looking statements and (2) use caution and common sense when analyzing our forward-looking statements in this document or elsewhere, and all of such forward-looking statements are qualified by this cautionary statement. VOLATILITY AND LEVEL OF HYDROCARBON COMMODITY PRICES. 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. Some of our projections and estimates are based on assumptions as to the future prices of natural gas and crude oil. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future may differ from our estimates. Any substantial or extended decline in the actual prices of natural gas and/or crude oil could have a material adverse effect on (1) our financial position and results of operations (including reduced cash flow and borrowing capacity), (2) the quantities of natural gas and crude oil reserves that we can economically produce, (3) the quantity of estimated proved reserves that may be attributed to our properties and (4) our ability to fund our capital program. PRODUCTION RATES AND RESERVE REPLACEMENT. Projecting future rates of oil and gas production is inherently imprecise. Producing oil and gas reservoirs generally have declining production rates. Production rates depend on a number of factors, including geological, geophysical and engineering factors, weather, production curtailments or restrictions, prices for natural gas and crude oil, available transportation capacity, market demand and the political, economic and regulatory climate. Another factor affecting production rates is our ability to replace depleting reservoirs with new reserves through exploration success or acquisitions. Exploration success is difficult to predict, particularly over the short term, where results can vary widely from year to year. Moreover, our ability to replace reserves over an extended period depends not only on the total volumes found, but also on the cost of finding and developing such reserves. Depending on the general price environment for natural gas and crude oil, our finding and development costs may not justify the use of resources to explore for and develop such reserves. There can be no assurances as to the level or timing of success, if any, that we will be able to achieve in finding and developing or acquiring additional reserves. Acquisitions that result in successful exploration or exploitation projects require assessment of numerous factors, many of which are beyond our control. There can be no assurance that any acquisition of property interests by us will be successful and, if unsuccessful, that such failure will not have an adverse effect on our financial condition, results of operations and cash flows. 11 RESERVE ESTIMATES. Our forward-looking statements may be predicated on our estimates of our oil and gas reserves. All of the reserve data in this prospectus or otherwise made by us or on our behalf are 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. Projecting future rates of production and timing of future development expenditures is also inexact. Many factors beyond our control affect these estimates. In addition, the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Therefore, it is common that estimates made by different engineers will vary. The results of drilling, testing and production after the date of an estimate may also require a revision of that estimate, and these revisions may be material. As a result, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered. LAWS AND REGULATIONS. Our forward-looking statements are generally based on the assumption that the legal and regulatory environment will remain stable. 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, including federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations, affecting (1) oil and gas production, including allowable rates of production by well or proration unit, (2) taxes applicable to us and/or our production, (3) the amount of oil and gas available for sale, (4) the availability of adequate pipeline and other transportation and processing facilities and (5) the marketing of competitive fuels. Our operations are also subject to extensive federal, state and local laws and regulations in the U.S. and laws and regulations of foreign nations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. These environmental laws and regulations continue to change and may become more onerous or restrictive in the future. Our forward-looking statements are generally based upon the expectation that we will not be required in the near future to expend amounts to comply with environmental laws and regulations that are material in relation to our total capital expenditures program. However, inasmuch as such laws and regulations are frequently changed, we are unable to accurately predict the ultimate cost of such compliance. DRILLING AND OPERATING RISKS. 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. In addition, a substantial amount of our operations are currently offshore and subject to the additional hazards of marine operations, such as loop currents, capsizing, collision and damage or loss from severe weather. Our drilling operations are also subject to the risk that no commercially productive natural gas or oil reserves will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including drilling conditions, pressure or irregularities in formations, equipment failures or accidents and adverse weather conditions. 12 COMPETITION. Our forward-looking statements are generally based on a stable competitive environment. Competition in the oil and gas industry is intense both domestically and internationally. We actively compete for reserve acquisitions and exploration leases and licenses, as well as in the gathering and marketing of natural gas and crude oil. Our competitors include the major oil companies, independent oil and gas concerns, individual producers, natural gas and crude oil marketers and major pipeline companies, as well as participants in other industries supplying energy and fuel to industrial, commercial and individual consumers. To the extent our competitors have greater financial resources than currently available to us, we may be disadvantaged in effectively competing for certain reserves, leases and licenses. Recently announced consolidations in the industry may enhance the financial resources of certain of our competitors. From time to time, the level of industry activity may result in a tight supply of labor or equipment required to operate and develop oil and gas properties. The availability of drilling rigs and other equipment, as well as the level of rates charged, may have an effect on our ability to compete and achieve success in our exploration and production activities. In marketing our production, we compete with other producers and marketers on such factors as deliverability, price, contract terms and quality of product and service. Competition for the sale of energy commodities among competing suppliers is influenced by various factors, including price, availability, technological advancements, reliability and creditworthiness. In making projections with respect to natural gas and crude oil marketing, we assume no material decrease in the availability of natural gas and crude oil for purchase. We believe that the location of our properties, our expertise in exploration, drilling and production operations, the experience of our management and generally enable us to compete effectively. In making projections with respect to numerous aspects of our business, we generally assume that there will be no material change in competitive conditions that would adversely affect us. OUR BUSINESS We are a Colorado corporation and were organized on December 21, 1984. We maintain our principal executive offices at Suite 3310, 555 Seventeenth Street, Denver, Colorado 80202, and our telephone number is (303) 293-9133. Our common stock is listed on NASDAQ under the symbol DPTR. We are engaged in the acquisition, exploration, development and production of oil and gas properties. As of June 30, 2000, we had varying interests in 112 gross (27.20 net) productive wells located in six states. We have undeveloped properties in six states, and interests in five federal units and one lease offshore California near Santa Barbara. We operate 28 of the wells and the remaining wells are operated by independent operators. All wells are operated under contracts that are standard in the industry. At June 30, 2000, we estimated onshore proved reserves to be approximately 250,000 Bbls of oil and 7.08 Bcf of gas, of which approximately 120,000 Bbls of oil and 5.67 Bcf of gas were proved developed reserves. At June 30, 2000, we estimated offshore proved reserves to be approximately 1.58 million Bbls of oil, of which approximately 910,000 Bbls were proved developed reserves. (See "Description of Property.) At March 31, 2001, we had an authorized capital of 3,000,000 shares of $.10 par value preferred stock, of which no shares of preferred stock were issued, and 300,000,000 shares of $.01 par value common stock of which 13 10,849,600 shares of common stock were issued and outstanding. We have outstanding warrants and options to purchase 2,385,000 shares of common stock at prices ranging from $2.00 per share to $6.00 per share at August 7, 2000. Additionally, we have outstanding options which were granted to our officers, employees and directors under our 1993 Incentive Plan, as amended, to purchase up to 3,128,069 shares of common stock at prices ranging from $0.05 to $9.75 per share at March 31, 2001. At June 30, 2000, we owned 4,277,977 shares of common stock of Amber Resources Company ("Amber"), representing 91.68% of the outstanding common stock of Amber. Amber is a public company (registered under the Securities Exchange Act of 1934) whose activities include oil and gas exploration, development, and production operations. Amber owns a portion of the interests referenced above in the producing oil and gas properties in Oklahoma and the non-producing oil and gas properties offshore California near Santa Barbara. We entered into an agreement with Amber effective October 1, 1998 which provides, in part, for the sharing of the management between the two companies and allocation of expenses related thereto. During the year ended June 30, 2000, we were engaged in only one industry, namely the acquisition, exploration, development, and production of oil and gas properties and related business activities. Our oil and gas operations have been comprised primarily of production of oil and gas, drilling exploratory and development wells and related operations and acquiring and selling oil and gas properties. We, directly and through Amber, currently own producing and non-producing oil and gas interests, undeveloped leasehold interests and related assets in Arkansas, Colorado, Louisiana, Oklahoma, New Mexico, North Dakota, South Dakota, Texas, and Wyoming; and interests in a producing Federal unit and undeveloped offshore Federal leases near Santa Barbara, California. We intend to continue our emphasis on the drilling of exploratory and development wells. 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 may participate in joint venture arrangements to develop certain other leases. Such transactions may be structured in any number of different manners which are in use in the oil and gas industry. Each such transaction is likely to be individually negotiated and no standard terms may be predicted. (1) Principal Products or Services and Their Markets. The principal products produced by us are crude oil and natural gas. The products are generally sold at the wellhead to purchasers in the immediate area where the product is produced. The principal markets for oil and gas are refineries and transmission companies which have facilities near our producing properties. (2) Distribution Methods of the Products or Services. Oil and natural gas produced from our wells are normally sold to purchasers as referenced in (6) below. Oil is picked up and transported by the purchaser from the wellhead. In some instances we are charged a fee for the cost of transporting the oil, which fee is deducted from or accounted for in the price paid for the oil. Natural gas wells are connected to pipelines generally owned by the natural gas purchasers. A variety of pipeline transportation charges are usually included in the calculation of the price paid for the natural gas. 14 (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, 2000 , we sold 71% of our oil to Gulf Mark Energy, Inc., an unaffiliated oil and gas company located in Houston, Texas and 13% to El Paso Natural Gas. We believe that there are numerous purchasers available for our oil and the loss of either Gulf Mark Energy, Inc. or El Paso Natural Gas as customers would not have a material adverse effect on our business. We do not depend upon one or a few major customers for the sale of oil and gas as of the date of this report. The loss of any one or several customers would not have a material adverse effect on our business. (7) Patents, Trademarks, Licenses, Franchises, Concessions, Royalty Agreements or Labor Contracts. We do not own any patents, trademarks, licenses, franchises, concessions, or royalty agreements except oil and gas interests acquired from industry participants, private landowners and state and federal governments. We are not a party to any labor contracts. (8) Need for Any Governmental Approval of Principal Products or Services. Except that we must obtain certain permits and other approvals from various governmental agencies prior to drilling wells and producing oil and/or natural gas, we do not need to obtain governmental approval of our principal products or services. (9) Government Regulation of the Oil and Gas Industry. General. ------- Our business is affected by numerous governmental laws and regulations, including energy, environmental, conservation, tax and other laws and 15 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 its oil and gas operations, products and other activities. In particular, these laws and regulations require the acquisition of permits, restrict the type, quantities, and concentration of various substances that can be released into the environment, limit or prohibit activities on certain lands lying within wilderness, wetlands and other protected areas, regulate the generation, handling, storage, transportation, disposal and treatment of waste materials and impose criminal or civil liabilities for pollution resulting from oil, natural gas and petrochemical operations. Governmental approvals and permits are currently, and may in the future be, required in connection with our operations. The duration and success of obtaining such approvals are contingent upon many 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 particular operations and products of ours, 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 our financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement of those laws, will not cause us to incur substantial environmental liabilities or costs. 16 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, 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 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 17 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 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 its inception, Delta has not had any customer or government-sponsored material research activities relating to the development of any new products, services or techniques, or the improvement of existing products. (11) Environmental Protection. Because we are engaged in acquiring, operating, exploring for and developing natural resources, we are subject to various state and local provisions regarding environmental and ecological matters. Therefore, compliance with environmental laws may necessitate significant capital outlays, may materially affect our earnings potential, and could cause material changes in our proposed business. At the present time, however, the existence of environmental law does not materially hinder nor adversely affect our business. Capital expenditures relating to environmental control facilities have not been material to the operation of Delta since its inception. In addition, we do not anticipate that such expenditures will be material during the fiscal year ending June 30, 2001. (12) Employees. We have five full time employees. Operators, engineers, geologists, geophysicists, landmen, pumpers, draftsmen, title attorneys and others necessary for our operations are retained on a contract or fee basis as their services are required. DESCRIPTION OF PROPERTY (1) Office Facilities. Our offices are located at 555 Seventeenth Street, Suite 3310, Denver, Colorado 80202. We lease approximately 4,800 square feet of office space for $7,125 per month and the lease will expire in April of 2002. (2) Oil and Gas Properties. We own interests in oil and gas properties located primarily in California, Colorado, Oklahoma, New Mexico, North Dakota, Texas, Wyoming. Most 18 wells from which we receive revenues are owned only partially by us. For information concerning our oil and gas production, average prices and costs, estimated oil and gas reserves and estimated future cash flows, see the tables set forth below in this section and "Notes to Financial Statements" included in this report. We did not file oil and gas reserve estimates with any federal authority or agency other than the Securities and Exchange Commission during the years ended June 30, 2000 and 1999. Principal Properties. The following is a brief description of our principal properties: 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 numerous drillable prospects. As of March 1, 2001 Delta's net daily production was approximately 400 mcf per day from wells drilled on this project. The area has adequate markets for the volumes of natural gas that are being produced 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 13 gas wells (10.3 net), and oil and gas leases covering approximately 8,000 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 many of our wells. The acreage is located in and around the Plateau and Vega Fields. Louisiana. We own 87.5% of the working interest in the West Delta Block 52 Unit, Plaquemines Parish, Louisiana. On April 13, 2000, we sold 100% of our working interest in this unit. We expect to record a gain on sale of approximately $500,000. Oklahoma. Directly (12 wells) and through Amber (20 wells) we own non-operating working interests in 32 natural gas wells in Oklahoma. The wells range in 19 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. During fiscal 1999 we sold interests in 23 wells in Oklahoma for aggregate proceeds of $1,384,000. Wyoming. Moneta Hills. In 1997 we sold an 80% interest in our Moneta Hills project to KCS Energy ("KCS"), a subsidiary of KCS Mountain Resources, Inc. The Moneta Hills project presently consists of approximately 9,696 acres, six wells and a 13 mile gas gathering pipeline. Under the terms of the sale, KCS paid us $450,000 for the interests acquired and agreed to drill two wells to the Fort Union formation at approximately 10,000 feet. KCS will carry Delta for a 20% back-in after payout interest in each of the two wells. The first well was drilled and is producing; however, KCS never did drill the second well before filing for Chapter 11 Bankruptcy protection in 1999. As a result, the properties, including the plugging and abandonment obligation, were returned to Delta. Recently, Delta agreed to sell all but one well and well spacing unit to Samedan Oil Corporation with a reserved overriding royalty interest 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. New Mexico. East Carlsbad Field. We own interests in 11 producing wells and associated acreage in a field which is primarily in New Mexico with a small portion in Texas. Current production net to the interests owned by Delta is approximately 738 Mcf per day and 30 Bbls of oil per day as of June 30, 2000. We also own an additional gas 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. We recently completed our acquisition of a working interest in Eland, Stadium, Subdivision and Livestock fields in Stark County, North Dakota. There are a total of 20 producing wells and 5 injection wells. Current production net to the interests being acquired by Delta is approximately 340 barrels of oil equivalent per day as of September 29, 2000. Delta had previously purchased two thirds of the interests and on September 29, 2000 completed the acquisition of the remaining third. 20 South Dakota. We own a 50% interest in approximately 52,000 oil and gas leasehold acres in Harding and Butte Counties, South Dakota. We are the operator of a drilling program. The first of four wells were drilled in May 2001 and appear to be successful, however, we have not yet completed the wells and do not have any production test rates. We do expect to have initial production information in the near future. Offshore: Offshore Federal Waters: Santa Barbara, California Area Undeveloped Properties: Directly and through our subsidiary, Amber Resources Company, we own interests in five undeveloped federal units (plus one additional lease) located in federal waters offshore California near Santa Barbara. The Santa Barbara Channel and the offshore Santa Maria Basin are the seaward portions of geologically well-known onshore basins with over 90 years of production history. These offshore areas were first explored in the Santa Barbara Channel along the near shore three mile strip controlled by the state. New field discoveries in Pliocene and Miocene age reservoir sands led to exploration into the federally controlled waters of the Pacific Outer Continental Shelf ("POCS"). Eight POCS lease sales and subsequent exploratory drilling conducted between 1966 and 1989 have resulted in some 915 million barrels of oil and 873 billion cubic feet of gas having been produced and sold. The latest MMS figures show POCS production of approximately 126,000 Bbls of oil and 208 million cubic feet of gas per day. However, except for our small interest in the Point Arguello Unit discussed below, we do not own any interest in any offshore California production and there no assurance that any of our undeveloped properties will ever achieve production. Most of the early offshore production was from Pliocene age sandstone reservoirs. The more recent developments are from the highly fractured zones of the Miocene age Monterey Formation. The Monterey is productive in both the Santa Barbara Channel and the offshore Santa Maria Basin. It is the principal producing horizon in the Point Arguello field, the Point Pedernales field, and the Hondo and Pescado fields in the Santa Ynez Unit. Because the Monterey is capable of relatively high productive rates, the Hondo field, which has been on production since late 1981, has already surpassed 190 million Bbls of production. 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. 21 Leasing, lease administration, development and production within the Federal POCS all fall under the Code of Federal Regulations administered by the MMS. The EPA controls disposal of effluents, such as drilling fluids and produced waters. Other Federal agencies, including the Coast Guard and the Army Corps of Engineers, also have oversight on offshore construction and operations. The first three miles seaward of the coastline are administered by each state and are known as "State Tidelands" in California. Within the State Tidelands off Santa Barbara County, the State of California, through the State Lands Commission, regulates oil and gas leases and the installation of permanent and temporary producing facilities. Because the four units in which we own an interest 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%. Under a financial arrangement between us and Whiting Petroleum Corporation ("Whiting"), Whiting holds in its name for our sole benefit and account a working interest 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 as currently proposed. 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 22 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 presents a long-term regional perspective of potential onshore constraints that should be considered when developing existing undeveloped offshore leases. COOGER 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 the Lion Rock Unit and the Point Sal Unit), the results of which are as follows: 23 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 that 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 Arguello Unit upon which the Rocky Point leases would be drilled from existing Point Arguello platforms with extended reach drilling technology. Current Status. On October 15, 1992 the MMS directed a Suspension of Operations (SOO), effective January 1, 1993, for the POCS undeveloped leases and units. The SOO was directed for the purpose of preparing what became known as the COOGER Study. Two-thirds of the cost of the Study was funded by the participating companies in lieu of the payment of rentals on the leases. 24 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 required to perform exploration and development activities in order to meet certain milestones set out by the MMS. Progress toward the milestones is 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 May 18, 2001 a revised Development and Production Plan for the Point Arguello Unit was submitted to the MMS and the California Coastal Commission for approval. If approved by the California Coastal Commission, this plan would enable development of the Rocky Point Unit from the Point Arguello platforms that are already in existence. The California Coastal Commission is required by law 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. If the California Coastal Commission finds that the plan is not consistent, the decision can then be appealed to the U.S. Secretary of Commerce. We believe that the plan is consistent with California's Coastal Plan and that the plan will be approved. If it is not approved, however, we currently plan to appeal the decision to the U.S. Secretary of Commerce. Upon a favorable ruling by either the California Coastal Commission or the U.S. Secretary of Commerce, we expect the permitting process to begin immediately. On June 22, 2001, however, a Federal Court 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. The milestones have not as yet been suspended and no decision has as yet been made by the MMS as to whether or not it will appeal this decision. 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 MMS currently established milestones is presently uncertain in light of the recent court ruling. Cost to Develop Offshore California Properties. The cost to develop four of the five undeveloped units (plus one lease) located offshore California, including delineation wells, environmental mitigation, development wells, fixed platforms, fixed platform facilities, pipelines and power cables, onshore facilities and platform removal over the life of the properties (assumed to be 38 years), is estimated by the partners to be in excess of $3 billion. Our share based on our current working interest of such costs over the life of the properties is estimated to be over $200 million. There will be additional costs of a currently undetermined amount to develop the Rocky Point Unit which is the fifth undeveloped unit in which we own an interest. To the extent that we do not have sufficient cash available to pay our share of expenses when they become payable under the respective operating 25 agreements, it will be necessary for us to seek funding from outside sources. Likely potential sources for such funding are currently anticipated to include (a) public and private sales of our common stock (which may result in substantial ownership dilution to existing shareholders), (b) bank debt from one or more commercial oil and gas lenders, (c) the sale of debt instruments to investors, (d) entering into farm-out arrangements with respect to one or more of our interests in the properties in which 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 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 property 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, management believes that the opportunities for us to increase our asset base and ultimately improve our cash flow are also substantial. 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 significantly, 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 during the time period in which development is actually occurring on each of the subject properties. 26 Gato Canyon Unit. We hold a 15.60% working interest (directly 8.63% and through Amber 6.97%) in the Gato Canyon Unit. This 10,100 acre unit is operated by Samedan Oil Corporation. Seven test wells have been drilled on the Gato Canyon structure. Five of these were drilled within the boundaries of the Unit and two were drilled outside the Unit boundaries in the adjacent State Tidelands. The test wells were drilled as follows: within the boundaries of the Unit; three wells were drilled by Exxon, two in 1968 and one in 1969; one well was drilled by Arco in 1985; and, one well was drilled by Samedan in 1989. Outside the boundaries of the Unit, in the State Tidelands but still on the Gato Canyon Structure, one well was drilled by Mobil in 1966 and one well was drilled by Union Oil in 1967. In April 1989, Samedan tested the P-0460 #2 which yielded a combined test flow rate of 5,160 Bbls of oil per day from six intervals in the Monterey Formation between 5,880 and 6,700 feet of drilled depth. The Monterey Formation is a highly fractured shale formation. The Monterey (which ranges from 500' to 2,900' 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 distances to access the Las Flores site is approximately six miles. Delta's share of the estimated capital costs to develop the Gato Canyon field are approximately $45 million. The Gato Canyon Unit leases are currently held under Suspension of Production status through May 1, 2003. An updated Exploration Plan is expected to include plans to drill an additional delineation well. 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 Exxon Mobil 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 10 API and the oil in the subthrust block has an average estimated gravity of 15 API. The Point Sal field is located in the Offshore Santa Maria Basin approximately six miles seaward of the coastline (see Map). Water depths range from 300 feet to 500 feet in the area of the field. It is anticipated that oil and gas produced from the field will be processed in a new facility 27 at an onshore site or in the existing Lompoc facility (see Map). Any processed oil would then be transported out of Santa Barbara County in either the All American Pipeline or the Tosco-Unocal Pipeline (see Map). Offshore pipeline distance is approximately six to eight miles depending on the final choice of the point of landfall. Delta's share of the estimated capital costs to develop the Point Sal unit are approximately $38 million. The Point Sal Unit leases are currently held under Suspension of Production status through November 1, 2002. An updated Exploration Plan is expected to include plans to drill an additional delineation well prior to preparing the Development Plan. Lion Rock Unit and Federal OCS Lease P-0409. We hold a 1% net profits interest (through Amber) in the Lion Rock Unit and a 24.21692% working interest (directly) in 5,693 acres in Federal OCS Lease P-0409 which is immediately adjacent to the Lion Rock Unit and contains a portion of the San Miguel Field reservoir. The Lion Rock Unit is operated by Aera Energy LLC. An aggregate of 13 test wells have been drilled on the Lion Rock Unit and OCS lease P-0409. Nine of these wells were completed and tested and indicated the presence of oil and gas in the Monterey Formation. The test wells were drilled as follows: one well was drilled by Socal (now Chevron) in 1965; six wells were drilled by Phillips Petroleum, one in 1982, two in 1983, two in 1984 and one in 1985; 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 10.7 API. The Lion Rock Unit and Lease P-0409 are located in the Offshore Santa Maria Basin eight to ten miles from the coastline (see Map). Water depths range from 300 feet to 600 feet in the area of the field. It is anticipated that any oil and gas produced at Lion Rock and P-0409 would be processed at a new facility in the onshore Santa Maria Basin or at the existing Lompoc facility (see Map), and would be transported out of Santa Barbara County in the All American Pipeline or the Tosco-Unocal Pipeline (see Map). Offshore pipeline distance will be eight to ten miles depending on the point of landfill. Delta's share of the estimated capital costs to develop the Lion Rock/San Miguel field is approximately $113 million. The Lion Rock Unit and Lease P-0409 are currently held under Suspension of Production status through November 1, 2002. During this SOP there will be an interpretation of the 3D seismic survey and the preparation of an updated Plan of Development leading to production. Additional delineation wells may or may not be drilled depending on the outcome of the interpretation of the 3D survey. Sword Unit. We hold a 2.492% working interest (directly 1.6189% and through Amber .8731%) in the Sword Unit. This 12,240 acre unit is operated by Conoco, Inc. In aggregate, three wells have been drilled on this unit of which two wells were completed and tested in the Monterey formation with calculated flow rates of from 4,000 to 5,000 Bbls per day with an estimated average gravity of 10.6 API. The two completed test wells were drilled by Conoco, one in 1982 and the second in 1985. The Sword field is located in the western Santa Barbara Channel ten miles west of Point Conception and five miles south of Point Arguello's field 28 Platform Hermosa (see Map). Water depths range from 1000 feet to 1800 feet in the area of the field. It is anticipated that the oil and gas produced from the Sword Field will likely be processed at the existing Gaviota consolidated facility and the oil would then be transported out of Santa Barbara County in the All American Pipeline (see Map). Access to the Gaviota plant is through Platform Hermosa and the existing Point Arguello Pipeline system. A pipeline proposed to be laid from a platform located in the northern area of the Sword field to Platform Hermosa would be approximately five miles in length. Delta's share of the estimated capital costs to develop the Sword field is approximately $19 million. The Sword Unit leases are currently held under a Suspension of Production status through August 1, 2003. An updated Exploration Plan is expected to include plans to drill an additional delineation well. Rocky Point Unit. Under a financial arrangement between Whiting and us, Whiting holds in its name for our sole benefit and account, an 11.11% interest in OCS Block 451 (E/2) and a 100% interest in OCS Block 452 and 453, which leases comprise the undeveloped Rocky Point Unit. The Rocky Point Unit is operated by Whiting. The financial arrangement between Whiting and us is prescribed by a letter agreement between Whiting and Delta dated November 19, 1999 which, among other things, provides that Whiting "will continue as operator of the Rocky Point Unit" and "will also continue to hold title to the working/leasehold interest in the Rocky Point Unit leases for the sole benefit and account of . . . Delta". The letter agreement further provides that upon our written request, Whiting will immediately assign or cause to be assigned to us, all right, title and interest of Whiting in the Rocky Point Unit leases held by Whiting. Further, Whiting may not take any action or make any agreement relating to these Rocky Point leases without our consent. 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 to 31 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. The Rocky Point Unit leases are currently held under Suspension of Production status through June, 2002. This Unit operator has prepared and timely submitted a Project Description for the development program to the MMS as the first milestone in the Schedule of Activities for the Unit. The operator, under the auspices of the MMS, has also made a presentation of the Project to the affected Federal, State and local agencies. On May 18, 2001 a revised Development and Production Plan and supporting information was submitted to the MMS and distributed to the California Coastal Commission 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 29 necessary for such a Plan have been addressed. Under law, the California Coastal Commission must 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). We currently expect that the California Coastal Commission will hold a consistency hearing in October of this year. It appears to us that the Plan is consistent with California's Coastal Plan, but in the event of an adverse determination, the decision will be appealed to the U.S. Secretary of Commerce. Developed Properties: Point Arugello Unit. Under 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 Petroleum. In an agreement between Whiting and Delta (see Form 8-K dated June 9, 1999), Whiting agreed to retain all of the abandonment costs associated with our interest in the Point Arguello Unit and the related facilities. We anticipate that we will redrill five wells in calendar 2001. Each redrill will cost approximately $1.71 million ($105,000 to our interest). We anticipate the redrill costs to be paid through current operations or additional financing. -------------- map page. -------------- Kazakhstan Acquisition of Exploration Licenses in Kazakhstan. During fiscal year 1999, we acquired Ambir Properties, Inc. ("Ambir") the only assets of which consisted of two licenses for exploration of approximately 1.9 million acres in the Pavlodar region of Eastern Kazakhstan. A work plan prepared by Delta was approved by the Kazakhstan government which established minimum work and spending commitments. The minimum required work and spending commitment for fiscal year 2001 is $264,000. We intend to transfer the licenses into the name of Delta and attempt to extend the time for certain commitments under the work plan. The acquisition is a high risk, frontier exploration project. Delta does not presently have the expertise nor the resources to meet all commitments that will be required in the later years of the work plan. Delta will seek other companies in the oil and gas industry to participate in the implementation of the work plan. 30 (3) Production. We are not obligated to provide a fixed and determined quantity of oil and gas in the future under existing contracts or agreements. During the years ended June 30, 2000, 1999 and 1998, we have not had, nor do we now have, any long-term supply or similar agreements with governments or authorities by which we acted as producer. Impairment of Long Lived Assets Undeveloped Offshore California Properties We acquired many of our (including Amber's) offshore properties in a series of transactions from 1999 to the present. These properties are carried at our cost bases and have been subject to an impairment review on an annual basis. These properties will be expensive to develop and produce and have been subject to significant regulatory restrictions and delays, but, based on information reported to us by the operator of the properties and the U.S. government's Mineral Management Services, we believe that it is worthwhile to continue to expend our resources to cause these properties to be developed in a timely manner. By using a 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 offshore properties and our Kazakhstan property exploration licenses. 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 basis 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. We recorded an impairment provision attributed to certain undeveloped onshore properties of $169,811 for the year ended June 30, 1999. 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. 31 We recorded an impairment provision attributable to certain producing properties of $103,230 and $128,993 for the years ended June 30, 1999 and 1998, respectively. 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: Year Ended Year Ended Year Ended June 30, June 30, June 30, 2000 1999 1998 Onshore Offshore Onshore Onshore ------- -------- ---------- ----------- Average sales price: Oil (per barrel) $25.95 11.54 10.24 16.46 Natural Gas (per Mcf) $ 2.62 - 1.97 2.26 Production costs (per Bbl equivalent) $ 4.94 11.02 4.37 4.02 The profitability of our oil and gas production activities is affected by the fluctuations in the sale prices of our oil and gas production. We sold 25,000 barrels per month from December 1999 to May 2000 at $8.25 per barrel and 25,000 barrels per month from June 2000 to December 2000 at $14.65 under fixed price contracts with production purchases. We have committed to sell 6,000 barrels per month at $27.31 under fixed price contracts with production purchases from March 1, 2001 through February 28, 2002. (See "Management's Discussion and Analysis or Plan of Operation.") (4) Productive Wells and Acreage. The table below shows, as of June 30, 2000, the approximate number of gross and net producing oil and gas wells by state and their related developed acres owned by us. Calculations include 100% of wells and acreage owned by us and by Amber as of that date. 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) --------- ------- --------- ------- --------- ------- Texas 4 1.82 0 .00 1,558 1,111 Colorado 8 .80 13 10.30 2,560 2,127 Oklahoma 0 .00 32 2.03 17,120 1,198 California: Onshore 0 .00 11 1.25 1,200 132 Offshore 38 2.30 0 .00 19,740 1,197 Wyoming 0 .00 6 1.20 960 192 New Mexico 10 7.5 2,480 1,860 -- ---- -- ----- ------ ----- 50 4.92 72 22.28 45,618 7,817 ------------------------ 32 (1) All of the wells classified as "oil" wells also produce various amounts 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. (5) Undeveloped Acreage. At June 30, 2000, we held undeveloped acreage by state as set forth below: Undeveloped Acres (1)(2) Location Gross Net -------- -------- ------ California, offshore(3) 64,905 15,837 California, onshore 640 96 Colorado 10,560 7,937 Wyoming 9,696 1,939 Oklahoma 1,600 112 ------ ------ Total 87,401 25,921 ------------------------- (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. (6) Drilling Activity During the years indicated, we drilled or participated in the drilling of the following productive and nonproductive exploratory and development wells: 33 Year Ended Year Ended Year Ended June 30, 2000 June 30, 1999 June 30, 1998 Gross Net Gross Net Gross Net ----- ----- ----- ----- ----- ----- Exploratory Wells(1): Productive: Oil 0 .00 0 .00 0 .000 Gas 0 .00 4 .44 5 .545 Nonproductive 0 .00 7 .77 1 .113 --- --- --- ---- --- ---- Total 0 .00 11 1.21 6 .658 Development Wells(1):. Productive: Oil 3 .18 0 .00 0 .000 Gas 2 .25 0 .00 1 .042 Nonproductive 0 .00 0 .00 0 .000 --- --- --- ---- --- ---- Total 5 .43 0 .00 1 .042 Total Wells(1): Productive: Oil 3 .18 0 .00 0 .000 Gas 2 .25 4 .44 6 .587 Nonproductive 0 .00 7 .77 1 .113 --- --- --- ---- --- ---- Total Wells 5 .43 11 1.21 7 .700 ------------------------- (1) Does not include wells in which we had only a royalty interest. (7) Present Drilling Activity We plan on participating or operating the drilling of up to 20 new wells during calendar 2001. LEGAL PROCEEDINGS We are not directly engaged in any material pending legal proceedings to which we or our subsidiaries are a party or to which any of our property is subject. COMMON EQUITY SECURITIES Market Information. Delta's common stock currently trades under the symbol "DPTR" on NASDAQ. The following quotations reflect inter-dealer high and low sales prices, without retail mark-up, mark-down or commission and may not represent actual transactions. 34 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 On June 7, 2001, the reported closing price for our common stock on the Nasdaq Small-Cap Market was $5.50. Approximate number of holders of common stock. The number of holders of record of our common stock at June 6, 2001 was approximately 1,000 which does not include an estimated 2,600 additional holders whose stock is held in "street name." Dividends. We have not paid dividends on our stock and we do not expect to do so in the foreseeable future. FINANCIAL DATA SELECTED FINANCIAL INFORMATION The following selected financial information should be read in conjunction with our financial statements and the accompanying notes.

Nine Months Ended March 31, Fiscal Years Ended June 30, ------------------------- -------------------------------------------------------------- 2001 2000 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- ---- ---- Total Revenues $ 9,475,596 1,956,105 3,575,524 1,694,925 2,163,615 1,812,456 1,385,317 Income/(Loss) from Operations $ 1,953,001 (1,451,486) (2,079,764) (2,905,206) (1,010,343) (2,457,007) (3,328,230) Income/(Loss) Per Share $ 0.09 (0.35) ($0.46) ($0.51) ($0.18) ($0.49) ($0.81) Total Assets $32,099,302 20,797,743 21,057,272 11,377,132 10,349,843 10,438,373 11,515,732 Total Long Term Debt $ 8,497,809 6,759,506 8,244,768 1,000,000 -0- -0- -0- Total Liabilities $14,064,967 10,133,339 10,094,540 1,530,708 844,789 1,267,505 3,691,824 Stockholders' Equity $18,034,335 10,664,404 10,962,732 9,846,424 9,505,054 9,170,868 7,823,908

35 MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION. At March 31, 2001, we had a working capital deficit of $2,412,712 compared to a working capital deficit of $1,985,141 at June 30, 2000. Our current assets include an increase in trade account receivable from June 30, 2000 of approximately $950,000. This increase is primarily due to the accrued revenue from the acquisitions completed during the nine month period. This receivable was also impacted by an increase in oil and gas prices. Our current liabilities include the current portion of long-term debt of $3,941,026 at March 31, 2001. The increase in the current portion of long- term debt from June 30, 2000 is primarily attributed to borrowings relating to the acquisition of interests in the Eland and Stadium fields in Stark County, North Dakota ("North Dakota"), the 100% working interest in the West Delta Block 52 Unit, a producing property in Plaquemines Parish, Louisiana ("West Delta") and the Cedar State gas property located in Eddy County, New Mexico. These acquisitions were closed on September 28, 2000, September 29, 2000 and January 22, 2001, respectively. The debt incurred for these acquisitions is being paid out of cash flow from production of the properties. Offshore There are certain milestones established by the Minerals Management Services ("MMS") which must be met relating to four of our five undeveloped offshore California units. The specific milestones for each of the four units vary depending upon the operator of the unit. If the milestones are not met development of the units will not be permitted by the MMS. We expect to meet the milestones established. In January 2000, the two properties which are operated by Aera Energy, LLC, lease OCS-P 0409 and the Point Sal Unit had requirements to submit an interpretation of the merged 3-D survey of the Offshore Santa Maria Basin covering the properties. This milestone was accomplished in February 2000. The next milestone for these properties was to submit a Project Description for each property to the MMS in February 2000. The Project Description for each of the properties was submitted in February and after responding to MMS' request for additional information and clarification revised Project Descriptions were submitted in September. 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 Suspensions of Production on both the Lion Rock Unit and Lease P- 0409 will expire on November 1, 2002. In September 2001, the revised Exploration Plans (EPs) and/or Development and Production Plans (DPP's) for the Aera properties must be submitted to the MMS. As the operator of the properties, Aera intends to submit the EPs and DPPs next September. It is estimated that it will cost $100,000 with Delta's share being $5,000. The next milestone for Aera will 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. The milestone date for the RFP is November 2001. The affected operating companies have 36 formed a committee to cooperate in the process of mobilizing the mobile drilling unit. It is anticipated that this committee will prepare the RFP for submission to the contractors and MMS. It is estimated that it will cost $210,000 to complete the RFPs with Delta's share being $10,500. The last milestone for the Point Sal Unit will be to begin the drilling of a delineation well. The drilling operations are expected to begin in February 2003 at a cost of $13,000,000. Delta's 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, 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. The next milestone for the Sword Unit is the DPP for Platform Hermosa, which must be submitted to the MMS in September 2001. It is estimated that the cost of filing the DPP will be $360,000, with Delta's share being $10,500. In February 2000, Samedan timely submitted the Project Description for the Gato Canyon Unit. In August 2000, after responding to MMS' request for additional information and clarification, Samedan filed the revised Project Description. In September 2001, the updated Exploration Plan for the Gato Canyon Unit must be submitted to the MMS. As the operator of the property, Samedan intends to submit the EP next September. It is estimated that it will cost $300,000, with Delta's share being $49,500. The next milestone for Gato Canyon will 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. The milestone date for the RFP is November 2001. It in anticipated that the same committee that is preparing the RFPs for the Aera properties will prepare the RFP for Gato Canyon for submittal to the contractors and MMS. It is estimated that it will cost $450,000 to complete the RFP, with Delta's cost estimated at $75,000. The last milestone will be to begin drilling operations on the Gato Canyon Unit by May 1, 2003 using the committee's mobile drilling unit (MODU). The cost of the drilling operations are estimated to be $11,000,000 with Delta's share being $1,750,000. The Rocky Point Unit leases were recently granted an extension and are held under Suspension of Production were recently granted an extension and are held under status through June, 2002. This Unit operator has prepared and timely submitted a Project Description for the development program to the MMS as the first milestone in the Schedule of Activities for the Unit. The operator, under the auspices of the MMS, has also made a presentation of the Project to the affected Federal, State and local agencies. 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 2001 and $1.0 million and $4.2 million are expected to be incurred during fiscal 2002 and 2003, respectively. There are additional, as yet undetermined, costs that we 37 expect in connection with the development of the fifth undeveloped property in which we have an interest (Rocky Point Unit). 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 interest. 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. Point Arugello 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 Petroleum. In an agreement between Whiting and Delta (see Form 8-K dated June 9, 1999), Whiting agreed to retain all of the abandonment costs associated with our interest in the Point Arguello Unit and the related facilities. We have already participated in the redrills of three wells in calendar 2000 and anticipate that we will participate in the redrilling of five to seven wells in calendar year 2001. Each redrill will cost approximately $1.71 million ($105,000 to our interest). We anticipate the redrill costs to be paid through current operations or additional financing. Onshore On July 10, 2000 and on September 28, 2000, we paid $3,745,000 and $1,845,000, respectively, 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 payments resulted in the acquisition by us 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 our officers, while the payment of $1,845,000 on September 28, 2000 was primarily paid out of our net revenues from the effective date of the acquisitions through closing. (See footnote 3) 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 38 Petroleum Corporation and its affiliates. We paid Saga and its affiliates $500,000 in cash and issued an additional 156,160 (289,583 in total) shares of our restricted common stock as a deposit required by the Purchase and Sale Agreement between the parties. On December 18, 2000, we entered into an agreement with SAGA Petroleum Corporation ("Saga") which replaces and supersedes the September 6, 2000 agreement. Under this agreement, we will acquire a producing as property for $2,700,000 of which $2,100,000 has been paid in cash and the remaining $600,000 has been paid with 181,269 shares of our restricted common stock. SAGA is obligated by the agreement to return 393,006 shares of our restricted common stock that was issued as a deposit. We estimate our capital expenditures for onshore properties to be approximately $1,500,000 for the year ended June 30, 2001. 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. Equity Transactions During the year ended June 30, 1998, we issued 22,500 shares of our common stock to a former employee as part of a severance package. This transaction was recorded at its estimated fair market value of the common stock issued of approximately $65,000 and expenses, which was based on the quoted market price of the stock at the time of issuance. The Company also agreed to forgive approximately $20,000 in debt owed to us by the former employee. On July 8, 1998, we completed a sale of 2,000 shares of our common stock to an unrelated individual for net proceeds to Delta of $6,475 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 July 8, 1998, we completed a sale of 2,000 shares of our common stock to Ralf Knueppel for net proceeds to Delta of $6,475 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 on the quoted market price of the stock at the time of issuance. The options were valued at $216,670 based on the estimated fair value of the options issued and recorded at $623,920 as undeveloped oil and gas properties. On December 1, 1998, we issued 10,000 shares of our common stock valued at $15,750, 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. 39 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. 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 $32,063, 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 5, 2000, we issued 60,000 shares of our restricted common stock, at a price of $2.14 per share and valued at $128,250, 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. On June 1, 2000, we issued 90,000 shares of our common stock, at a price of $3.04 per share and valued at $273,375, 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. During fiscal 2000, we issued 215,000 shares of our common stock, at a price of $2.56 per share and valued at $549,563, 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 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 $5.6 million in cash consideration and the issuance of 500,000 shares of the our common stock with an estimated fair value of $1,133,550. 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 $95,481 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 January 1, 1999 and January 4, 2000, we completed the sale of 194,444 and 175,000 shares, respectively, of our common stock in a private transaction to an unrelated entity for net proceeds for each issuance to us of $350,000. 40 On July 5, 2000, we completed the sale of 258,621 shares of our restricted common stock to an unrelated entity for $750,001. 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 and 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 paid an aggregate of 30,000 shares of our restricted common stock, at a price of $3.38 per share and valued at $116,451, 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 $73,828, to CEC Inc. in exchange for an option to purchase certain properties owned by CEC Inc. and its partners. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time the Company committed to the transaction and recorded in oil and gas properties. On September 7, 2000, we issued 103,423 shares of our restricted common stock, at a price of $4.95 per share and valued at $511,944, 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 $1,646,474, 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 the Company committed to the transaction and is recorded in oil and gas properties. 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 $1,335,702, to Saga Petroleum Corporation ("SAGA") 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. 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 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 and is recorded in oil and gas properties. 41 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 two unrelated individuals for their efforts and consultation related to the transaction. On January 3, 2001, we entered into an agreement with Evergreen Resources, Inc. ("Evergreen"), also a shareholder, whereby Evergreen 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, Evergreen must transfer the 116,667 shares of the 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 $1,102,500. We paid a cash commission of $110,250 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. The options were valued at approximately $200,000. Both the commission and the value of the options have been recorded as an adjustment to equity. On July 21, 2000, we entered into an investment agreement with Swartz Private Equity, LLC ("Swartz") and issued Swartz a warrant to purchase 500,000 shares of common stock exercisable at $3.00 per share until May 31, 2005. A warrant to purchase 150,000 shares of the Company's common stock at $3.00 per share for five years was also issued to another unrelated company as consideration for its efforts in this transaction and have been recorded as an adjustment to equity. In the aggregate, we issued options to Swartz and the other unrelated company valued at $1,435,797 as consideration for the firm underwriting commitment of Swartz and related services to be rendered and recorded in additional paid in capital. The options were valued at market based on the quoted market price at the time of issuance. The investment agreement entitles us to issue and sell ("Put") up to $20 million of our common stock to Swartz, subject to a formula based on our stock price and trading volume over a three year period following the effective date of a registration statement covering the resale of the shares to the public. Pursuant to the terms of this investment agreement the Company is not obligated to sell to Swartz all of the common stock 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 we sell shares to Swartz, we are 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, we must have an effective registration statement on file with the Securities and Exchange Commission covering the resale to the public by Swartz of any shares that it acquires under the investment agreement. The Company has filed a registration statement covering the Swartz transaction with the SEC. Swartz will pay us the lesser of the market price for each share minus $0.25, or 91% of the market price for each share of common stock under the Put. The market price of the shares of common stock during the 20 business days immediately following the date we exercise a Put 42 is used to determine the purchase price Swartz will pay and the number of shares we will issue in return. If we do not Put at least $2,000,000 worth of common stock to Swartz during each one year period following the effective date of the Investment Agreement, we must pay Swartz an annual non-usage fee. This fee equals the difference between $200,000 and 10% of the value of the shares of common stock we Put to Swartz during the one year period. The fee is due and payable on the last business day of each one year period. Each annual non-usage fee is payable to Swartz, in cash, within five (5) business days of the date it accrued. We are not required to pay the annual non-usage fee to Swartz in years we have met the Put requirements. We are also not required to deliver the non-usage fee payment until Swartz has paid us for all Puts that are due. If the investment agreement is terminated, we must pay Swartz the greater of (i) the non-usage fee described above, or (ii) the difference between $200,000 and 10% of the value of the shares of common stock Put to Swartz during all Puts to date. We may terminate our right to initiate further Puts or terminate the investment agreement at any time by providing Swartz with written notice of our intention to terminate. However, any termination will not affect any other rights or obligations we have concerning the investment agreement or any related agreement. We cannot determine the exact number of shares of our common stock issuable under the investment agreement and the resulting dilution to our existing shareholders, which will vary with the extent to which we utilize the investment agreement, the market price of our common stock and exercise of the related warrants. 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. We received proceeds from the exercise of options to purchase shares of our common stock of $994,174 during the nine months ended March 31, 2001 and $1,377,536 during the year ended June 30, 2000. These proceeds were obtained from the exercise of 206,500 options to purchase shares of our common stock for an aggregate of $641,250 by persons or entities not affiliated with us and the exercise of 435,295 options to purchase shares of our common stock for an aggregate of $352,924 by our employees during the nine months ended March 31, 2001. We received proceeds from the exercise of 657,000 options to purchase shares of our common stock for an aggregate of $1,255,000 by persons or entities not affiliated with us and the exercise of 391,777 options to purchase shares of our common stock for an aggregate of $122,536 by our employees during the year ended June 30, 2000. We received proceeds from the exercise of 120,000 options to purchase shares of our common stock for an aggregate of $160,000 by persons or entities not affiliated with us during the year ended June 30, 1999. 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 43 be able to do so or that we will be able to do so upon terms that are acceptable. We will continue to explore additional sources of both short-term and long-term liquidity to fund our operations and our capital requirements for development of our properties including establishing a credit facility, sale of equity or debt securities and sale of properties. Many of the factors which may affect our future operating performance and liquidity are beyond our control, including oil and natural gas prices and the availability of financing. After evaluation of the considerations described above, we presently believe that our cash flow from our existing producing properties and other sources of funds will be adequate to fund our operating expenses and satisfy our other current liabilities over the next year or longer. If it were necessary to sell an existing producing property or properties to meet our operating expenses and satisfy our other current liabilities over the next year or longer we believe we would have the ability to do so. Market Risk Market risk is the potential loss arising from adverse changes in market rates and prices, such as foreign currency exchange and interest rates and commodity prices. We do not use financial instruments to any degree to manage foreign currency exchange and interest rate risks and do not hold or issue financial instruments to any degree for trading purposes. All of our revenue and related receivables are payable in U.S. dollars. We do have a contract to sell 6,000 barrels a month at $27.31 through February 28, 2002. We were subject to interest rate risk on $12,478,835 of variable rate debt obligations at March 31, 2001. The annual effect of a one percent change in interest rates would be approximately $125,000. The interest rate on these variable rate debt obligations approximates current market rates as of March 31, 2001. Other On April 2, 2001, our Board of Directors appointed our President Roger A. Parker to the additional position of Chief Executive Officer and appointed our Chief Financial Officer Kevin K. Nanke to the additional position of Treasurer. Results of Operations Three and Nine Months Ended March 31, 2001 Compared to Three and Nine Months Ended March 31, 2000 --------------------------------------------------------- Income (loss). We reported net income for the three and nine months ended March 31, 2001 of $331,290 and $893,453 compared to a net loss of $1,017,579 and $2,488,384 for the three and nine months ended March 31, 2000. The net income and net loss for the three and nine months ended March 31, 2001 and 2000 were effected by numerous items, described in detail below. Revenue. Total revenue for the three and nine months ended March 31, 2001 was $3,701,866 and $9,475,596 compared to $1,223,149 and $1,956,105 for the three and nine months ended March 31, 2000. Oil and gas sales for the three and nine months ended March 31, 2001 were $3,660,638 and $9,351,912 compared to $1,180,436 and 1,852,135 for the three and nine months ended March 31, 2000. The increase of $7,499,777 in oil and gas revenue comparing the 44 nine months ended March 31, 2001 to the nine months ended March 31, 2000 is primarily attributed to the acquisitions that occurred during the fiscal year ended June 30, 2000 and the quarter ended September 30, 2000. During the nine months ended March 31, 2001, we sold 215,547 barrels of oil from our interests in the Point Arguello Unit located in federal waters offshore California and sold 185,328 Mcf of gas and 6,536 barrels of oil from our interests in the our New Mexico properties. Both of these properties were acquired during fiscal 2000. We also sold 33,279 Mcf of gas and 71,089 barrels of oil from the North Dakota acquisition and sold 29,547 barrels of oil from the West Delta Block 52 acquisition both of which closed during the quarter ended September 30, 2000. Other Revenue. Other revenue includes 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 three and nine months ended March 31, 2001 and 2000 are as follows: Three Months Ended Nine Months Ended March 31, March 31, --------- --------- 2001 2000 2001 2000 ---- ---- ---- ---- Production-Onshore: Oil (Bbls) 26,946 3,680 81,530 7,544 Gas (Mcfs) 157,863 114,478 393,968 285,011 Average Price-Onshore : Oil (per Bbls) $29.04 $27.13 $28.30 $23.17 Gas (per Mcf) $ 7.62 $ 2.57 $ 6.54 $ 2.28 Production-Offshore- Oil (Bbls) 84,566 76,140 245,495 106,996 Gas (Mcfs) 675 - 675 - Average Price-Offshore- Oil (per Bbls) $19.70 $10.26 $18.17 $ 9.97 Gas (per Mcfs) $13.33 - $13.33 - Average Price-Offshore Point Arguello Oil (per Bbls) gross price $18.41 $21.38 $21.95 $21.14 Oil (per Bbls) net price $18.41 $10.26 %16.59 $ 9.97 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. Lease Operating Expenses. Lease operating expenses were $1,520,604 and $3,782,468 for the three and nine months ended March 31, 2001 compared to $951,903 and $1,363,850 for the same periods in 2000. On a Bbl equivalent basis, lease operating expenses were $3.23 and $4.37, during the three and nine months ended March 31, 2001 compared to $4.33 and $4.69 for the same periods in 2000 for onshore properties. On a barrel equivalent basis, lease operating expenses were $15.89 and $12.72 during the three and nine months ended March 31, 2001 and $11.60 and $10.33 for the same periods in 2000 for the offshore properties. The increase in lease operating expenses can be attributed to the acquisitions discussed above and significant work-over costs relating to our West Delta Block 52 unit offshore Louisiana. 45 Depreciation and Depletion Expense. Depreciation and depletion expense for the three and nine months ended March 31, 2001 was $599,673 and $1,555,522 compared to $187,905 and $394,947 for the same period in 2000. On a barrel equivalent basis, the depletion rate was $7.80 and $6.49 for the three and nine months ended March 31, 2001 and $4.96 and $4.69 for the same periods in 1999 for onshore properties. On a barrel equivalent basis, the depletion rate was $2.44 and $2.17 for the three and nine months ended March 31, 2001 compared to $.98 and $1.26 for the same periods in 2000 for offshore properties. Exploration Expenses. We incurred exploration expenses of $26,530 and $48,859 for the three and nine months ended March 31, 2001 compared to $15,251 and $37,495 for the same period in 2000. Professional fees. Professional fees for the three and nine months ended March 31, 2001 were $345,702 and $815,177 compared to $62,711 and $343,524 for the same period in 2000. The increase in professional fees are primarily attributed legal fees for representation in negotiations and discussions with various state and federal governmental agencies relating to the company's undeveloped offshore California leases. General and Administrative Expenses. General and administrative expenses for the three and nine months ended March 31, 2001 were $268,397 and $895,177 compared to $463,146 and $973,891 for the same periods in 2000. The increase in general and administrative expenses are primarily attributed to the increase in travel, corporate filings and the addition of a new employee. Stock Option Expense. Stock option expense has been recorded for the three and nine months ended March 31, 2001 of $45,413 and $334,383 compared to $81,795 and $293,860 for the same period in 2000, 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. Other income. Other income during the six months ended December 31, 2000 includes the sale of our unsecured claim in bankruptcy against our former parent, Underwriters Financial Group in the amount of $350,000. Interest and Financing Costs. Interest and financing costs for the three and nine months ended March 31, 2001 were $503,720 and $1,494,865 compared to $384,152 and $941,360 for the same period in 2000. The increase in interest and financing costs can be attributed to the new debt established to purchase certain oil and gas properties. 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 $3,597,548 compared to the net loss of $1,580,501 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 $3,665,981 compared to $1,717,655 for the year ended June 30, 1999. Oil and gas sales for the year ended June 30, 2000 were $3,355,783 compared to $557,507 for the year ended June 30, 1999. The increase in oil and gas sales during the year 46 ended June 30, 2000 resulted from the acquisition of eleven producing wells in New Mexico and Texas and the acquisition of an interest in the offshore California Point Arguello Unit. The increase in oil and gas sales were also impacted by the increase in oil and gas prices. If we would have not committed to sell our proportionate shares of our barrels at $8.25 and $14.65 per barrel, we would have realized an increase in income of $2,033,153. 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 $957,147 for the years ended June 30, 2000 and 1999, respectively. Other Revenue. Other revenue represents amounts recognized from the production of gas previously deferred pending determination of our interests in the properties. Production volumes and average prices received for the years ended June 30, 2000 and 1999 are as follows: 2000 1999 Onshore Offshore Onshore Offshore ------- -------- ------- -------- Production: Oil (barrels) 9,620 186,989 5,574 - Gas (Mcf) 362,051 - 254,291 - Average Price: Oil (per barrel) $25.95 $11.54* $10.24 - Gas (per Mcf) $ 2.62 - $1.97 - Average Price-Offshore Point Arguello Oil (per Bbls) gross price - $21.14 - - Oil (per Bbls) net price - $11.54 - - *We 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. Lease Operating Expenses. Lease operating expenses for the year ended June 30, 2000 were $2,405,469 compared to $209,438 for the year ended June 30, 1999. On a per Bbl equivalent basis, production expenses and taxes were $4.94 for onshore properties and $11.02 for offshore properties during the year ended June 30, 2000 compared to $4.37 for onshore properties for the year ended June 30, 1999. The increase in lease operating expense compared to 1999 resulted from the acquisition of an interest in eleven new properties onshore and an interest in the offshore Point Arguello Unit near Santa Barbara, California. In general the cost per Bbl for offshore operations are higher than onshore. The offshore properties had approximately $175,000 in non capitalized workover cost included in lease operating expense. Depreciation and Depletion Expense. Depreciation and depletion expense for the year ended June 30, 2000 was $887,802 compared to $229,292 for the 47 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 $46,730 for the year ended June 30, 2000 compared to $74,670 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 $273,041. Our proved properties were assessed for impairment on an individual field basis and we recorded impairment provisions attributable to certain producing properties of $103,230 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 $169,811. 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 $1,777,579 compared to $1,506,683 for the year ended June 30, 1999. The increase in general and administrative expenses compared to fiscal 1999, can be attributed to an increase in shareholder relations and professional services relating to Securities and Exchange related filings. Stock Option Expense. Stock option expense has been recorded for the years ended June 30, 2000 and 1999 of $537,708 and $2,080,923, 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 $1,264,954 and $19,726, respectively. The increase in interest and financing costs can be attributed to the new debt established to purchase oil and gas properties. 48 Year Ended June 30, 1999 Compared to Year Ended June 30, 1998 ------------------------------------------------------------- Net Earnings (Loss). Our net loss for the year ended June 30, 1999 was $2,998,759 compared to the net loss of $962,003 for the year ended June 30, 1998. The losses for the years ended June 30, 1999 and 1998 were effected by numerous items described in detail below. Revenue. Total revenue for the year ended June 30, 1999 was $1,580,501 compared to $1,958,967 for the year ended June 30, 1998. Oil and gas sales for the year ended June 30, 1999 were $557,503 compared to $1,225,115 for the year ended June 30, 1998. The decrease in oil and gas sales during the year ended June 30, 1999 resulted form the sale of certain properties, which resulted in a gain of $957,147, and the decease in oil and gas prices during fiscal 1999. If we would have not committed to sell our proportionate shares of our barrels at $8.25 per barrel, we would have realized an increase in income of $2,033,153. Production Volumes and average prices received for the years ended June 30, 1999 and 1998 are as follows: 1999 1998 -------- ------- Production: Oil (barrels) 5,574 11,632 Gas (Mcf) 254,291 457,758 Average Price: Oil (per barrel) $10.24 $16.46 Gas (per Mcf) $ 1.97 $ 2.26 Lease Operating Expenses. Lease operating expenses for the year ended June 30, 1999 were $209,438 compared to $349,551 for the year ended June 30, 1998. On an Mcf equivalent basis, production expenses and taxes were $.73 per Mcf equivalent during the year ended June 30, 1998. The increase in lease operating costs on an equivalent basis compared to 1998 resulted primarily from the selling of lower operated properties. Depreciation and Depletion Expense. Depreciation and depletion expense for the year ended June 30, 1999 was $229,292 compared to $303,563 for the year ended June 30, 1998. On a Mcf equivalent basis, the depletion rate was $.80 per Mcf equivalent during the year ended June 30, 1999 compared to $.58 per Mcf equivalent for the year ended June 30, 1998. The increase in depreciation and depletion expense is a result of lower average lives on newly drilled wells. Exploration Expenses. Exploration expenses consists of geological and geophysical costs and lease rentals. Exploration expenses were $74,670 for the year ended June 30, 1999 compared to $515,383 for the year ended June 30, 1998. The exploration expenses during fiscal 1998 were abnormally high and primarily represent costs associated with our participation in the shooting of 3-D seismic on prospects in the Sacramento Basin of Northern California. Abandonment and Impairment of Oil and Gas Properties. We recorded an expense for the abandonment and impairment of oil and gas properties for the 49 year ended June 30, 1999 of $273,041 compared to $128,993 in 1998. Our proved properties were assessed for impairment on an individual field basis and we recorded impairment provisions attributable to certain producing properties of $103,230 and $128,993 for the years ended June 30, 1999 and 1998, respectively. The expense in 1999 also includes a provision for impairment of the costs associated with the Sacramento Basin of Northern California of $169,811. We made a determination based on drilling results that it will not be economical to develop certain prospects and as such we will not proceed with these prospects. See "Description of Properties." Professional Fees and General and Administrative Expense. General and administrative expenses for the year ended June 30, 1999 were $1,506,683 compared to $1,433,461 for the year ended June 30, 1998. Stock Option Expense. Stock option expense has been recorded for the years ended June 30, 1999 and 1998 of $2,080,923 and $46,402, respectively, for options granted to certain officers, directors, employees and consultants at option prices below the market price at the date of grant. 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 repricing of 980,477 options to purchase shares of our common stock for the two officers at a price of $.05 per share under the Incentive Plan. The Committee also repriced 150,000 options to purchase shares of our common stock to tow employees at a price of $1.75 per share under the Incentive Plan. Stock option expense of $1,985,414 has been recorded based on the difference between the option price and the quoted market price on the date of grant and repricing of the options. Gain or Write-Off of Royalty Payable. We set up a reserve for potential royalties received on the royalty owners' behalf. After numerous attempts by us and royalty owners to determine if the operators had paid the royalty owners on our behalf, there has been no resolution. Accordingly, based on attorney representation, these amounts have been written-off as the statute of limitations has expired. Royalty to Related Party. The royalty to related party represents the $350,000 paid in 1998 under the terms of the agreement with Ogle to acquire interests in three undeveloped offshore Santa Barbara, California federal oil and gas units. On December 17, 1998, we amended our Purchase and Sale Agreement with Burdette A. Ogle ("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 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, according to this agreement, we extended and repriced a previously issued warrant to purchase 100,000 shares of our common stock. The $60,000 fair value placed on the extension and repricing of this warrant was recorded as an addition to undeveloped offshore California properties. As of June 30, 1999, we have paid a total of $1,550,000 in minimum royalty payments. Recently Issued or Proposed Accounting Standards and Pronouncements. In March 2000, the Financial Accounting Standards Board ("FASB") issued FASB Interpretation No. 44 "Accounting for Certain Transactions involving Stock Compensation- and interpretation of APB Opinion No. 25 ("FIN 44"). This 50 opinion provides guidance on the accounting for certain stock option transactions and subsequent amendments to stock option transactions. FIN 44 is effective July 1, 2000, but certain conclusions cover specific events that occur after either December 15, 1998 or January 12, 2000. To the extent that FIN 44 covers events occurring during the period from December 15, 1998 and January 12, 2000, but before July 1, 2000, the effects of applying this interpretation are to be recognized on a prospective basis. Repriced options mentioned above may impact future periods. The adoption of FIN 44 had no impact on our financial position or results of operations. In December 1999, the SEC released Staff Accounting Bulletin ("SAB") No. 101, "Revenue Recognition in Financial Statements", which provides guidance on the recognition, presentation and disclosure of revenue in financial statements filed with the SEC. Subsequently, the SEC released SAB 101B, which delayed the implementations date of SAB 101 for registrants with fiscal years beginning between December 16, 1999 and March 15, 2000. The adoption of SAB 101 had no impact on our financial position or results of operations. Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133), was issued in June 1998, by the Financial Accounting Standards Board. SFAS 133 establishes new accounting and reporting standards for derivative instruments and for hedging activities. This statement required an entity to establish at the inception of a hedge the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach for determining the ineffective aspect of the hedge. Those methods must be consistent with the entity's approach to managing risk. SFAS 133 was amended by SFAS 137 and is effective for all fiscal quarters of fiscal years beginning after June 15, 2000. The adoption of SFAS 133 had no impact on our financial statements or results of operations. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS. Name Age Positions Period of Service ---- -- --------- ----------------- Roger A. Parker 39 President, Chief Executive May 1987 Officer and a Director to present Aleron H. Larson, Jr. 55 Chairman of the Board, May 1987 Secretary and a Director to present Terry D. Enright 52 Director November 1987 to Present Jerrie F. Eckelberger 56 Director September 1996 to Present Kevin K. Nanke 36 Treasurer and Chief December 1999 Financial Officer to Present The following is biographical information as to the business experience of each of our current officers and directors. Roger A. Parker, age 39, served as the President, a Director and Chief Operating Officer of Underwriters Financial Group ("UFG") (formerly Chippewa Resources Corporation) from July of 1990 through March 31, 1993. Subsequent 51 to a change of control, Mr. Parker resigned from all positions with UFG effective March 31, 1993. Mr. Parker also serves as President, Chief Operating Officer and Director of Amber. He also serves as a Director and Executive Vice President of P & G Exploration, Inc., a private oil and gas company (formerly Texco Exploration, Inc.). Mr. Parker has also been the President, a Director and sole shareholder of Apex Operating Company, Inc. since its inception in 1987. He has operated as an independent in the oil and gas industry individually and through public and private ventures since 1982. He 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). Aleron H. Larson, Jr., age 55, 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 UFG. Subsequent to a change of control, Mr. Larson resigned from all positions with UFG effective March 31, 1993. Mr. Larson serves as Chairman, CEO, Secretary, Treasurer and Director of Amber Resources Company ("Amber"), a public oil and gas company which is OUR majority-owned subsidiary. He has also served, since 1983, as the President and Board Chairman of Western Petroleum Corporation, a public Colorado oil and gas company which is now inactive. Mr. Larson practiced law in Breckenridge, Colorado from 1971 until 1974. During this time he was a member of a law firm, Larson & Batchellor, engaged primarily in real estate law, land use litigation, land planning and municipal law. In 1974, he formed Larson & Larson, P.C., and was engaged primarily in areas of law relating to securities, real estate, and oil and gas until 1978. Mr. Larson received a Bachelor of Arts degree in Business Administration from the University of Texas at El Paso in 1967 and a Juris Doctor degree from the University of Colorado in 1970. Terry D. Enright, age 52, has been in the oil and gas business since 1980. Mr. Enright was a reservoir engineer until 1981 when he became Operations Engineer and Manager for Tri-Ex Oil & Gas. In 1983, Mr. Enright founded and is President and a Director of Terrol Energy, a private, independent oil company with wells and operations primarily in the Central Kansas Uplift and D-J Basin. In 1989, he formed and became President and a Director of a related company, Enright Gas & Oil, Inc. Since then, he has been involved in the drilling of prospects for Terrol Energy, Enright Gas & Oil, Inc., and for others in Colorado, Montana and Kansas. He has also participated in brokering and buying of oil and gas leases and has been retained by others for engineering, operations, and general oil and gas consulting work. Mr. Enright received a B.S. in Mechanical Engineering with a minor in Business Administration from Kansas State University in Manhattan, Kansas in 1972, and did graduate work toward an MBA at Wichita State University in 1973. He is a member of the Society of Petroleum Engineers and a past member of the American Petroleum Institute and the American Society of Mechanical Engineers. Jerrie F. Eckelberger, age 56, is an investor, real estate developer and attorney who has practiced law in the State of Colorado for 28 years. 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 52 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. Kevin K. Nanke, age 36, 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 Delta, he was employed by KPMG LLP. He is a member of the Colorado Society of CPA's and the Council of Petroleum Accounting Society. There is no family relationship among or between any of officers and/or the directors. Messrs. Enright and Eckelberger serve as the Audit Committee and as the Compensation Committee. Messrs. Enright and Eckelberger also constitute our Incentive Plan Committee for the Delta 1993 Incentive Plan. All directors will hold office until the next annual meeting of shareholders. All of our officers will hold office until our next annual directors' meeting. There is no arrangement or understanding among or between any such officer or any person by which such officer is to be selected as an officer of Delta. 53 EXECUTIVE COMPENSATION EXECUTIVE COMPENSATION SUMMARY COMPENSATION TABLE ANNUAL COMPENSATION

LONG TERM COMPENSATION ANNUAL COMPENSATION AWARDS SECURITIES UNDERLYING NAME AND OPTIONS/ ALL OTHER PRINCIPAL POSITION PERIOD SALARY(1) BONUS SARS(#) COMPENSATION($) ------------------ ------ --------- ----- ----------- --------------- Roger A. Parker President, Chief Executive Officer Year Ended and Director 6/30/00 $198,000 $ 75,000 100,000(2) -0- Year Ended 6/30/99 198,000 105,000 510,663(3) -0- Year Ended 6/30/98 198,000 -0- 253,427(5) -0- Aleron H. Larson, Jr. Chairman, Secretary, Year Ended and Director 6/30/00 $198,000 $ 75,000 100,000(2) -0- Year Ended 6/30/99 198,000 105,000 559,500(4) -0- Year Ended 6/30/98 198,000 -0- 275,000(5) -0- Kevin K. Nanke Year Ended Treasurer and Chief 6/30/00 $105,417 $ 15,000 100,000(6) -0- Financial Officer ---------------------------------

(1) Includes reimbursement of certain expenses. (2) Option to purchase 100,000 shares of common stock at $1.75 per share until November 5, 2009. (3) Represents all options held by individual at June 30, 1999. 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. (4) Represents all options held by individual at June 30, 1999. 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. 54 (5) Previously granted options: exercise price repriced from $3.25 to $1.66 and expiration date extended until December 8, 2007 during fiscal year 1998 and repriced again in 1999 as described in Notes 2 and 3 above. These options are included in the options described in Notes 2 and 3 above. (6) Represents option to purchase 75,000 shares of common stock at $1.75 per share until November 5, 2009 and option 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 MARKET UNDERLYING GRANTED TO EXERCISE PRICE ON OPTIONS/SAR's EMPLOYEES IN OR BASE DATE OF EXPIRATION NAME GRANTED FISCAL YEAR PRICE($/sh) GRANT($/sh) DATE ---- ------------- ------------- ----------- ----------- ---------- Roger A. Parker 100,000 28.57% $1.75 $1.75 11/05/09 Aleron H. Larson, Jr. 100,000 28.57% $1.75 $1.75 11/05/09 Kevin K. Nanke 75,000 21.43% $1.75 $1.75 11/05/09 25,000 7.14% .01 .01 12/31/09

AGGREGATED OPTIONS/EXERCISES IN LAST FISCAL YEAR AND FY-END OPTION/VALUES

NUMBER OF SECURITIES VALUE OF UNDERLYING UNEXERCISED UNEXERCISED IN-THE-MONEY OPTIONS OPTIONS SHARES AT AT ACQUIRED JUNE 30, 2000(#) JUNE 30, 2000($) ON REALIZED EXERCISABLE/ EXERCISABLE/ NAME EXERCISE (#) $ UNEXERCISABLE UNEXERCISABLE ---- ------------ -------- ---------------- ----------------- Roger A. Parker 260,427 513,501 350,336/0 $1,188,915/0 President Aleron H. Larson, Jr. 40,000 $101,120 619,500/0 $2,233,660/0 Chairman Kevin K. Nanke 25,000 53,750 298,900/0 718,102/0 Chief Financial Officer

55 Compensation of Directors. As a result of elections made by non-employee directors under the formulas provided in our 1993 Incentive Plan, as amended, we granted options to non-employee directors as follows: Number Exercise Expiration Director Of Options Price Date -------- ---------- -------- ---------- Terry D. Enright 10,000 $1.30 1/20/2010 Jerrie F. Eckelberger 10,000 1.30 1/20/2010 In addition, the outside non-employee directors are each paid $500.00 per month. Jerrie F. Eckelberger and Terry D. Enright were each paid $6,000 during the year ended June 30, 2000. Employment Contracts and Termination of Employment and Change-in-Control Agreement. On April 10, 1998, our Compensation Committee authorized us enter into employment agreements with our Chairman and President, 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 $198,000 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 1993 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, 2000, we contributed $17,565 under the Plan. 56 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 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 April 24, 2001. Name and Address Amount and Nature of Beneficial of Beneficial Percent Title of Class (1) Owner Ownership of Class (2) ----------------- ---------------- ----------------- ------------ Common stock Aleron H. Larson, Jr. 1,319,657 shares(3) 10.87% (includes options 555 17th St., #3310 for common stock) Denver, CO 80202 Common stock Roger A. Parker 1,255,057 shares(4) 10.68% (includes options 555 17th St., #3310 for common stock) Denver, CO 80202 Common stock Bank Leu AG 843,621 shares(5) 7.78% Bahnhofstrasse 32 8022 Switzerland Common stock GlobeMedia AG 835,346 shares(6) 7.30% (includes options Immanuel Hohlbauch for common stock) Strasse 41 Goppingen/Germany Common stock Burdette A. Ogle 761,891 shares(7) 6.96% (includes options 1224 Coast Village Rd, #24 for common stock) Santa Barbara, CA 93108 Common stock Evergreen Resources, Inc 643,061 shares 5.93% 1401 17th Street Suite 1200 Denver, CO 80202 Common stock BWAB Limited Liability 642,430 shares 5.93% Company 475 17th Street Suite 1390 Denver, CO 80202 ------------------------ (1) We have an authorized capital of 300,000,000 shares of $.01 par value common stock of which 10,908,600 shares were issued and outstanding as of April 24, 2001. We also have an authorized capital of 3,000,000 shares of $.10 par value preferred stock of which no shares were outstanding at March 31, 2001. (2) The percentage set forth after the shares listed for each beneficial owner is based upon total shares of common stock outstanding at March 31, 2001 of 10,840,100. The percentage set forth after each beneficial owner is 57 calculated as if any warrants and/or options owned had been exercised by such beneficial owner and as if no other warrants and/or options owned by any other beneficial owner had been exercised. Warrants and options are aggregated without regard to the class of warrant or option. (3) Includes 12,467 shares owned by Mr. Larson's wife and 4,000 shares owned by his children; and 453,190 options to purchase 453,190 shares of common stock at $0.05 per share until September 1, 2008 for 353,190 of the options and until December 10, 2008 for 100,000 of these 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; and options to purchase 200,000 shares of common stock at $3.29 per share until January 8, 2011. (4) Includes 346,681 shares owned by Mr. Parker directly and 58,376 options to purchase 58,376 shares of common stock at $0.05 per share until May 20, 2009. 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; and options to purchase 200,000 shares of common stock at $3.29 per share until January 8, 2011. (5) Shares are held by Bank Leu AG as nominee for various beneficial owners, none of which owns beneficially greater than 5% of our stock. Bank Leu AG holds record title only and does not have voting or investment power for the shares. (6) Consists of 30,692 shares owned directly by GlobeMedia AG; 46,154 shares owned by Quadrafin AG; options to purchase 168,000 shares of common stock at $2.50 per share until April 10, 2002; options to purchase 200,000 shares of common stock at $4.5625 per share for a period of one year beginning with the effective date of a registration statement covering the shares underlying the options; options in the name of Pegasus Finance Limited, an affiliate of GlobeMedia AG, to purchase common stock for periods beginning with the effective date of a registration statement covering the common shares underlying the options as follows: 100,000 shares at $2.50 per share for one year; 100,000 shares at $3.00 per share for one year; 100,000 shares at $6.00 per share for one year; and options, also in the name of Pegasus Financial Limited, to purchase 100,000 shares of common stock at $3.125 per share until January 9, 2004. (7) Includes 635,264 shares owned by Mr. Ogle directly, 26,627 shares owned beneficially by Sunnyside Production Company, and warrants to purchase 100,000 shares of common stock at $3.00 per share until August 31, 2004, with a call provision that allows us to repurchase any unexercised warrants for an aggregate sum of $1,000 after our stock has traded for $6.00 per share or greater for 30 consecutive trading days. 58 Security Ownership of Management: Amount and Nature Title of Name of Beneficial of Beneficial Percent Class (1) Owner Ownership of Class(2) ------------ --------------------- ------------------- ----------- Common stock Aleron H. Larson, Jr. 1,319,657 shares(3) 10.86% Common stock Roger A. Parker 1,255,057 shares(4) 10.67% Common stock Kevin K. Nanke 489,175 shares(5) 4.32% Common stock Terry D. Enright 25,000 shares(6) 0.23% Common stock Jerrie F. Eckelberger 5,725 shares(7) 0.05% Common stock Officers and Directors 3,094,614 shares(8) 22.83% as a Group (5 persons) ------------------------ (1) See Note (1) to preceding table; includes options. (2) See Note (2) to preceding table. (3) See Note (3) to preceding table. (4) See Note (4) to preceding table. (5) Consists of 25,000 shares of common stock owned directly by Mr. Nanke; options to purchase 39,175 shares of common stock at $1.125 per share until September 1, 2008; options to purchase 25,000 shares of common stock at $1.5625 per share until December 12, 2008; options to purchase 100,000 shares of common stock at $1.75 per share until May 12, 2009; options to purchase 75,000 shares of common stock at $1.75 per share until November 5, 2009; options to purchase 125,000 shares of common stock at $3.75 per share until July 14, 2010; and options to purchase 100,000 shares of common stock at $3.29 until January 9, 2011. (6) Includes 10,000 Class I warrants to purchase shares of common stock at $3.50 per share until June 9, 2003; 7,500 options to purchase shares of common stock at $3.30 per share until November 11, 2006; and 7,500 options to purchase shares of common stock at $3.15 per share until December 31, 2006. (7) Includes 1,875 options to purchase shares of common stock at $2.98 per share until December 31, 2006, and 3,850 options to purchase shares of common stock at $1.88 per share until December 31, 2007. (8) Includes all warrants, options and shares referenced in footnotes (3), (4), (5), (6) and (7) above as if all warrants and options were exercised and as if all resulting shares were voted as a group. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. (1) 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 59 December 1, 1999 we have retained Messrs Ogle and Heck on a month to month basis at the same monthly rate. At January 17, 2001, Messrs. Ogle and Heck own 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. (2) 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 have been produced; or 3) 30 years from the date of the conveyance. Under the terms of the agreement, we may reassign the working interests to Ogle upon notice of not more than 14 months nor less than 12 months, 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, according 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 March 31, 2001, we have 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. 60 We are of the opinion that the transaction is on terms no less favorable to us than those which could have been obtained from non-affiliated parties. No independent determination of the fairness and reasonableness of the terms of the transaction was made by any outside person. (3) Our Board of Directors has granted each of our officers the right to participate in the drilling on the same terms as us 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). Prior to commencement of the work on any such well, Messrs. Larson, Parker and Nanke are required to pay us the cost as estimated by our consulting engineers. (4) On April 10, 1998, our Compensation Committee authorized us to enter into employment agreements with our Chairman and President, 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 1993 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. (5) 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. On that date, our officers purchased 47,250 shares for $237,668. (6) Our officers, Aleron H. Larson, Jr., Chairman, and Roger A. Parker, President, loaned us $1,000,000 to make our June 8, 1999 payment to 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.) (7) On July 30, 1999, we borrowed $2,000,000 from an unrelated entity which was personally guaranteed by Aleron H. Larson, Jr., Chairman, and Roger A. Parker, President. The proceeds were applied to the acquisition of Whiting's interests in the Point Arguello Unit and adjacent Rocky Point Unit. As consideration for the guarantee of our indebtedness we agreed to assign a 1% overriding royalty interest to each officer in the properties acquired with the proceeds of the loan (proportionately reduced to the interest we acquired in each property). (See Form 8-K dated August 25, 1999.) (8) On November 1, 1999 we borrowed approximately $2,800,000 from an unrelated entity which was personally guaranteed by Aleron H. Larson, Jr., Chairman, and Roger A. Parker, President. The loan proceeds were used to 61 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.) (9) We operate wells in which our officers or employees or companies affiliated with one of them own working interests. At June 30, 2000 we had $129,730 of net receivables from these related parties (including affiliated companies) primarily for drilling costs and lease operating expenses on wells operated by us. (10) On July 10, 2000, we borrowed $3,795,000 from an unrelated entity which was personally guaranteed by Aleron H. Larson, Jr., Chairman, and Roger A. Parker, President. 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. (11) During the past two years ended March 31, 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 $75,000 for services and expenses relating to shareholder and public relations in Europe and approximately $285,000 in commissions for raising additional capital. (12) 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 half of our interest in three small working interests that are a part of our Offshore California Properties. The value on our books of the interests subject to the option is $550,000. In the event that Evergreen exercises its option and production from the properties has not commenced, Evergreen would be required to pay on our behalf the full amount of the required minimum payment of our purchase price for the interests of $350,000 per year (up to a maximum remaining amount of $6,100,000), and we would retain ownership of a one-half interest in the property without having to pay any 62 part of the purchase price after the date that the option is exercised. If production does commence, however, the first $350,000 per year attributable to both halves of the working interest would go toward payment of the required minimum payment. In any event, Evergreen would be required to return 116,667 shares of our stock to us if the option is exercised, and we would be entitled to keep the $350,000 that Evergreen has already paid. (13) During the past two years ended March 31, 2001 we issued 315,000 shares of restricted common stock to BWAB Limited Liability Company 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 $382,290 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. (14) 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 $1,529,157 and issuing 509,719 shares of our restricted common stock at $3.00 per share. We borrowed $1,463,532 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 Roger A. Parker, President, 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 to us 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, 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. (15) On February 12, 2001, we permitted our officers, Aleron H. Larson, Jr., Chairman, Roger A. Parker, President, and Kevin K. Nanke, 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 Delta 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 Delta's working interest costs of drilling and completing or abandoning the well. The costs may be paid in either cash or Delta common stock at the February 12, 2001 closing price of $5.125 per share. Messrs. Larson and Parker each committed to pay the costs associated with a 5% working interest in the well and Mr. Nanke likewise committed to a 2-1/2% working interest in the well. At March 31, 2001, the working interest costs had not yet been billed. 63 SELLING SECURITY HOLDER We currently only have a total of 10,908,600 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 37.3%. 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." 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. 64 Swartz has agreed to include a dribble-out provision that prevents Swartz from exercising the warrant in excess of a number of shares equal to fifteen percent (15%) of the aggregate trading volume of our Common Stock, on the primary exchange or market upon which our Common Stock is then listed for trading, during the twenty (20) trading days preceding the date of such exercise. The dribble-out provision does not apply if the average closing price of our Common Stock for the five (5) trading days immediately preceding the date of exercise is greater than or equal to eight dollars ($8.00) per share or if we are acquired by another entity. - PUT RIGHTS We may begin exercising Puts on the date of effectiveness of this prospectus and continue for a three-year period. We currently do not intend to issue any shares to Swartz under the Investment Agreement until we obtain shareholder approval. To exercise a Put, we must have an effective registration statement on file with the Securities and Exchange Commission covering the resale to the public by Swartz of any shares that it acquires under the Investment Agreement. Also, we must give Swartz at least 10, but not more than 20, business days advance notice of the date on which we intend to exercise a particular Put right. The notice must indicate the date we intend to exercise the Put and the maximum number of shares of common stock we intend to sell to Swartz. At our option, we may also specify a maximum dollar amount (not to exceed $2 million) of common stock that we will sell under the Put. We may also specify a minimum purchase price per share at which we will sell shares to Swartz. The minimum purchase price cannot exceed 80% of the closing bid price of our common stock on the date we give Swartz notice of the Put. The number of common shares we sell to Swartz may not exceed 15% of the aggregate daily reported trading volume of our common shares during the 20 business days before and 20 days after the date we exercise a Put. Further, we cannot issue additional shares to Swartz that, when added to the shares Swartz previously acquired under the Investment Agreement during the 31 days before the date we exercise the Put, will result in Swartz holding over 9.99% of our outstanding shares upon completion of the Put. Swartz will pay us a percentage of the market price for each share of common stock under the Put. The market price of the shares of common stock during the 20 business days immediately following the date we exercise a Put is used to determine the purchase price Swartz will pay and the number of shares we will issue in return. This 20 day period is the pricing period. For each share of common stock, Swartz will pay us the lesser of: - the market price for each share, minus $.25; or - 91% of the market price for each share. The Investment Agreement defines market price as the lowest closing bid price for our common stock during the 20 business day pricing period. However, Swartz must pay at least the designated minimum per share price, if any, that we specify in our notice. If the price of our common stock is below the greater of the designated minimum per share price plus $.25, or the designated minimum per share price divided by .91 during any of the 20 days during the pricing period, that day is excluded from the 15% volume limitation described above. Therefore, the amount of cash that we can receive for that Put may be reduced if we elect to a minimum price per share and our stock price declines. 65 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. - 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 66 - 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 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. 67 - 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 have agreed to give Swartz a Right of First Offer during this same period, the term of the Investment Agreement plus ninety (90) days. If we commence or plan to commence negotiations with another investor, during this time period, for a private capital raising transaction we will first notify and negotiate in good faith with Swartz regarding the potential financing transaction. If Swartz is more than five (5) business days late in paying for the Put shares, then it is not entitled to the benefits of these restrictions until the date amounts due are paid. Neither of the above restrictions apply to the following items and we may engage in and issue securities in the following transactions without notifying or obtaining approval from Swartz; - in connection with a merger, consolidation, acquisition, or sale of assets; - in connection with a strategic partnership or joint venture, the primary purpose of which is not simply to raise money; - in connection with our disposition or acquisition of a business, product or license; 68 - 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." As noted above, we cannot determine the exact number of shares of our common stock issuable under the Investment Agreement and the resulting dilution to our existing shareholders, which will vary with the extent to which we utilize the Investment Agreement, the market price of our common stock, and exercise of the related warrants. The potential effects of any dilution on our existing shareholders include the significant dilution of the current shareholders' economic and voting interests in us. The Investment Agreement provides that we cannot issue shares of common stock that would exceed 20% of the outstanding stock on the date of a Put unless and until we obtain shareholder approval of the issuance of common stock. The table below includes information regarding ownership of our common stock by Swartz on March 31, 2001 and the number of shares that they may sell under this prospectus. The actual number of shares of our common stock issuable upon exercise of warrants to Swartz and our Put rights is subject to adjustment and could be materially less or more than the amount contained in the table below, depending on factors which we cannot predict at this time, including, among other factors, the future price of our common stock. There are no material relationships with Swartz other than as indicated below. 69 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 37.3% of our outstanding common stock based on the number of shares that we currently have issued and outstanding. It is expected, however, that Swartz will not beneficially own more than 9.9% of our outstanding stock at any one time. PLAN OF DISTRIBUTION Swartz and its successors, which term includes its transferees, pledgees or donees or their successors, may sell the common stock directly to one or more purchasers (including pledgees) or through brokers, dealers or underwriters who may act solely as agents or may acquire common stock as principals, at market prices prevailing at the time of sale, at prices related to such prevailing market prices, at negotiated prices or at fixed prices, which may be changed. Swartz may effect the distribution of the common stock in one or more of the following methods: - ordinary brokers transactions, which may include long or short sales; - transactions involving cross or block trades or otherwise on the open market; - purchases by brokers, dealers or underwriters as principal and resale by such purchasers for their own accounts under this prospectus; - "at the market" to or through market makers or into an existing market for the common stock; - in other ways not involving market makers or established trading markets, including direct sales to purchasers or sales effected through agents; 70 - 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 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. 71 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 10,849,600 shares were issued and outstanding as of March 31, 2001. Holders of common stock are entitled to cast one vote for each share held of record on all matters presented to shareholders. Shareholders do not have cumulative rights; hence, the holders of more than 50% of the outstanding common stock can elect all directors. Holders of common stock are entitled to receive such dividends as may be declared by the Board of Directors out of funds legally available therefor and, in the event of liquidation, to share pro rata in any distribution of our assets after payment of all liabilities. We do not anticipate that any dividends on common stock will be declared or paid in the foreseeable future. Holders of common stock do not have any rights of redemption or conversion or preemptive rights to subscribe to additional shares if issued by us. All of the outstanding shares of our common stock are fully paid and nonassessable. WARRANTS Under our Investment Agreement, Swartz is the holder of warrants to purchase our common stock (for a further discussion see "Selling Security Holders"). Swartz currently has 500,000 warrants, (for a further discussion see "Selling Security Holders" and Exhibit 10.1 for "The Investment Agreement"). INTERESTS OF NAMED EXPERTS AND COUNSEL EXPERTS The Consolidated Financial Statements of Delta Petroleum Corporation as of June 30, 2000 and 1999, and for each of the years in the three year period ended June 30, 2000, and the Statements of Oil and Gas Revenue and Direct Lease Operating Expenses of the New Mexico Properties for each of the years in the two year period ended June 30, 1999, the Point Arguello Properties for the year ended June 30, 1999 and the nine month period ended June 30, 1998, and the North Dakota Properties for each of the years in the two year period ended June 30, 2000, included in this Registration Statement have been included herein in reliance upon reports by KPMG LLP, independent certified public accountants, appearing elsewhere herein and upon the authority of such firm as experts in accounting and auditing. 72 LEGAL MATTERS The validity of the issuance of the common stock offered by this prospectus will be passed upon for us by Krys Boyle Freedman & Sawyer, P.C., Denver, Colorado. No person is authorized to give any information or to make any representations other than those contained or incorporated by reference in this prospectus and, if given or made, such information or representations must not be relied upon as having been authorized. This prospectus does not 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. 73 FINANCIAL STATEMENTS Financial Statements are included on Pages F-1 through F-53. The Table of Contents to the Financial Statements is as follows: Report of Independent Certified Public Accountants KPMG LLP F-1 Consolidated Balance Sheets as of March 31, 2001, June 30, 2000 and 1999 F-2 to F-3 Consolidated Statements of Operations for the Nine Months Ended March 31, 2001 and 2000 and the Years Ended June 30, 2000, 1999 and 1998 F-4 Consolidated Statements of Changes in Stockholders' Equity and Comprehensive Income (Loss) for the Nine Months Ended March 31, 2001, and the Years ended June 30, 2000, 1999 and 1998 F-5 to F-6 Consolidated Statements of Cash Flows for the Nine Months Ended March 31, 2001 and 2000 and the Years Ended June 30, 2000, 1999 and 1998 F-7 Summary of Accounting Policies and Notes to Consolidated Financial Statements F-8 to F-37 Report of Independent Certified Public Accountants KPMG LLP F-38 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-39 Notes to New Mexico Properties Statements of Oil and Gas Revenue and Direct Lease Operating Expenses F-40 to F-42 Report of Independent Certified Public Accountants KPMG LLP F-43 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-44 Notes to Point Arguello Properties Statements of Oil and Gas Revenue and Direct Lease Operating Expenses F-45 to F-48 Report of Independent Certified Public Accountants KPMG LLP F-49 75 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-50 Notes to North Dakota Properties Statements of Oil and Gas Revenue and Direct Lease Operating Expenses F-51 to F-53 Condensed Proforma Combined Financial Statements of Delta Petroleum Corporation for the Nine Months Ended March 31, 2001 and for the Year Ended June 30, 2000 F-54 to F-60 76 Independent Auditors' Report The Board of Directors Delta Petroleum Corporation: We have audited the accompanying consolidated balance sheets of Delta Petroleum Corporation (the Company) and subsidiary as of June 30, 2000 and 1999 and the related consolidated statements of operations, stockholders' equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the 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 Delta Petroleum Corporation and subsidiary as of June 30, 2000 and 1999 and the results of their operations and their cash flows for each of the years in the three-year period ended June 30, 2000, in conformity with generally accepted accounting principles. s/KPMG LLP KPMG LLP Denver, Colorado August 11, 2000 F-1 DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS

March 31, June 30, June 30, 2001 2000 1999 ------------- --------- ---------- Unaudited ASSETS Current Assets: Cash $ 413,916 302,414 99,545 Trade accounts receivable, net of allowance for doubtful accounts of $50,000 at March 31, 2001 June 30, 2000 and 1999 1,560,794 613,527 113,841 Accounts receivable - related parties 183,442 142,582 116,855 Prepaid assets 768,072 373,334 10,000 Other current assets 228,222 198,427 100 ------------ ---------- ---------- Total current assets 3,154,446 1,630,284 340,341 ------------ ---------- ---------- Property and Equipment: Oil and gas properties, at cost (using the successful efforts method of accounting): Undeveloped offshore California properties 10,590,810 10,809,310 7,369,830 Undeveloped onshore domestic properties 1,778,529 451,795 506,363 Undeveloped foreign properties 623,920 623,920 623,920 Developed offshore California properties 4,256,939 3,285,867 - Developed offshore Louisiana properties 2,899,771 - - Developed onshore domestic properties 11,856,984 5,154,295 2,231,187 Office furniture and equipment 92,996 89,019 82,489 ------------ ---------- ---------- 32,099,949 20,414,206 10,813,789 Less accumulated depreciation and depletion (4,093,552) (2,538,030) (1,650,228) ------------ ---------- ---------- Net property and equipment 28,006,397 17,876,176 9,163,561 ------------ ---------- ---------- Long term assets: Deferred financing costs 280,626 366,996 - Investment in Bion Environmental 108,046 228,629 257,180 Partnership net assets 549,787 675,185 - Deposit on purchase of oil and gas properties - 280,002 1,616,050 ------------ ---------- ---------- Total long term assets 938,459 1,550,812 1,873,230 $ 32,099,302 21,057,272 11,377,132 ============ ========== ==========

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

March 31, June 30, June 30, 2001 2000 1999 ------------ --------- ---------- Unaudited LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Current portion of long-term debt: Related party $ - - 105,268 Other 3,941,026 1,765,653 - Accounts payable 1,516,708 1,636,651 393,542 Other accrued liabilities 94,741 154,388 10,000 Deferred revenue 14,683 58,733 127,166 ----------- ---------- ---------- Total current liabilities 5,567,158 3,615,425 635,976 ----------- ---------- ---------- Long-term debt: Related party - - 894,732 Other 8,497,809 6,479,115 - ----------- ---------- ---------- 8,497,809 6,479,115 894,732 ----------- ---------- ---------- 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 10,849,600 shares at March 31, 2001, 8,422,079 at June 30, 2000 and 7,913,379 at June 30, 1999 108,496 84,221 63,903 Additional paid-in capital 40,021,319 33,746,861 29,476,275 Accumulated other comprehensive loss (43,524) 77,059 (115,395) Accumulated deficit (22,051,956) (22,945,409) (19,578,359) ----------- ---------- ---------- Total stockholders' equity 18,034,335 10,962,732 9,846,424 ----------- ---------- ---------- Commitments $32,099,302 21,057,272 11,377,132 =========== ========== ==========

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

Nine Months Ended Year Ended ---------------------------- ------------------------------------- Unaudited March 31, March 31, June 30, June 30, June 30, 2000 1999 2000 1999 1998 ------------- ------------- --------- ---------- ---------- Revenue: Oil and gas sales $9,351,912 1,852,135 3,355,783 557,507 1,225,115 Gain on sale of oil and gas properties - - 75,000 957,147 650,417 Operating fee income 79,634 48,933 76,308 43,117 204,648 Other revenue 44,050 55,037 68,433 137,154 83,435 ---------- ----------- ---------- ---------- ---------- Total revenue 9,475,596 1,956,105 3,575,524 1,694,925 2,163,615 Operating expenses: Lease operating expenses 3,782,468 1,363,850 2,405,469 209,438 349,551 Depreciation and depletion 1,555,522 394,971 887,802 229,292 303,563 Exploration expenses 48,859 37,495 46,730 74,670 515,383 Abandoned and impaired properties - - - 273,041 128,993 Dry hole costs 90,391 - - 226,084 46,605 Professional fees 815,177 343,524 519,267 372,314 406,775 General and administrative 895,795 973,891 1,258,312 1,134,369 1,026,686 Stock option expense 334,383 293,860 537,708 2,080,923 46,402 Royalty to related party - - - - 350,000 ---------- ----------- ---------- ---------- ---------- Total operating expenses 7,522,595 3,407,591 5,655,288 4,600,131 3,173,958 ---------- ----------- ---------- ---------- ---------- Income (loss) from operations 1,953,001 (1,451,486) (2,079,764) (2,905,206) (1,010,343) Other income and expenses: Other income 435,317 17,251 90,457 22,730 - Interest and financing costs (1,494,865) (941,360) (1,264,954) (19,726) - Gain (loss) on sale of securities available for sale - (112,789) (112,789) (96,553) 48,340 ---------- ----------- ---------- ---------- ---------- Total other income and expenses (1,059,548) (1,036,898) (1,287,286) (93,549) 48,340 ---------- ----------- ---------- ---------- ---------- Net income (loss) $ 893,453 (2,488,384) (3,367,050) (2,998,755) (962,003) ========== =========== ========== ========== ========== Net income (loss) per common share: Basic $ 0.09 (0.35) (0.46) (0.51) (0.18) ========== =========== ========== ========== ========== Diluted $ 0.08 (0.35) * * * ========== =========== ========== ========== ========== * Potentially dilutive securities outstanding were anti-dulutive

See accompanying notes to consolidated financial statements. F-4 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Consolidated Statement of Stockholders' Equity Years ended June 30, 2000, 1999, 1998 and nine months ended March 31, 2001

Accumulated other Additional comprehensive Common Stock paid-in income Comprehensive Accumulated Shares Amount capital (loss) income (loss) deficit Total -------------------------------------------------------------------------------------------------------------------------------- Balance, July 1, 1997 5,230,631 $52,306 24,950,128 (213,969) (15,617,597) 9,170,868 Comprehensive loss: Net loss - - - (962,003) (962,003) (962,003) ----------- Other comprehensive loss, net of tax Unrealized loss on equity securities - - - 719,903 Less: Reclassification adjustment for losses included in net loss (48,340) 671,563 671,563 ----------- Comprehensive loss - - - (290,440) =========== Stock options granted as compensation - - 46,402 - - 46,402 Shares issued for cash 156,950 1,570 348,430 - - 350,000 Shares issued for cash upon exercise of options 114,100 1,141 202,395 - - 203,536 Shares issued for services 22,500 225 64,463 - - 64,688 Shares reacquired and retired (10,323) (103) (39,897) - - (40,000) ---------- -------- ----------- --------- ------------ ----------- Balance, June 30, 1998 5,513,858 55,139 25,571,921 457,594 (16,579,600) 9,505,054 Comprehensive loss: Net loss - - - (2,998,759) (2,998,759) (2,998,759) ----------- Other comprehensive loss, net of tax Unrealized loss on equity securities - - - (669,542) Less: Reclassification adjustment for losses included in net loss 96,553 (572,989) (572,989) ----------- Comprehensive loss - - - (3,571,748) =========== Stock options granted as compensation - - 2,081,423 2,081,423 Shares issued for cash 196,444 1,964 354,011 - - 355,975 Shares issued for cash upon exercise of options 120,000 1,200 158,800 - - 160,000 Shares issued for services 10,000 100 15,650 - - 15,750 Shares issued for oil and gas properties 250,000 2,500 621,420 - - 623,920 Shares issued for deposit on oil and gas properties 300,000 3,000 613,050 - - 616,050 Fair value of warrant extended and repriced - - 60,000 - - 60,000 ----------- -------- ----------- --------- ------------ ----------- Balance, June 30, 1999 6,390,302 63,903 29,476,275 (115,395) (19,578,359) 9,846,424 Comprehensive loss: Net loss - - - (3,367,050) (3,367,050) (3,367,050) ----------- Other comprehensive loss, net of tax Unrealized loss on equity securities - - - 79,665 - Less: Reclassification adjustment for losses included in net loss - - - 112,789 192,454 192,454 ----------- Comprehensive loss - - - (3,174,596) =========== Stock options granted as compensation - - 500,208 - - 500,208 Shares issued for cash 603,000 6,030 1,017,970 - - 1,024,000 Shares issued for cash upon exercise of options 1,048,777 10,488 1,367,048 - - 1,377,536 Shares and options issued with financing 75,000 750 565,472 - - 566,422 Shares issued for oil and gas properties 215,000 2,150 547,413 - - 549,563 Shares issued for deposit on oil and gas properties 90,000 900 272,475 - - 273,375 ----------- -------- ----------- --------- ------------ ----------- Balance, June 30, 2000 8,422,079 84,221 33,746,861 77,059 (22,945,409) 10,962,732 F-5 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Consolidated Statement of Stockholders' Equity Years ended June 30, 2000, 1999, 1998 and nine months ended March 31, 2001 (Continued) Comprehensive loss: Net income - - - 893,453 893,453 893,453 ----------- Other comprehensive gain, net of tax Unrealized gain on equity securities - - - (120,583) (120,583) (120,583) ----------- Comprehensive loss - - - 772,870 =========== Stock options granted as compensation - - 445,144 - - 445,144 Fair value of warrants issued for common stock investment agreement - - 1,435,797 - - 1,435,797 Warrant issued in exchange for common stock investment agreement - - (1,435,797) - - (1,435,797) Shares issued for cash, net 1,003,749 10,037 2,412,201 - - 2,422,238 Shares issued for cash upon exercise of options 641,795 6,418 987,756 - - 994,174 Conversion of note payable and accrued interest to common stock 200,000 2,000 508,959 - - 510,959 Shares issued for oil and gas properties, net 820,988 8,210 2,823,858 - - 2,832,068 Shares reacquired and retired (239,011) (2,390) (903,460) - - (905,850) ----------- -------- ----------- --------- ------------ ----------- Balance, March 31, 2001 10,849,600 108,496 40,021,319 (43,524) (22,051,956) 18,034,335 ========== ======== =========== ========= ============ ===========

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

Nine Months Ended Years Ended ---------------------------- ----------------------------------- Unaudited March 31, March 31, June 30, June 30, June 30 2001 2000 2000 1999 1998 ------------- ------------ ------------ ----------- ---------- Cash flows from operating activities: Net income (loss) $ 893,453 $(2,488,384) $(3,367,050) (2,998,759) $ (962,003) Adjustments to reconcile net income (loss) to cash used in operating activities: Gain on sale of oil and gas properties - - (75,000) (957,147) (650,417) Loss on sale of securities available for sale - 112,789 112,789 96,553 (48,340) Depreciation and depletion 1,555,522 394,971 887,802 229,292 303,563 Stock option expense 445,144 293,860 500,208 2,080,923 46,402 Amortization of financing costs 369,714 383,112 466,568 - - Abandoned and impaired properties - - - 273,041 128,993 Common stock issued for services - - - 15,750 64,688 Bad debt expense - - - - 29,754 Net changes in operating assets and operating liabilities: (Increase) decrease in trade accounts receivable (940,609) (827,283) (533,074) 84,432 36,566 (Increase) decrease in prepaid assets (394,738) - (373,334) - - (Increase) decrease in other current assets 60,960 (1,873) (62,500) - - (Increase) decrease in accounts payable trade (119,943) 1,058,994 1,243,109 (176,927) (206,233) (Increase) decrease in other accrued liabilities (292,787) 31,961 144,388 - (11,835) Deferred Revenue (44,050) (53,093) (68,433) (137,154) (204,648) ----------- ----------- ----------- ---------- ----------- Net cash provided by (used in) operating activities 1,532,666 (1,095,846) (1,124,527) (1,489,996) (1,473,510) Cash flows from investing activities: Additions to property and equipment (9,542,332) (7,320,300) (7,759,804) (507,068) (628,387) Deposit on purchase of oil and gas properties - - (6,627) (1,000,000) - Proceeds from sale of securities available for sale - 135,441 135,441 174,602 (197,012) Proceeds from sale of oil and gas properties - - 75,000 1,384,000 1,023,432 Decrease (increase) in long term assets 125,398 (476,049) (675,185) - - ----------- ----------- ----------- ---------- ----------- Net cash provided by (used in) investing activities (9,416,934) (7,660,908) (8,231,175) 51,534 592,057 ----------- ----------- ----------- ---------- ----------- Cash flows from financing activities: Stock issued for cash upon exercise of options 994,174 595,346 1,377,536 160,000 163,536 Issuance of common stock for cash 2,422,238 1,024,000 1,024,000 356,475 350,000 Proceeds from borrowings 13,519,255 13,142,427 12,816,851 400,000 - Proceeds from borrowings from related parties - - - 1,000,000 - Repayment of borrowings (8,825,188) (4,644,928) (4,640,252) (400,000) - Repayment of borrowings to related parties - (1,000,000) (1,000,000) - - Decrease (increase) in accounts receivable from related parties (114,709) (40,187) (19,564) 4,397 (7,996) ----------- ----------- ----------- ---------- ----------- Net cash provided by financing activities 7,995,770 9,076,658 9,558,571 1,520,872 505,540 ----------- ----------- ----------- ---------- ----------- Net increase in cash 111,502 319,904 202,869 82,410 (375,913) ----------- ----------- ----------- ---------- ----------- Cash at beginning of period 302,414 99,545 99,545 17,135 (393,048) ----------- ----------- ----------- ---------- ----------- Cash at end of period $ 413,916 $ 419,449 $ 302,414 $ 99,545 $ 17,135 =========== =========== =========== ========== =========== Supplemental cash flow information - Cash paid for interest and financing costs $ 1,398,491 $ 459,207 $ 741,348 $ 19,726 $ - =========== =========== =========== ========== =========== Non-cash financing activities: Common stock issued for the purchase of oil and gas properties $ 2,832,068 $ 549,563 $ 549,563 $ - $ - =========== =========== =========== ========== =========== Common stock issued for deposit on purchase of oil and gas properties $ - $ - $ 273,375 $ 616,050 $ - =========== =========== =========== ========== =========== Common stock issued for note payable and accrued interest $ 510,959 $ - $ - $ - $ - =========== =========== =========== ========== =========== Common stock, options and overriding royalties issued relating to debt financing $ 130,000 $ - $ 891,223 $ - $ - =========== =========== =========== ========== =========== Shares reacquired and retired for oil and gas properties and option exercise $ 905,850 $ - $ - $ - $ - =========== =========== =========== ========== ===========

See accompanying notes to consolidated financial statements. F-7 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) (1) Summary of Significant Accounting Policies Organization and Principles of Consolidation Delta Petroleum Corporation ("Delta") was organized December 21, 1984 and is principally engaged in acquiring, exploring, developing and producing oil and gas properties. The Company owns interests in developed and undeveloped oil and gas properties in federal units offshore California, near Santa Barbara, and developed and undeveloped oil and gas properties in the continental United States. In addition, the Company has a license to explore undeveloped properties in Kazakhstan. At March 31, 2001, the Company owned 4,277,977 shares of the common stock of Amber Resources Company ("Amber"), representing 91.68% of the outstanding common stock of Amber. Amber is a public company also engaged in acquiring, exploring, developing and producing oil and gas properties. The consolidated financial statements include the accounts of Delta and Amber (collectively, the Company). All intercompany balances and transactions have been eliminated in consolidation. As Amber is in a net shareholders' deficit position for the periods presented, the Company has recognized 100% of Amber's earnings/losses for all periods. Liquidity The Company has incurred losses from operations over the past several years, prior to fiscal 2001, coupled with significant deficiencies in cash flow from operations for the same periods. As of March 31, 2001, the Company had a working capital deficit of $2,412,712. These factors among others may indicate the Company may not be able to meet its obligations in a timely manner. One aspect of the Company's business activities has been the buying and selling of oil and gas properties. In the past the Company has sold properties to fund its working capital deficits and/or its funding needs. In addition, during fiscal 2000 and 1999, the Company has raised $2,401,536 and $515,975, respectively, through private placements and option exercises. Recently, the Company has taken steps to reduce losses and generate cash flow from operations, through the pending acquisition of producing oil and gas properties (see Note 3) 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 a timely or acceptable terms. F-8 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) 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 ($11,844,221 at December 31, 2000) 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 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" (SFAS 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. 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 F-9 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) 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 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, we recorded an impairment provision attributable to certain producing properties of $103,230 and $128,993 for the years ended June 30, 1999 and 1998, respectively. 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 cost 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 onshore properties of $169,811 for the year ended June 30, 1999. 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 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, 2001, the Company had produced and recognized as revenue approximately $13,000 Mcf more than its share of production. The undiscounted value of this imbalance is approximately $50,000 using the lower of the price received for the natural gas, the current market price or the contract price, as applicable. 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. F-10 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) The statute of limitation has expired for these deferred amounts and accordingly $44,050 and $53,037 for the nine months ended March 31, 2001 and 2000, respectively, and $68,433, $137,154 and $204,648 for the years ended June 30, 2000, 1999 and 1998, respectively, have been written off and recorded as a component of other revenue. 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 109 (SFAS 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 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. 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 warrant. The effect of potentially dilutive securities outstanding were antidilutive during the quarter ended March 31, 2000 and during the years ended June 30, 2000, 1999 and 1998. F-11 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) 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 March 2000, the Financial Accounting Standards Board ("FASB") issued FASB Interpretation No. 44 "Accounting for Certain Transactions involving Stock Compensation" and interpretation of APB Opinion No. 25 ("FIN 44"). This opinion provides guidance on the accounting for certain stock option transactions and subsequent amendments to stock option transactions. FIN 44 is effective July 1, 2000, but certain conclusions cover specific events that occur after either December 15, 1998 or January 12, 2000. To the extent that FIN 44 covers events occurring during the period from December 15, 1998 and January 12, 2000, but before July 1, 2000, the effects of applying this interpretation are to be recognized on a prospective basis. Repriced options mentioned above may impact future periods. The adoption of FIN 44 had no impact on our financial position or results of operations. In December 1999, the SEC released Staff Accounting Bulletin ("SAB") No. 101, "Revenue Recognition in Financial Statements", which provides guidance on the recognition, presentation and disclosure of revenue in financial statements filed with the SEC. Subsequently, the SEC released SAB 101B, which delayed the implementations date of SAB 101 for registrants with fiscal years beginning between December 16, 1999 and March 15, 2000. The adoption of SAB 101 had no impact on our financial position or results of operations. Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133), was issued in June 1998, by the Financial Accounting Standards Board. SFAS 133 establishes new accounting and reporting standards for derivative instruments and for hedging activities. This statement required an entity to establish at the inception of a hedge the method it will use for assessing the effectiveness of the hedging derivative and the measurement approach for determining the ineffective aspect of the hedge. Those methods must be consistent with the entity's approach to managing risk. SFAS 133 was amended by SFAS 137 and is effective for all fiscal quarters of fiscal years beginning after June 15, 2000. The adoption of SFAS 133 had no impact on our financial statements or results of operations. F-12 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) Reclassification Certain amounts in the 1998 and 1999 financial statements have been reclassified to conform to the 2000 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 and 1999, the Company received an additional 16,808 and 10,249 shares, respectively, of Bion's common stock for rent and other services provided by the Company. The Company realized losses of $2,551 for the nine months ended March 31, 2000 and $112,789, $96,553 and $48,340 for the years ended June 30, 2000, 1999 and 1998, respectively, on the sales of securities available for sale. The cost and estimated market value of the Company's investment in Bion at March 31, 2001, June 30, 2000 and 1999 are as follows: Estimated Unrealized Market Cost Gain/(Loss) Value -------- ----------- ---------- March 31, 2001 $151,570 $ (43,524) $ 108,046 June 30, 2000 $151,570 $ 77,059 $ 228,629 June 30, 1999 $372,575 $(115,395) $ 257,180 As of December 5, 2000, the estimated market value of the Company's investment in Bion, based on the quoted bid price of Bion's common stock, was approximately $138,000. (3) Oil and Gas Properties On October 12, 1998 we issued 250,000 shares and 500,000 warrants to purchase common stock at prices ranging from $3.50 per share to $5.00 per share to the Ambir Properties, Inc., shareholders in exchange for 100% of Ambir Properties, Inc. the only assets of which consisted of two licenses for exploration of approximately 1.9 million acres in the Pavlodar region of Eastern Kazakhstan. We accounted for the acquisition under the purchase method of accounting. and recorded $623,920 as undeveloped oil and gas properties. On November 1, 1999, the Company acquired interests in 10 operated wells in New Mexico and 1 non-operated well in Texas for a cost of $2,879,850. F-13 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) 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 undeveloped Rocky Point Unit from Whiting Petroleum Corporation ("Whiting"), a shareholder. Whiting will retain its proportionate share of future abandonment liability associated with both the onshore and offshore facilities of the Point Arguello Unit. If the Point Arguello property development and operating expenses are not covered by revenues then, at Delta's election, until December 31, 2000, Whiting will invest up to $2,000,000 in an amount equal to the aggregate amount of lease operating expenses and capital costs over production revenue, if any, net to our interest, for the eight months ended December 31, 1999 and twelve months ended December 31, 2000 at $1,000,000 per period specified through the purchase of our preferred stock to cover such costs. The preferred convertible stock has a 5% interest rate payable in cash on the Company's common stock and is convertible based on the lower of the average closing price of our stock during the months of March 1999, March 2000 or March 2001. As of September 30, 2000, Delta has not elected to issue any convertible preferred stock. The acquisition had a purchase price of approximately $6,758,550 consisting of $5,625,000 in cash and 500,000 shares (which include the 300,000 shares issued during fiscal 1999) of the Company's restricted common stock with a fair market value of $1,133,550. 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 have not 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 $2,033,153 for the year ended June 30, 2000. If the Company would have not committed to sell its proportionate share of its barrels at $14.65 per barrel, the Company would have realized an increase in income of $1,285,337 for the nine months ended March 31, 2001, The Company assigned an unaffiliated third party a 3% overriding royalty interest in the Point Arguello properties as consideration for arranging the transaction. On July 10, 2000 and on September 28, 2000, the Company paid $3,745,000 and $1,845,000, respectively, to acquire interests in 20 producing wells, 5 injection wells and acreage located in the Eland and Stadium fields in Stark County, North Dakota ("North Dakota"). The July 10, 2000 and September 28, 2000 payments resulted in the acquisition by the Company of 67% and 33%, respectively, of the ownership interest in each property acquired. The $3,745,000 payment on July 10, 2000 was financed through borrowings from an unrelated entity and personally guaranteed by two of the Company's officers, while the payment on September 28, 2000 was primarily paid out of the Company's net revenues from the effective date of the acquisitions through closing. Delta also issued 100,000 shares of its restricted common stock, valued at $450,000, to an unaffiliated party for its consultation and assistance related to the F-14 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) transaction and recorded in oil and gas properties. 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 September 29, 2000 the Company acquired the West Delta Block 52 Unit ("West Delta") from two unrelated entities by paying $1,529,157 and issuing 509,719 shares of its restricted common stock valued at $3.38 per share. The Company permitted three officers to purchase an aggregate 12.5% working interest acquired by the Company in the West Delta by delivering to the Company shares of the Company's common stock valued at $3.38 per share equal to 12.5% of the purchase price paid by the Company. The officers delivered 156,333 shares of common stock valued at $482,125 for actual costs incurred and the exercise of options. These shares have been retired. The Company borrowed $1,463,532 of the cash portion of the purchase price from an unrelated entity. Two of the Company's officers agreed to personally guarantee the loan. On 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 $461,734. 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 part of the acquisition, Saga was required to return 393,006 shares of the Company's common stock at closing valued at $1,847,645, which had been previously issued as a deposit for the acquisition of additional 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 $423,725 for actual costs incurred and the exercise of options. The following unaudited pro forma consolidated statements of operations information assumes that the acquisition of North Dakota discussed above occurred as of July 1, 1999: F-15 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) Pro Forma Nine Months Ended March 31, 2001 ------------------------------------------ 2001 2000 ---- ---- Operating revenue- Oil and gas sales $ 9,643,705 $ 4,144,748 =========== =========== Net income (loss) $ 1,164,653 $ (363,848) =========== =========== Net income (loss) per common share: Basic $.12 $(.05) ==== ===== Diluted $.10 $(.05) ==== ===== The following unaudited proforma consolidated statement of operations information assumes that the November 1, 1999 and December 1, 1999 acquisitions occurred as of July 1, 1998: Years Ended June 30, ----------- 2000 1999 ---- ---- Oil and gas sales $ 5,179,526 $ 4,414,289 =========== =========== Net loss $(3,685,786) $(5,109,588) =========== =========== Net loss per common share- basic and diluted $(.51) $(.84) =========== =========== During the years ended June 30, 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 $75,000 and $1,384,000 and resulted in a gain on sale of oil and gas properties of $75,000 and $957,147 for the years ended June 30, 2000 and 1999, respectively. F-16 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) (4) Long Term Debt March 31, June 30, 2001 2000 1999 ---------- ---------- ---------- A $6,750,568 $7,504,306 $ -- B 5,065,497 -- -- C 662,770 -- - D -- 740,462 -- E -- -- 1,000,000 ----------- ---------- ---------- $12,478,835 $8,244,768 $1,000,000 Current Portion 3,941,026 1,765,653 105,268 ----------- ---------- ---------- Long-Term Portion $ 8,497,809 $6,479,115 $ 894,732 =========== ========== ========== A. On December 1, 1999, the Company borrowed $8,000,000 at prime plus 1-1/2% from Kaiser-Francis Oil Company ("Lender"). As additional consideration for entering into the loan, the Company issued warrants to purchase 250,000 shares of our common stock for two years at $2.00 per share. The 250,000 warrants were valued at $260,000 and recorded as a deferred cost to be amortized over the life of the loan. The loan agreement provides for a 4-1/2 year loan with additional cost in the form of oil and gas overriding royalty interests of two and one-half percent (2.5%) on September 1, 2000 and an additional 2.5% on June 1, 2001, proportionately reduced, on all of the oil and gas properties acquired by Delta pursuant to the offshore agreement. In addition, the Company will be required to pay fees of $250,000 on June 1, 2002 and June 1, 2003 if the loan has not been retired prior to these dates. The proceeds from this loan were used to pay off existing debt and the balance of the Point Arguello Unit and East Carlsbad field purchases. The Company is required to make minimum monthly payments of principal and interest equal to the greater of $150,000 or 75% of net cash flows from the acquisitions completed on November 1, 1999 and December 1, 1999. The lender was assigned a 2.5% overriding royalty on September 1, 2000, proportionately reduced to the Company's working interest ownership, on the offshore properties purchased as required by the loan agreement and valued at $130,000 which was recorded as deferred financing cost and amortized. As of March 31, 2001, no warrants have been exercised. The loan is collateralized by the Company's oil and gas properties acquired with the loan proceeds. B. On October 25, 2000, the Company borrowed $3,000,000 at prime plus 3%, secured by the acquired interests in the Eland and Stadium fields in Stark County, North Dakota, from US Bank National Association (US Bank). On February 28, 2001, the Company increased its existing loan with US Bank to $5,300,000. The loan matures on August 31, 2003 and is collateralized by certain oil and gas properties. The Company is required to make monthly payments in the amount of 90% of the net revenue from the oil and gas properties collateralizing the loan. The Company has a contract to sell 6,000 barrels of oil per month at $27.31 per barrel through February 28, 2002. F-17 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) C. 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 is collateralized by the Company's oil and gas properties acquired with the loan proceeds and subsequent to the quarter ended March 31, 2001, the balance has been paid in full. 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. 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. During the quarter ended September 30, 2000, the Company paid off the loan and expensed the unamortized costs. E. On May 24, 1999, the Company borrowed $1,000,000 at 18% per annum from the Company's officers, related party, maturing on June 1, 2001 upon the same terms under which they borrowed these funds from an unrelated lender. The Company agreed to make monthly payments of interest only for the first six months and then monthly principal and interest payments of 429,375 through June 1, 2001 with the remaining principal amount payable at the maturity date. The loan was paid in full during fiscal 1999. On September 29, 2000, the Company borrowed $1,463,532 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 has been paid in full. 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 $10,959 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. 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 o each overriding royalty interest of $37,500 was recorded as a deferred financing cost. Each officer earned $10,000 for their 1% overriding royalty interest during fiscal 2000. F-18 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) (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 March 31, 2000, June 30, 2000 and 1999, 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 $6,475 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 $216,670 based on the estimated fair value of the options issued and recorded $623,920 as undeveloped oil and gas properties. On December 1, 1998, the Company issued 10,000 shares of its common stock valued at $15,750, 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, another oil and gas company, for net proceeds to us of $350,000. F-19 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) 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 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, 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 $95,481 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 $32,063, 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 9, 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 $128,250, 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. 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 $273,375, 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. F-20 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) During fiscal 2000, the Company issued 215,000 shares of its common stock, at a price of $2.56 per share and valued at $549,563, 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 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 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 $116,451, 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 $73,828, to CEC Inc. in exchange for an option to purchase certain properties owned by CEC Inc. and its partners. The common stock issued was recorded at a 10% discount to market, which was based on the quoted market price of the stock at the time the Company committed to the transaction and recorded in oil and gas properties. On September 7, 2000, the Company issued 103,423 shares of its restricted common stock, at a price of $4.95 per share and valued at $511,944, 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, the Company issued 487,844 shares of its restricted common stock, at a price of $3.38 per share and valued at $1,646,474, 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 the Company committed to the transaction and is recorded in oil and gas properties. F-21 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) On September 30, 2000, the Company issued 289,583 shares of its restricted common stock, at a price of $4.61 per share and valued at $1,335,702, to Saga Petroleum Corporation ("SAGA") 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. 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 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 and is recorded in oil and gas properties. 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. On January 3, 2001, the Company entered into an agreement with Evergreen Resources, Inc. ("Evergreen"), also a shareholder, whereby Evergreen acquired 116,667 shares of the Company's common stock and an option to acquire an interest in three undeveloped Offshore Santa Barbara, California properties until September 30, 2001. Upon exercise, Evergreen must transfer the 116,667 shares of the Company's common stock back to the Company and would be responsible for 100% of all future minimum payments underlying the properties in which the interest is acquired. On January 12, 2001, the Company issued 490,000 shares of its restricted common stock to an unrelated entity for $1,102,500. The Company paid a cash commission of $110,250 to an unrelated individual and issued options to purchase 100,000 shares of the Company's common stock at $3.25 per share to an unrelated company for their efforts in connection with the sale. The options were valued at approximately $200,000. Both the commission and the value of the options have been recorded as an adjustment to equity. On July 21, 2000, the Company entered into an investment agreement with Swartz Private Equity, LLC ("Swartz") and issued Swartz a warrant to purchase 500,000 shares of common stock exercisable at $3.00 per share until May 31, 2005. A warrant to purchase 150,000 shares of the Company's common stock at $3.00 per share for five years was also issued to another unrelated company. In the aggregate, the Company issued options to Swartz and the other unrelated company valued at $1,435,797 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. F-22 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) 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 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 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. 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 F-23 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) basis. Incentive awards under the Incentive Plan may include non-qualified or incentive stock options, limited appreciation rights, tandem stock appreciation rights, phantom stock, stock bonuses or cash bonuses. Options issued to date have been non- qualified stock options as defined in the Incentive Plan. A summary of the Plan's stock option activity and related information for the years ended June 30, 2000, 1999 and 1998 are as follows:

2000 1999 1998 Weighted-Average Weighted-Average Weighted-Average Exercise Exercise Exercise Options Price Options Price Options Price --------- -------- ----------- ---------- ----------- --------- Outstanding-beginning of year 1,640,163 $ 1.05 1,162,977 $ 2.25 1,262,077 $ 3.25 Granted 387,500 1.60 477,186 1.43 15,000 1.88 Exercised (391,777) (.29) - - (114,100) (1.78) Repriced - - 2,110,954 .68 1,621,054 2.47 Returned for repricing - - (2,110,954 (1.47) (1,621,054) (3.27) Outstanding-end of year 1,635,886 $ 1.36 1,640,163 $ 1.05 1,162,977 2.25 Exercisable at end of year 1,510,886 $ .95 1,385,163 $ 2.32 1,132,977 2.27

The Company issued or repriced options to employees at or below market. Accordingly, the Company recorded stock option expense in the amount of $91,851, $1,984,615 and $23,846 to employees for the years ended June 30, 2000, 1999 and 1998, respectively. Exercise prices for options outstanding under the plan as of June 30, 2000 ranged from $0.05 to $9.75 per share. All options are fully vested at June 30, 2000. The weighted-average remaining contractual life of those options is 8.14 years. A summary of the outstanding and exercisable options at June 30, 2000, 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 -------- ----------- --------- ----------- ----------- --------- $0.05 769,736 $0.05 8.25 769,736 $0.05 $1.13-$3.25 701,150 1.78 8.64 701,150 1.78 $3.26-$9.75 165,000 5.72 5.50 40,000 3.58 1,635,886 $1.36 8.14 1,510,886 $0.95

F-24 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) 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, 2000, 1999 and 1998, 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 loss for the years ended June 30, 2000, 1999 and 1998 would have been as follows:

June 30, ------------------------------------- 2000 1999 1998 Net Loss $3,367,050 $2,998,755 $ 962,003 FAS 123 compensation effect 132,770 (756,248) 371,742 ---------- ---------- ---------- Net loss after FAS 123 compensation effect $3,499,820 $2,242,507 $1,333,745 ========== ========== ========== Loss per common share $ .45 $ .38 $ .25 ========== ========== ==========

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, 2000, 1999 and 1998 are as follows: F-25 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited)

2000 1999 1998 Weighted-Average Weighted-Average Weighted-Average Exercise Exercise Exercise Options Price Options Price Options Price --------- -------- -------- -------- -------- -------- Outstanding-beginning of year 1,194,500 $ 4.09 889,500 $ 5.36 639,500 $ 6.27 Granted 1,090,000 2.99 525,000 3.86 500,000 4.11 Exercised (657,000) (1.92) (120,000) (1.32) - - Repriced 350,000 1.93 250,000 2.35 - - Returned for repricing (350,000) (3.48) (250,000) (4.97) - - Expired (65,000) (2.00) (100,000) (8.50) (250,000) (5.20) Outstanding-end of year 1,562,500 3.33 1,194,500 4.09 889,500 5.36 Exercisable at end of year 1,112,500 2.67 182,000 2.28 227,000 2.48

The Company issued or repriced options to non-employees at or below market. Accordingly, the Company recorded stock option expense in the amount of $445,857, $96,308 and $22,556 to non-employees for the years ended June 30, 2000, 1999 and 1998, respectively. Exercise prices for options outstanding under the plan as of June 30, 2000 ranged from $2.00 to $6.13 per share. All options are fully vested at June 30, 2000. The weighted-average remaining contractual life of those options is 2.39 years. A summary of the outstanding and exercisable options at June 30, 2000, 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-$3.50 1,112,500 $2.67 2.51 1,112,500 $2.67 $3.51-$6.13 450,000 4.96 2.08 - - 1,562,500 $3.33 2.39 1,112,500 $2.67

F-26 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) (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. During the nine months ended March 31, 2001 and 2000,the Company contributed $13,295 and $11,250 and for the years ended June 30, 2000, 1999 and 1998 the Company contributed $17,565, $16,631 and $24,304, respectively under the Plan. (7) Income Taxes At June 30, 2000, 1999 and 1998, the Company's significant deferred tax assets and liabilities are summarized as follows: 2000 1999 1998 ---- ---- ---- Deferred tax assets: Net operating loss carryforwards $ 9,591,000 $ 8,163,000 $ 7,999,000 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 2,206,000 Gross deferred tax assets 10,165,000 9,240,000 10,224,000 Less valuation allowance (10,165,000) (9,240,000) $(10,224,000) Net deferred tax asset $ - $ - $ - No income tax benefit has been recorded for the years ended June 30, 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 an increase in the valuation allowance for such net deferred tax assets. F-27 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) At June 30, 2000, the Company had net operating loss carryforwards for regular and alternative minimum tax purposes of approximately $25,240,000 and $24,630,000. If not utilized, the tax net operating loss carryforwards will expire during the period from 2000 through 2020. If not utilized, approximately $1.4 million of net operating losses will expire over the next five years. Net operating loss carryforwards attributable to Amber prior to 1993 of approximately $2,342,000, 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. (8) Related Party Transactions Transactions with Officers On January 3, 2000, the Company's Compensation Committee authorized the officers of the Company to purchase 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 $237,668. Because the market price per share was below the Company's cost basis the Company recorded a loss on this transaction of $107,730. 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 $62,330 has been recorded based on the difference between the option price and the quoted market price on the date of grant. On May 20, 1999, the Company Incentive Plan Committee granted options to purchase 89,686 shares of the Company's common stock and repriced 980,477 options to purchase shares of the Company's common stock for the two officers of the Company at a price of $.05 per share under the Incentive Plan. Stock option expense of $1,960,704 has been recorded based on the difference between the option price and the quoted market price on the date of grant and repricing of the options. On January 6, 1999, the Company's Compensation Committee authorized two officers of the Company to purchase the Company's securities available for sale at the market closing price on that date not to exceed $105,000 per officer. The Company's Chief Executive Officer purchased 29,900 shares of the Company's securities available for sale for a cost of $89,668. Because the market price per share was below the Company's cost basis the Company recorded a loss on this transaction of $67,382. 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). F-28 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) 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 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. 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 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. 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 paid for the interests as required. Accounts Receivable Related Parties At March 31, 2001, the Company had $183,442 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 Incentive Plan, as amended, the Company grants on an annual basis, to each nonemployee director, at the nonemployee 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 $34,849 and $20,863 for the nine months ended March 31, 2001 and 2000 and of $29,521, $23,911 and $23,846 for the years ended June 30, 2000, 1999 and 1998, respectively. F-29 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) Transactions with Other Stockholders On December 17, 1998, the Company amended its Purchase and Sale Agreement to acquire 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, with Ogle dated 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 repriced 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 repricing 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, 2000, the Company has paid a total of $1,900,000 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 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"), also a shareholder, until September 30, 2001. Upon exercise, Evergreen must transfer 116,667 shares of Delta's common stock back to the Company and is responsible for all future cash payments of the Company to Ogle of $6,100,000. The value on our books of the interest subject to the option is $550,000. Evergreen has had this option for three consecutive years. To date, Evergreen has not exercised its option. 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-30 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) (9) Earnings Per Share The following table sets forth the computation of basic and diluted earnings per share:

Nine Months Ended Years Ended March 31, June 30, 2001 2000 2000 1999 1998 ------------ ------------ ------------ ----------- ----------- Numerator: Numerator for basic and diluted earnings per share - income available to common stockholders $ 893,453 $(2,488,384) $(3,367,050) $(2,998,759) $ (962,003) ----------- ----------- ----------- ----------- ---------- Denominator: Denominator for basic earnings per share-weighted average shares outstanding 10,049,344 7,011,750 7,271,336 5,854,758 5,361,900 Effect of dilutive securities- stock options and warrants 1,736,355 * * * * ----------- ----------- ----------- ----------- ---------- Denominator for diluted earnings per common shares 11,785,699 7,011,750 7,271,336 5,854,758 5,361,900 =========== =========== =========== =========== ========== Basic earnings per common share $ .09 (.35) (.46) (.51) (.18) =========== =========== =========== =========== ========== Diluted earnings per common share $ .08 (.35) (.46) (.51) (.18) =========== =========== =========== =========== ========== *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 nine months ended March 31, 2001 and 2000 was approximately $66,000 and $48,000 and for the years ended June 30, 2000 and 1999 was approximately $60,000 and $53,000, respectively. Future minimum payments under noncancelable operating leases are as follows: 2001 87,106 2002 94,840 2003 12,504 2004 8,336 As a condition of the October 25, 2000 loan (note 5), the Company entered into a contract with Enron North America Corp. to sell 6,000 barrels per month of the production from these properties at an equivalent well head price of approximately $27.31 per barrel through February 28, 2002. (11) Disclosures About Capitalized Costs, Cost Incurred and Major Customers F-31 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) Capitalized costs related to oil and gas producing activities are as follows:

March 31, June 30, June 30, June 30, 2001 2000 1999 1998 ------------ ----------- ----------- ---------- Undeveloped offshore California properties $10,590,810 10,809,310 7,369,830 6,959,830 Undeveloped onshore domestic properties 1,778,529 451,795 506,363 726,127 Undeveloped foreign properties 623,920 623,920 623,920 Developed Offshore California Properties 4,256,939 3,285,867 - - Developed offshore Louisiana properties 2,899,771 - - - Developed onshore domestic properties 11,856,984 5,154,295 2,231,187 3,369,881 ----------- ---------- ---------- ---------- 31,383,033 20,325,187 10,731,300 11,055,838 Accumulated depreciation and depletion (4,010,611) (2,457,480) (1,571,705) (1,311,719) ----------- ---------- ---------- ---------- 27,372,422 17,867,707 $9,159,595 9,744,119 =========== ========== ========== ==========

Cost incurred in oil and gas producing activities are as follows:

March 31, June 30, ------------------------------------------- --------------------------------------------------------------- 2001 2000 2000 1999 1998 Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore --------- --------- -------- ---------- -------- ---------- --------- --------- -------- -------- Unproved property acquisition costs $1,326,734 $ 291,500 $ - $1,739,480 $ - $3,439,480 $1,033,920 $ - $ 156,681 $ - Proved property acquisition costs 6,528,056 2,826,683 2,738,363 4,263,687 2,755,658 2,607,490 16,518 - 40,876 - Development costs 174,633 534,160 129,716 283,724 112,882 678,377 140,550 - 430,830 - Exploration costs 30,438 18,421 11,841 25,654 32,533 14,197 74,670 - 515,383 - $8,059,861 $3,670,764 $2,879,920 $6,312,545 $2,901,073 $6,739,544 $1,265,658 $ - $1,143,770 - Transferred amounts from undeveloped to developed properties $ - $ 510,000 $ 29,561 $ - $ 54,569 $ - $ 49,953 $ - $ - -

F-32 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) A summary of the results of operations for oil and gas producing activities, excluding general and administrative cost, is as follows:

March 31, June 30, ------------------------------------------- --------------------------------------------------------------- 2001 2000 2000 1999 1998 Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore Onshore Offshore ----------- ---------- --------- -------- ---------- ---------- --------- -------- ---------- -------- Revenue: Oil and gas revenues $4,882,570 $4,469,342 $ 825,431 $1,026,704 $ 1,198,334 $2,157,449 $ 557,503 $ - $1,225,115 $ - Expenses: Lease operating 601,169 3,181,299 258,203 1,105,647 345,744 2,059,725 209,438 - 349,551 - Depletion 946,773 598,219 245,247 135,300 324,849 560,926 229,292 - 303,563 - Exploration 30,438 18,421 11,841 15,654 32,533 14,197 74,670 - 515,383 - Abandonment and impaired properties - - - - - - 273,041 - 128,993 - Dry hole costs 90,391 - - - - - 226,084 - 46,605 - Minimum Royalty to related party - - - - - - - - 350,000 - Results of operations of oil and gas producing activities $3,213,799 $ 671,403 $ 310,140 $( 239,897) $ 495,208 $(477,399) $(455,022) $ - 468,980 -

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, 2000, 1999 and 1998 were: 2000 1999 1998 ---- ---- ---- A 71% -% -% B 13% -% -% C 7% 38% 4% D -% 17% 42% F-33 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) (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-34 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) 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, 2000, 1999 and 1998 are as follows:

Onshore Offshore GAS OIL GAS OIL (MCF) (BBLS) (MCF) (BBLS) --------- ---------- ------- -------- Balance at July 1, 1997 5,417,203 162,812 - - Extension and discoveries 3,995,565 - - - Revisions of quantity estimates 1,285,573 (2,364) - - Sales of properties (807,472) (1,375) - - Production (457,758) (11,632) - - Balance at July 1, 1998 9,433,111 147,441 - - Revisions of quantity estimates (3,751,139) 5,360 - - Sales of properties (1,600,440) (4,316) - - Production (254,291) (5,574) - - Balance at June 30, 1999 3,827,241 142,911 - - Revisions of quantity estimates 448,290 9,890 - - Purchase of properties 3,166,210 107,136 - 1,771,162 Production (362,051) (9,620) - (186,989) Balance at June 30, 2000 7,079,690 250,317 - 1,584,173 Proved developed reserves: June 30, 1998 3,905,228 22,273 - - June 30, 1999 2,289,024 13,140 - - June 30, 2000 5,672,425 119,849 - 908,379

F-35 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) 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, 1998 Future cash inflows $ 21,864,136 - 21,864,126 Future costs: Production 6,341,210 - 6,341,210 Development 3,058,005 - 3,058,005 Income taxes - - - Future net cash flows 12,464,921 - 12,464,921 10% discount factor 5,902,279 - 5,902,279 Standardized measure of discounted future net cash flows $ 6,562,642 - $6,562,642 June 30, 1999 Future cash inflows $ 10,147,136 - 10,147,136 Future costs: Production 3,353,561 - 3,353,561 Development 1,287,211 - 1,287,211 Income taxes - - - Future net cash flows 5,506,364 - 5,506,364 10% discount factor 2,154,142 - 2,154,142 Standardized measure of discounted future net cash flows $ 3,352,222 - $3,352,222 June 30, 2000 Future cash inflows $ 30,760,012 36,820,392 67,580,404 Future costs: Production 7,712,896 12,026,623 19,739,519 Development 1,584,211 3,308,693 4,892,904 Income taxes - - - Future net cash flows 21,462,905 21,485,076 42,947,981 10% discount factor 10,426,754 5,394,473 15,821,227 Standardized measure of discounted future net cash flows $ 11,036,151 $16,090,603 $27,126,754 Estimated future development cost anticipated for fiscal 2001 and 2002 $ 1,400,000 $ 3,300,000 $4,700,000

F-36 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements March 31, 2001, June 30, 2000, 1999 and 1998 (Information as of and for nine months ended March 31, 2001 and 2000 is unaudited) The principal sources of changes in the standardized measure of discounted net cash flows during the years ended June 30, 2000, 1999 and 1998 are as follows:

2000 1999 1998 ------------- ---------- ----------- Beginning of year $ 3,352,222 $6,562,642 $4,319,526 Sales of oil and gas produced during the period, net of production costs (950,314) (348,065) (875,564) Purchase of reserves in place 21,678,174 - - Net change in prices and production costs 2,079,837 (376,526) 134,318 Changes in estimated future development costs 218,148 891,498 628,160 Extensions, discoveries and improved recovery - - 2,661,463 Revisions of previous quantity estimates, estimated timing of development and other 335,465 (2,636,107) 374,627 Previously estimated development costs incurred during the period 78,000 78,000 - Sales of reserves in place - (1,475,484) (943,205) Accretion of discount 335,222 656,264 431,953 End of year $ 27,126,754 $3,352,222 $6,562,642

(13) Subsequent Event On April 13, 2001, the Company sold 100% of its working interest in the West Delta Block 52 Unit, located in Plaquemines Parish, Louisiana for $3,500,000. As a result of the sale, the Company expects to record a gain on the sale of approximately $500,000. F-37 INDEPENDENT AUDITORS' REPORT THE BOARD OF DIRECTORS WHITING PETROLEUM CORPORATION We have audited the accompanying statement of oil and gas revenue and direct lease operating expenses of oil and gas properties as described in Note 1 ("the New Mexico Properties") of Whiting Petroleum Corporation ("Whiting") acquired by Delta Petroleum Corporation for each of the years in the two-year period ended June 30, 1999. This financial statement is the responsibility of Whiting's management. Our responsibility is to express an opinion on this financial statement based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of oil and gas revenue and direct lease operating expenses is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of oil and gas revenue and direct lease operating expenses. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The accompanying statement of oil and gas revenue and direct lease operating expenses was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. Full historical financial statements, including general and administrative expenses and other indirect expenses, have not been presented as management of the New Mexico Properties cannot make a practicable determination of the portion of their general and administrative expenses or other indirect expenses which are attributable to the New Mexico Properties. In our opinion, the statement of oil and gas revenue and direct lease operating expenses referred to above presents fairly, in all material respects, the oil and gas revenue and direct lease operating expenses of the New Mexico Properties for each of the years in the two-year period ended June 30, 1999, in conformity with generally accepted accounting principles. /s/ KPMG LLP KPMG LLP Denver, Colorado December 29, 1999 F-38 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-39 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-40 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-41 1999 1998 ---- ---- Future oil and gas sales $9,911,271 8,635,254 Future production costs (4,176,027) (3,999,310) ---------- ---------- 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-42 INDEPENDENT AUDITORS' REPORT The Board of Directors Whiting Petroleum Corporation We have audited the accompanying statement of oil and gas revenue and direct lease operating expenses of oil and gas properties as described in Note 1 ("the Point Arguello Properties") of Whiting Petroleum Corporation ("Whiting") acquired by Delta Petroleum Corporation for the year ended June 30, 1999 and the nine month period ended June 30, 1998. This financial statement is the responsibility of Whiting's management. Our responsibility is to express an opinion on this financial statement based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of oil and gas revenue and direct lease operating expenses is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of oil and gas revenue and direct lease operating expenses. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The accompanying statement of oil and gas revenue and direct lease operating expenses was prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. Full historical financial statements, including general and administrative expenses and other indirect expenses, have not been presented as management of the Point Arguello Properties cannot make a practicable determination of the portion of their general and administrative expenses or other indirect expenses which are attributable to the Point Arguello Properties. In our opinion, the statement of oil and gas revenue and direct lease operating expenses referred to above presents fairly, in all material respects, the oil and gas revenue and direct lease operating expenses of the Point Arguello Properties for the year ended June 30, 1999 and the nine month period ended June 30, 1998, in conformity with generally accepted accounting principles. /s/ KPMG LLP KPMG LLP Denver, Colorado February 7, 2000 F-43 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-44 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-45 A) ESTIMATED PROVED OIL AND GAS RESERVES Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. 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-46 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 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-47 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-48 INDEPENDENT AUDITORS' REPORT THE BOARD OF DIRECTORS WHITING PETROLEUM CORPORATION We have audited the accompanying statements of oil and gas revenue and direct lease operating expenses of oil and gas properties as described in Note 1 ("the North Dakota Properties") of Whiting Petroleum Corporation ("Whiting") acquired by Delta Petroleum Corporation for each of the years in the two-year period ended June 30, 2000. These financial statement are the responsibility of Whiting's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the statement of oil and gas revenue and direct lease operating expenses is free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the statement of oil and gas revenue and direct lease operating expenses. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The accompanying statements of oil and gas revenue and direct lease operating expenses were prepared for the purpose of complying with the rules and regulations of the Securities and Exchange Commission. Full historical financial statements, including general and administrative expenses and other indirect expenses, have not been presented as management of the North Dakota Properties cannot make a practicable determination of the portion of their general and administrative expenses or other indirect expenses which are attributable to the North Dakota Properties. In our opinion, the statements of oil and gas revenue and direct lease operating expenses referred to above present fairly, in all material respects, the oil and gas revenue and direct lease operating expenses of the North Dakota Properties for each of the years in the two-year period ended June 30, 2000, in conformity with generally accepted accounting principles. /s/ KPMG LLP KPMG LLP Denver, Colorado November 28, 2000 F-49 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-50 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, 200 (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-51 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 ======== ======= 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. F-52 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-53 DELTA PETROLEUM CORPORATION CONDENSED PRO FORMA FINANCIAL STATEMENTS On November 1, 1999, Delta Petroleum Corporation ("Delta" or "the Company") purchased interests in 10 operated wells in Eddy County, New Mexico with an average working interest of 75%, associated acreage, and 1 non- operated well in Matagorda County, Texas with a working interest of 39.5% ("New Mexico Properties") for a purchase price of $2,879,850 financed through borrowings from an unrelated entity at an interest rate of 18% per annum. On December 1, 1999, Delta purchased a 6.07% 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 ("Point Arguello Properties") from a shareholder for a purchase price of approximately $6,758,550 consisting of $5,625,000 in cash and the issuance of 500,000 shares of the Company's common stock with a fair market value of $1,333,550. 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 per share. 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 20 producing and 5 injection wells located in the Eland and Stadium fields, Stark County, North Dakota ("North Dakota Properties"). The largest value is located in the Eland field where our working interest average is 3.25%. The July 10, 2000 and September 28, 2000 payments resulted in the acquisition by the Company of 67% and 33%, respectively, of the ownership interest in each property acquired. The $3,745,000 payment on July 10, 2000 was financed through borrowings from an unrelated entity and personally guaranteed by two of the Company's officers. 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 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 three above-mentioned acquisitions are referred to as "the Properties". The following unaudited condensed pro forma statement of operations for the nine months ended March 31, 2001 and year ended June 30, 2000 assumes the acquisition of the Properties occurred on July 1, 2000 and July 1, 1999, respectively. No general and administrative or other indirect costs related to the Properties have been reflected in the historical results of the Whiting Properties nor have they been reflected in proforma adjustments as it is not practical to allocate such costs for the historical statements or estimate such costs for proforma purposes. The pro forma results of operations are not necessarily indicative of the results of operations that would actually have been attained if the transaction had occurred as of this date. These statements should be read in conjunction with our historical financial statements and related notes and the Statements of Oil and Gas Revenue and Direct Operating Expenses of the Properties. F-54 DELTA PETROLEUM CORPORATION Unaudited Condensed Pro Forma Statement of Operations Nine Months Ended March 31, 2001

July 10, 2000 & Pro Forma Delta September 28, 2000 Adjustments Pro Forma Historical North Dakota Combined Delta ---------- ------------------ ------------ ---------- Revenue: Oil and gas sales $ 9,351,912 291,793 - $ 9,643,705 Operating fee income 79,634 - - 79,634 Other revenue 44,050 - - 44,050 ----------- ------- -------- ----------- Total revenue 9,475,596 291,793 - 9,767,389 Operating expenses: Lease operating expenses 3,782,468 20,593 3,803,061 Depreciation and depletion 1,555,522 - 154,543 (1) 1,710,065 Exploration expenses 48,859 - 48,859 Dry hole costs 90,391 - - 90,391 Professional fees 815,177 - 815,177 General and administrative 895,795 - 895,795 Stock option expense 334,383 - 334,383 ----------- ------- -------- ----------- Total operating expenses 7,522,595 20,593 154,543 7,697,731 ----------- ------- -------- ----------- Income (loss) from operations 1,953,001 271,200 (154,543) 2,069,658 Other income and expenses: Other income 435,317 - 435,317 Interest and financing costs (1,494,865) - (147,438) (2) (1,642,303) ----------- ------- -------- ----------- Total other income and expenses (1,509,548) - (147,438) (1,206,986) ----------- ------- -------- ----------- Net income (loss) $ 893,453 271,200 (301,981) $ 862,672 =========== ======= ======== =========== Basic income (loss) per common share $ 0.09 $ 0.09 =========== =========== Weighted average number of common shares outstanding 10,049,344 10,049,344 =========== ===========

See accompanying notes to condensed pro forma financial statements. F-55 DELTA PETROLEUM CORPORATION Unaudited Condensed Pro Forma Statement of Operations Year Ended June 30, 2000

July 10, 2000 & Pro Forma Delta November 1, 1999 December 1, 1999 September 28, 2000 Adjustments Pro Forma Historical New Mexico Point Arguello North Dakota Combined Delta ------------ ---------------- ---------------- ------------------ ----------- ---------- Revenue: Oil and gas sales $ 3,355,783 342,304 1,481,344 3,133,565 $ 8,312,996 Gain on sale of oil and gas properties 75,000 - - - 75,000 Other revenue 166,765 - - - 166,765 ----------- ------- --------- --------- ---------- ----------- Total revenue 3,597,548 342,304 1,481,344 3,133,565 - 8,554,761 Operating expenses: Lease operating expenses 2,405,469 75,595 1,266,245 233,475 3,980,784 Depreciation and depletion 887,802 - - - 1,999,594(1) 2,887,396 Exploration expenses 46,730 - - - 46,730 General and administrative 1,777,579 - - - 1,777,579 Stock option expense 537,708 - - - 537,708 ----------- ------- --------- --------- ---------- ----------- Total operating expenses 5,655,288 75,595 1,266,245 233,475 1,999,594 9,230,197 ----------- ------- --------- --------- ---------- ----------- Income (loss) from operations (2,057,740) 266,709 215,099 2,900,090 (1,999,594) (675,436) Other income and expenses: Gain on write-off of royalty payable 68,433 - - - - 68,433 Interest and financing costs (1,264,954) - - - (1,109,017)(2) (2,373,971) Loss on sale of securities available for sale (112,789) - - - (112,789) ----------- ------- --------- --------- ---------- ----------- Total other income and expenses (1,309,310) - - - (1,109,017) (2,418,327) ----------- ------- --------- --------- ---------- ----------- Net income (loss) $(3,367,050) 266,709 215,099 2,900,090 (3,108,611) $(3,093,763) =========== ======= ========= ========= ========== =========== Basic income (loss) per common share $ (0.46) $ (0.42) =========== =========== Weighted average number of common shares outstanding 7,271,336 100,000 7,371,336 =========== ========== ===========

See accompanying notes to condensed pro forma financial statements. F-56 NOTES TO CONDENSED PRO FORMA FINANCIAL STATEMENTS JUNE 30, 2000 (UNAUDITED) A) BASIS OF PRESENTATION The accompanying unaudited condensed pro forma statement of operations for the nine months ended March 31, 2001 and for the year ended June 30, 2000 assumes that the acquisition of the Properties occurred as of July 1, 1999. No general and administrative or other indirect costs related to the Properties have been reflected in the historical results of the Properties nor have they been reflected in proforma adjustments as it is not practical to allocate such costs for the historical statements or estimate such costs for proforma purposes. The pro forma results of operations are not necessarily indicative of the results of operations that would actually have been attained if the transactions had occurred as of this date. These statements should be read in conjunction with the historical financial statements and related notes of Delta and the Statements of Revenue and Direct Operating Expenses of the Properties which are included in this prospectus. B) ACQUISITION OF WHITING PROPERTIES On November 1, 1999, Delta Petroleum Corporation ("Delta" or "the Company") purchased interests in 10 operated wells in Eddy County, New Mexico with an average working interest of 75%, associated acreage, and 1 non- operated well in Matagorda County, Texas with a working interest of 39.5% ("New Mexico Properties") for a purchase price of $2,879,850 financed through borrowings from an unrelated entity at an interest rate of 18% per annum. On December 1, 1999, Delta purchased a 6.07% 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 ("Point Arguello Properties") from a shareholder for a purchase price of approximately $6,758,550 consisting of $5,625,000 in cash and the issuance of 500,000 shares of the Company's common stock with a fair market value of $1,333,550. 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 per share. 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 20 producing and 5 injection wells located in the Eland and Stadium fields, Stark County, North Dakota ("North Dakota Properties"). The largest value is located in the Eland field where our working interest average is 3.25%. The July 10, 2000 and September 28, 2000 payments resulted in the acquisition by the Company of 67% and 33%, respectively, of the ownership interest in each property acquired. The $3,745,000 payment on July 10, 2000 was financed through borrowings from an unrelated entity and personally guaranteed by two of the Company's officers. 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 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 three above-mentioned acquisitions are referred to as "the Properties". F-57 C) ACQUISITION OF PROPERTIES - STATEMENT OF OPERATIONS The accompanying condensed pro forma statement of operations for the nine months ended March 31, 2001 and for the year ended June 30, 2000 has been adjusted to include the historical revenue and direct lease operating expenses of the Properties. The pro forma adjustments represent the operating revenue and direct lease operating expenses the Company would have earned if they owned the properties during the entire period presented. The following adjustments have been made to the accompanying condensed pro forma statement of operations for the nine months ended March 31, 2001 the year ended June 30, 2000: Nine Months Ended March 31, 2001 The North Dakota properties were acquired as of July 10, 2000 and September 28, 2000. Revenues and operating expenses for the period from July 1, 2000 and September 28, 2000 were $291,793 and $20,593, respectively. Revenue and expenses for the North Dakota properties after the acquisition dates and for the Point Arguello and New Mexico properties are reflected in the Company's historical financial statements. Year Ended June 30, 2000 The New Mexico and Point Arguello properties were acquired during the Company's year ending June 30, 2000. Revenues and expenses after the dates of acquisition were reflected in the Company's historical financial statements. Revenues and expenses for periods prior to the acquisition date for all three properties are as follows: Revenues Expenses ---------- ---------- New Mexico Three months ended September 30, 1999 254,932 66,339 October 1999 87,372 9,256 ---------- ---------- 342,304 75,595 ========== ========== Point Arguello Three months ended September 30, 1999 903,646 800,776 October and November 1999 577,698 465,469 ---------- ---------- 1,481,344 1,266,245 ========== ========== North Dakota Year ended June 30, 2000 3,133,565 233,475 ========== ========== (1) To record pro forma depletion expense giving effect to the acquisition of the Whiting properties for periods prior to the ownership by Delta. F-58 Nine Months Ended March 31, 2001 Acquisition Average Cost Depletion Pro Forma Basis Rate Expense ----------- --------- ----------- July 10, 2000 & September 28, 2000 North Dakota 5,001,394 0.0309 154,543 Delta historical depletion and depreciation expense 1,555,522 ---------- Total $1,710,065 ========== Year Ended June 30, 2000 Acquisition Average Cost Depletion Pro Forma Basis Rate Expense ----------- --------- ----------- November 1, 1999 New Mexico 2,880,000 0.0209 60,192 December 1, 1999 Point Arguello 3,285,867 0.1441 473,493 July 10, 2000 & September 28, 2000 North Dakota 5,001,394 0.2931 1,465,909 ----------- Subtotal 1,999,594 Delta historical depletion and depreciation expense 887,802 ----------- Total $ 2,887,396 =========== (2) To record pro forma interest expense for interest associated with the debt incurred in connection with the Properties for the period prior to the ownership by Delta at rates from 9.5% to 18% per annum. A one-eighth change in interest rate would have a $18,281 annual impact on interest expense. Nine Months Ended March 31, 2001 Acquisition Interest Pro Forma Debt Rate per Annum Expense ----------- -------------- ----------- July 10, 2000 & September 28, 2000 North Dakota 3,745,000 15.00% 147,438 Delta historical interest and financing costs 1,494,865 ----------- Total $ 1,642,303 =========== F-59 Year Ended June 30, 2000 Acquisition Interest Pro forma Debt Rate per Annum Expense ----------- -------------- ---------- November 1, 1999 New Mexico 2,880,000 18.00% 172,800 December 1, 1999 Point Arguello 8,000,000 9.50% 316,667 Amortization of deferred financing costs for Point Arguello acquisition 57,800 July 10, 2000 & September 28, 2000 North Dakota 3,745,000 15.00% 561,750 ---------- Subtotal 1,109,017 Delta historical interest and financing costs 1,264,954 ---------- Total $2,373,971 ========== No income tax effects of the pro forma adjustment have been reflected due to Delta's net operating loss carry forward position and income tax valuation allowance. F-60 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 December 23, 1997, we completed a sale of 156,950 shares of our common stock to Evergreen Resources, Inc. ("Evergreen"), another oil and gas company, for net proceeds to us of $350,000. 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 $6,475 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 $216,670 based on the estimated fair value of the options issued and recorded at $623,920 as undeveloped oil and gas properties. On December 1, 1998, we issued 10,000 shares of our common stock valued at $15,750, 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 $32,063, 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 $128,250, 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 $273,375, 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 $549,563, 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 $116,451, 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 $73,828, 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 $511,944, 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 $1,646,474, 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 $1,335,702, 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 $1,102,500. We paid a cash commission of $110,250 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. (3) 10.2 Amended and Restated Registration Rights Agreement. (3) II-6 10.3 Amended and Restated Agreement (warrant side agreement). (3) 10.4 Warrant Interpretation Agreement. (3) 10.5 Agreement effective October 28, 1992 between Delta Petroleum Corporation, Burdette A. Ogle and Ron Heck. Incorporated by reference from Exhibit 28.2 to the Company's Form 8-K dated December 4, 1992. (1) 10.6 Option Amendment Agreement effective March 30, 1993. Incorporated by reference from Exhibit 28.2 to the Company's Form 8-K dated April 14, 1993. (1) 10.8 Agreement between Delta Petroleum Corporation and Burdette A. Ogle dated February 24, 1994 for offshore Santa Barbara California Federal oil and gas units. Incorporated by reference from Exhibit 28.1 to the Company's Form 8-K dated February 25, 1994. (1) 10.9 Addendum to agreement dated February 24, 1994 between Delta Petroleum Corporation and Burdette A. Ogle for offshore Santa Barbara California Federal oil and gas units. Incorporated by reference from Exhibit 28.1 to the Company's Form 8-K dated May 24, 1994. (1) 10.10 Addendum #2 to agreement dated February 24, 1994 between Delta Petroleum Corporation and Burdette A. Ogle for offshore Santa Barbara California Federal oil and gas units. Incorporated by reference from Exhibit 28.2 to the Company's Form 8-K dated July 15, 1994. (1) 10.11 Addendum #3 to agreement dated February 24, 1994 between Delta Petroleum Corporation and Burdette A. Ogle. Incorporated by reference from Exhibit 28.3 to the Company's Form 8-K dated August 9, 1994. (1) 10.12 Addendum #4 to agreement dated February 24, 1994 between Delta Petroleum Corporation and Burdette A. Ogle for offshore Santa Barbara California Federal oil and gas units. Incorporated by reference from Exhibit 28.1 to the Company's Form 8-K dated August 31, 1993. (1) 10.13 Burdette A. Ogle "Assignment, Conveyance and Bill of Sale of Federal Oil and Gas Leases Reserving a Production Payment", "Lease Interests Purchase Option Agreement" and "Purchase and Sale Agreement". Incorporated by reference from Exhibit 28.1 to the Company's Form 8-K dated January 3, 1995. (1) 10.14 Companies Employment Agreements with Aleron H. Larson, Jr. and Roger A. Parker, previously filed on Form 10-KSB for the fiscal year ended June 30, 1998. (1) 10.15 Delta Petroleum Corporation 1993 Incentive Plan, as amended. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated November 1, 1996. (1) 11-7 10.16 Agreement among Eva H. Posman, as Chapter 11 Trustee of Underwriters Financial Group, Inc., Snyder Oil Corporation and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated May 23, 1997. (1) 10.17 Option and First Right of Refusal between Evergreen Resources, Inc., and Delta Petroleum Corporation dated December 23, 1997, previously filed on Form 10-KSB for the fiscal year ended June 30, 1998. (1) 10.18 Professional Services Agreement with GlobeMedia AG and Investment Representation Agreements with GlobeMedia AG, incorporated by reference from Exhibits 99.2 and 99.3 to the Company's Form 8-K dated April 9, 1998. (1) 10.19 Delta Petroleum Corporation 1993 Incentive Plan, as amended June 30, 1999. Incorporated by reference to the Company's Notice of Annual Meeting and Proxy Statement dated June 1, 1999. (1) 10.20 Agreement between Evergreen Resources, Inc., and Delta Petroleum Corporation effective January 1, 1999. Incorporated by reference from Exhibit 99.1 to the Company's Form 10-QSB for the quarterly period ended December 31, 1998. (1) 10.21 Agreement between Burdette A. Ogle and Delta Petroleum Corporation effective December 17, 1998. Incorporated by reference from Exhibit 99.2 to the Company's Form 10-QSB for the quarterly period ended December 31, 1998. (1) 10.22 Agreement between Delta Petroleum Corporation and Ambir Properties, Inc., dated October 12, 1998. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated October 16, 1998. (1) 10.23 Agreement between Whiting Petroleum Corporation and Delta Petroleum Corporation (including amendment) dated June 8, 1999. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated June 9, 1999. (1) 10.24 Purchase and Sale Agreement dated October 13, 1999 between Whiting Petroleum Corporation and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated November 1, 1999. (1) 10.25 Agreement between Delta Petroleum Corporation, Roger A. Parker and Aleron H. Larson, Jr. dated November 1, 1999. Incorporated by reference from Exhibit 99.3 to the Company's Form 8-K dated November 1, 1999. (1) 10.26 Conveyance and Assignment from Whiting Petroleum Corporation dated December 1, 1999. Incorporated by reference from Exhibit 10.1 to the Company's Form 8-K dated December 1, 1999. (1) II-8 10.27 Loan Agreement (without exhibits) between Kaiser-Francis Oil Company and Petroleum Corporation dated December 1, 1999. Incorporated by reference from Exhibit 10.2 to the Company's Form 8-K dated December 1, 1999. (1) 10.28 Promissory Note dated December 1, 1999. Incorporated by reference from Exhibit 10.3 to the Company's Form 8-K dated December 1, 1999. (1) 10.29 July 29, 1999 Agreement between GlobeMedia AG and Delta Petroleum Corporation with November 23, 1999 amendment. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated January 4, 2000. (1) 10.30 Letter Agreement between GlobeMedia AG and Delta Petroleum Corporation dated November 23, 1999. Incorporated by reference from Exhibit 99.3 to the Company's Form 8-K dated January 4, 2000. (1) 10.31 Agreement dated December 30, 1999 between Burdette A. Ogle and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.4 to the Company's Form 8-K dated January 4, 2000. (1) 10.32 Investment Representation Agreement dated December 17, 1999 between Evergreen Resources, Inc. and Delta Petroleum Corporation. Incorporated by reference from Exhibit 99.5 to the Company's Form 8-K dated January 4, 2000. (1) 10.33 Option Agreement between Evergreen Resources, Inc. and Delta Petroleum Corporation dated December 17, 1999 (effective as of January 4, 2000). Incorporated by reference from Exhibit 99.6 to the Company's Form 8-K dated January 4, 2000. (1) 10.34 Purchase and Sale Agreement dated June 1, 2000 between Whiting Petroleum Corporation and Delta Petroleum Corporation. Incorporated by reference from Exhibit 10.1 to the Company's Form 8-K dated July 10, 2000. (1) 10.35 Documents and Agreements dated July 10, 2000 between Delta Petroleum Corporation and Hexagon Investments, Inc. and/or Sovereign Holdings, LLC related to financing arrangements: -Partial Assignment of Contract; -Collateral Assignment of Purchase and Sale Agreement; -Letter Agreement re: loan; -Estoppel Certificate and Agreement; -Promissory Note; -Guarantee Agreement Incorporated by reference from Exhibit 10.2 to the Company's Form 8-K dated July 10, 2000. (1) 10.36 Investment Agreement dated July 21, 2000 between Delta Petroleum Corporation and Swartz Private Equity, LLC and related agreements. Incorporated by reference from Exhibit 99.2 to the Company's Form 8-K dated July 10, 2000. (1) II-9 10.37 Purchase and Sale Agreement and supplemental Letter Agreement dated September 6, 2000, between Saga Petroleum Corporation, et al. and Delta Petroleum Corporation. Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated September 7, 2000. (1) 10.38 Purchase and Sale Agreement between Delta Petroleum Corporation and Castle Offshore LLC and BWAB Limited Liability Company dated August 4, 2000. Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated September 29, 2000. (1) 10.39 Documents evidencing financing arrangements between Hexagon Investments and Delta Petroleum Corporation dated September 28, 2000. Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated September 29, 2000. (1) 10.40 Termination Agreement and Purchase and Sale Agreement dated as of December 18, 2000 between Delta Petroleum Corporation and Saga Petroleum Corp., et al. Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated December 22, 2000. (1) 10.41 Agreements between Evergreen Resources Inc. and Delta Petroleum Corporation dated January 3, 2001. Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated January 22, 2001. (1) 10.41 Purchase and Sale Agreement dated March 29, 2001, between Delta Petroleum Corporation and Panaco, Inc. (without exhibits). Incorporated by reference to Exhibit 10.1 to the Company's Form 8-K dated April 13, 2001. (1) 21 Subsidiaries of the Registrant (2) 23.2 Consent of KPMG LLP (3) 23.3 Consent of Krys Boyle Freedman & Sawyer, P.C. ** ------------------------ (1) Incorporated by reference. (2) Previously filed. (3) Filed herewith electronically. ** Contained in the legal opinion filed as Exhibit 5.1. Undertakings The Company on behalf of itself hereby undertakes and commits as follows: A. 1. To file, during any period in which it offers or sells securities, a post-effective amendment to this registration statement to: (i) Include any prospectus required by Section 10(a)(3) of the Securities Act. II-10 (ii) Reflect in the prospectus any facts or events which, individually or together, represent a fundamental change in the information in the registration statement. (iii) Include any additional or changed material information on the plan of distribution. 2. For determining liability under the Securities Act, to treat each post-effective amendment as a new registration statement of the securities offered, and the offering of the securities at that time to be the initial bona fide offering. 3. To file a post-effective amendment to remove from registration any of the securities that remain unsold at the end of the offering. B. Insofar as indemnification for liabilities arising under the Securities Act of 1933 (the "Act") may be permitted to directors, officers and controlling persons of Delta under the foregoing provisions, or otherwise, Delta has been advised that in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by Delta of expenses incurred or paid by a director, officer or controlling person of Delta in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, Delta will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue. II-11 SIGNATURES Pursuant to the requirements of the Securities Act of 1933, the Company has caused this Amendment No. 1 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 3rd day of July, 2001. DELTA PETROLEUM CORPORATION By: /s/ Roger A. Parker --------------------------------- Roger A. Parker, President and Chief Executive Officer By: /s/ Kevin K. Nanke --------------------------------- Kevin K. Nanke, Treasurer and Chief Financial Officer Pursuant to the requirements of the Securities Act of 1933, this Amendment No. 1 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/ Roger A. Parker July 3, 2001 ---------------------------------- Roger A. Parker, Director /s/ Aleron H. Larson, Jr. July 3, 2001 ---------------------------------- Aleron H. Larson, Jr., Director /s/ Terry D. Enright July 3, 2001 ---------------------------------- Terry D. Enright, Director /s/ Jerrie F. Eckelberger July 3, 2001 ---------------------------------- Jerrie F. Eckelberger, Director