10KSB 1 0001.txt SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-KSB [X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended June 30, 2000. [ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from . Commission File No. 0-16203 DELTA PETROLEUM CORPORATION (Exact name of registrant as specified in its charter) Colorado 84-1060803 (State or other jurisdiction of (I.R.S.Employer Identification No.) incorporation or organization) 555 17th Street, Suite 3310 Denver, Colorado 80202 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (303) 293-9133 Securities registered under Section 12(b) of the Exchange Act: None Securities registered under to Section 12(g) of the Exchange Act: Common Stock, $.01 par value Check whether issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Check if there is no disclosure of delinquent filers in response to Item 405 of Regulation S-B contained in this form, and no disclosure will be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KSB or any amendment to this Form 10-KSB. [X] The issuer's revenues for the fiscal year ended June 30, 2000 total $3,665,781. The aggregate market value as of August 7, 2000 of voting stock held by non-affiliates of the registrant was $53,292,569. As of August 7, 2000, 8,989,125 shares of registrant's Common Stock $.01 par value were issued and outstanding. DOCUMENTS INCORPORATED BY REFERENCE: DEFINITIVE PROXY MATERIALS FOR THE 2000 ANNUAL MEETING OF SHAREHOLDERS - PART III, ITEMS 9, 10, 11, AND 12. The Index to Exhibits appears at Page 37 TABLE OF CONTENTS PART I PAGE ITEM 1. DESCRIPTION OF BUSINESS 1 ITEM 2. DESCRIPTION OF PROPERTY 6 ITEM 3. LEGAL PROCEEDINGS 23 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 23 ITEM 4A. DIRECTORS AND EXECUTIVE OFFICERS 23 PART II ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS 26 ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION 28 ITEM 7. FINANCIAL STATEMENTS 34 ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 34 PART III ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT 34 ITEM 10. EXECUTIVE COMPENSATION 34 ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT 34 ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 34 ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K 34 FORWARD-LOOKING STATEMENTS 35 The terms "Delta", "Company", "we", "our", and "us" refer to Delta Petroleum Corporation and its subsidiaries unless the context suggests otherwise. PART I ITEM 1. DESCRIPTION OF BUSINESS (a) Business Development. Delta Petroleum Corporation ("Delta", "the Company") is 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 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 (17.08 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. 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;" Item 2 herein.) At August 7, 2000, 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 8,989,125 shares of common stock were issued and outstanding. We have outstanding warrants and options to purchase 2,347,500 shares of common stock at prices ranging from $2.00 per share to $6.13 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 2,346,836 shares of common stock at prices ranging from $0.05 to $9.75 per share at August 7, 2000. 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. The Company and Amber entered into an agreement effective October 1, 1998 which provides, in part, for the sharing of the management between the two companies and allocation of expenses related thereto. (b) Business of Issuer. 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, Oklahoma, New Mexico, North 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 primarily in Colorado, California, Oklahoma, Texas, Wyoming and offshore California. We intend to drill on some of our leases (presently owned or subsequently acquired); may farm out or sell all or part of some of the leases to others; and/or may participate in joint venture arrangements to develop certain other leases. Such transactions may be structured in any number of different manners which are in use in the oil and gas industry. Each such transaction is likely to be individually negotiated and no standard terms may be predicted. (1) Principal Products or Services and Their Markets. The principal products produced by us are crude oil and natural gas. The products are generally sold at the wellhead to purchasers in the immediate area where the product is produced. The principal markets for oil and gas are refineries and transmission companies which have facilities near our producing properties. (2) Distribution Methods of the Products or Services. Oil and natural gas produced from our wells are normally sold to purchasers as referenced in (6) below. Oil is picked up and transported by the purchaser from the wellhead. In some instances we are charged a fee for the cost of transporting the oil, which fee is deducted from or accounted for in the price paid for the oil. Natural gas wells are connected to pipelines generally owned by the natural gas purchasers. A variety of pipeline transportation charges are usually included in the calculation of the price paid for the natural gas. (3) Status of Any Publicly Announced New Product or Service. We have not made a public announcement of, and no information has otherwise become public about, a new product or industry segment requiring the investment of a material amount of the Company's 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. We do not depend upon one or a few major customers for the sale of oil and gas as of the date of this report. The loss of any one or several customers would not have a material adverse effect on our business. (7) Patents, Trademarks, Licenses, Franchises, Concessions, Royalty Agreements or Labor Contracts. We do not own any patents, trademarks, licenses, franchises, concessions, or royalty agreements except oil and gas interests acquired from industry participants, private landowners and state and federal governments. We are not a party to any labor contracts. (8) Need for Any Governmental Approval of Principal Products or Services. Except that we must obtain certain permits and other approvals from various governmental agencies prior to drilling wells and producing oil and/or natural gas, we do not need to obtain governmental approval of our principal products or services. (9) Government Regulation of the Oil and Gas Industry. General. Our business is affected by numerous governmental laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the energy industry. Changes in any of these laws and regulations could have a material adverse effect on our business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations. We believe that our operations comply in all material respects with all applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on our method of operations than on other similar companies in the energy industry. The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing. Environmental Regulation. Together with other companies in the industries in which we operate, our operations are subject to numerous federal, state, and local environmental laws and regulations concerning 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 financial condition of the Company, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur substantial environmental liabilities or costs. Hazardous Substances and Waste Disposal. We currently own or lease interests in numerous properties that have been used for many years for natural gas and crude oil production. Although the operator of such properties may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us. In addition, some of these properties have been operated by third parties over whom we had no control. The U.S. Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the management and disposal of wastes. Although CERCLA currently excludes petroleum from cleanup liability, many state laws affecting our operations impose clean-up liability regarding petroleum and petroleum related products. In addition, although RCRA currently classifies certain exploration and production wastes as "non-hazardous," such wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. If such a change in legislation were to be enacted, it could have a significant impact on our operating costs, as well as the gas and oil industry in general. Oil Spills. Under the Federal Oil Pollution Act of 1990, as amended ("OPA"), (i) owners and operators of onshore facilities and pipelines, (ii) lessees or permittees of an area in which an offshore facility is located and (iii) owners and operators of tank vessels ("Responsible Parties") are strictly liable on a joint and several basis for removal costs and damages 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. 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. ITEM 2. DESCRIPTION OF PROPERTY (a) Office Facilities. Our offices are located at 555 Seventeenth Street, Suite 3310, Denver, Colorado 80202. We lease approximately 4,800 square feet of office space for $7,125 per month and the lease will expire in April of 2002. We subleased approximately 2,500 square feet of our space to Bion Environmental Technologies, Inc. for $3,575 per month until May 1, 2000. (b) 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 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 approximately 25 drillable prospects. As of August 7, 2000, 20 wells have been drilled of which ten are now producing and one is awaiting completion. We expect to participate in the drilling of two additional wells during the remainder of calendar 2000. The area has adequate markets for the volumes of natural gas that are projected from the drilling activity in the area. Colorado. Denver-Julesburg Basin. We own leasehold interests in approximately 480 gross (47 net) acres and have interests in eight gross (.77 net) wells in the Denver-Julesburg Basin producing primarily from the D-Sand and J-Sand formations. No new activity is planned for this area for the next fiscal year. Piceance Basin. We own working interests in 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. 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 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 20 to 30 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 its 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 $450,000 to Delta 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 has been drilled and is producing. 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 New Mexico and 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. North Dakota. We are in the process of completing our acquisition of a small 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 350 barrels of oil equivalent per day. Delta has purchased two thirds of the interests and has an option to purchase the remaining third on September 29, 2000. 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 drilling conducted between 1966 and 1984 have resulted in the discovery of an estimated two billion Bbls of oil and three trillion cubic feet of gas. Of these totals, some 869 million Bbls of oil and 819 billion cubic feet of gas have been produced and sold. During 1999, POCS production was approximately 150,000 Bbls of oil and 210 million cubic feet of gas per day according to the Minerals Management Service of the Department of the Interior ("MMS"). 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. 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 the Company owns interests are located in the POCS seaward of the three mile limit, leasing, drilling, and development of these units are not directly regulated by the State of California. However, to the extent that any production is transported to an on-shore facility through the state waters, the Company's pipelines (or other transportation facilities) would be subject to California state regulations. Construction and operation of any such pipelines would require permits from the state. Additionally, all development plans must be consistent with the Federal Coastal Zone Management Act ("CZMA"). In California the decision of CZMA consistency is made by the California Coastal Commission. The Santa Barbara County Energy Division and the Board of Supervisors will have a significant impact on the method and timing of any offshore field development through its permitting and regulatory authority over the construction and operation of on-shore facilities. In addition, the Santa Barbara County Air Pollution Control District has authority in the federal waters off Santa Barbara County through the Federal Clean Air Act as amended in 1990. Each working interest owner will be required to pay its proportionate share of these costs based upon the amount of the interest that it owns. The size of our working interest in the units, other than the Rocky Point Unit, varies from 2.492% to 15.60%. Whiting Petroleum Corporation holds a working interest for us as our nominee of approximately 70% in the Rocky Point Unit. This interest is expected to be reduced if the Rocky Point Unit is included in the Point Arguello Unit and developed from existing Point Arguello platforms. We may be required to farm out all or a portion of our interests in these properties to a third party if we cannot fund our share of the development costs. There can be no assurance that we can farm out our interests on acceptable terms. These units have been formally approved and are regulated by the MMS. While the Federal Government has recently attempted to expedite the process of obtaining permits and authorizations necessary to develop the properties, there can be no assurance that it will be successful in doing so. We do not act as operator of any offshore California properties and consequently will not generally control the timing of either the development of the properties or the expenditures for development unless we choose to unilaterally propose the drilling of wells under the relevant operating agreements. The MMS initiated the California Offshore Oil and Gas Energy Resources (COOGER) Study at the request of the local regulatory agencies of the three counties (Ventura, Santa Barbara and San Luis Obispo) affected by offshore oil and gas development. A private consulting firm completed the study under a contract with the MMS. The COOGER 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: 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, pursuant to 30 CFR 250.110. The SOO was directed for the purpose of preparing what became known as the COOGER Study. Two-thirds of the cost of the Study was funded by the participating companies in lieu of the payment of rentals on the leases. Additionally, all operations were suspended on the leases during this period. On November 12, 1999, as the COOGER Study drew to a conclusion, the MMS approved requests made by the operating companies for a Suspension of Production (SOP) status for the POCS leases and units. During the period of a 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 the last quarter of 1999, and the first and second quarters of 2000. 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 currently engaged in studies and project planning to meet the next milestone leading to development of the leases. Where additional drilling is needed the operators will bring a mobile drilling unit to the POCS to further delineate the undeveloped oil and gas fields. 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 agreements, it will be necessary for us to seek funding from outside sources. Likely potential sources for such funding are currently anticipated to include (a) public and private sales of our Common Stock (which may result in substantial ownership dilution to existing shareholders), (b) bank debt from one or more commercial oil and gas lenders, (c) the sale of debt instruments to investors, (d) entering into farm- out arrangements with respect to one or more of our interests in the properties whereby the recipient of the farm-out would pay the full amount of our share of expenses and we would retain a carried ownership interest (which would result in a substantial diminution of our ownership interest in the farmed-out properties), (e) entering into one or more joint venture relationships with industry partners, (f) entering into financing relationships with one or more industry partners, and (g) the sale of some or all of our interests in the properties. It is unlikely that any one potential source of funding would be utilized exclusively. Rather, it is more likely that we will pursue a combination of different funding sources when the need arises. Regardless of the type of financing techniques that are ultimately utilized, however, it currently appears likely that because of our small size in relation to the magnitude of the capital requirements that will be associated with the development of the subject properties, we will be forced in the future to issue significant amounts of additional shares, pay significant amounts of interest on debt that presumably would be collateralized by all of our assets (including our offshore California properties), reduce our ownership interest in the properties through sales of interests in the 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 in relation to our small size, management believes that the opportunities for us to increase our asset base and ultimately improve our cash flow are also substantial in relation to our size. Although there are several factors to be considered in connection with our plans to obtain funding from outside sources as necessary to pay our proportionate share of the costs associated with developing our offshore properties (not the least of which is the possibility that prices for petroleum products could decline in the future to a point at which development of the properties is no longer economically feasible), we believe that the timing and rate of development in the future will in large part be motivated by the prices paid for petroleum products. To the extent that prices for petroleum products were to decline below their recent levels, it is likely that development efforts will proceed at a slower pace such that costs will be incurred over a more extended period of time. If petroleum prices remain at current levels, however, we believe that development efforts will intensify. Our ability to successfully negotiate financing to pay our share of development costs on favorable terms will be inextricably linked to the prices that are paid for petroleum products during the time period in which development is actually occurring on each of the subject properties. Gato Canyon Unit. We hold a 15.60% working interest (directly 8.63% and through Amber 6.97%) in the Gato Canyon Unit. This 10,100 acre unit is operated by Samedan Oil Corporation. Seven test wells have been drilled on the Gato Canyon structure. Five of these were drilled within the boundaries of the Unit and two were drilled outside the Unit boundaries in the adjacent State Tidelands. The test wells were drilled as follows: within the boundaries of the Unit; three wells were drilled by Exxon, two in 1968 and one in 1969; one well was drilled by Arco in 1985; and, one well was drilled by Samedan in 1989. Outside the boundaries of the Unit, in the State Tidelands but still on the Gato Canyon Structure, one well was drilled by Mobil in 1966 and one well was drilled by Union Oil in 1967. In April 1989, Samedan tested the P-0460 #2 which yielded a combined test flow rate of 5,160 Bbls of oil per day from six intervals in the Monterey Formation between 5,880 and 6,700 feet of drilled depth. The Monterey Formation is a highly fractured shale formation. The Monterey (which ranges from 500' 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 ExxonMobil Company. Four test wells were drilled within this unit. These test wells were drilled as follows: two wells were drilled by Sun Oil (now Oryx Energy), one in 1984 and one in 1985; and the other two wells were drilled by Reading & Bates, both in 1984. All four wells drilled on this unit have indicated the presence of oil and gas in the Monterey Formation. The largest of these, the Sun P-0422 #1, yielded a combined test flow rate of 3,750 Bbls of oil per day from the Monterey. The oil in the upper block has an average estimated gravity of 10 degrees API and the oil in the subthrust block has an average estimated gravity of 15 degrees 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 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 degrees 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 degrees API. The two completed test wells were drilled by Conoco, one in 1982 and the second in 1985. The Sword field is located in the western Santa Barbara Channel ten miles west of Point Conception and five miles south of Point Arguello's field Platform Hermosa (see Map). Water depths range from 1000 feet to 1800 feet in the area of the field. It is anticipated that the oil and gas produced from the Sword Field will likely be processed at the existing Gaviota consolidated facility and the oil would then be transported out of Santa Barbara County in the All American Pipeline (see Map). Access to the Gaviota plant is through Platform Hermosa and the existing Point Arguello Pipeline system. A pipeline proposed to be laid from a platform located in the northern area of the Sword field to Platform Hermosa would be approximately five miles in length. Delta's share of the estimated capital costs to develop the Sword field is approximately $19 million. 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. Whiting Petroleum Corporation ("Whiting") holds, as nominee for Delta, an 11.11% interest in OCS Block 451 (E/2) and 100% interest in OCS Block 452 and 453, which leases comprise the undeveloped Rocky Point Unit. The Rocky Point Unit is operated by Whiting. 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 1, 2001. 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. Developed Properties: Point Arugello Unit. Whiting holds, as our nominee, the equivalent of a 6.07% working interest in the form of a financial arrangement termed a "net operating interest" in the Point Arguello Unit and related facilities. 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 three wells during the remainder of calendar 2000 and five redrills 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 INSERT Map depicting Santa Barbara County, California oil and gas facilities in relation to offshore federal units in which the Company owns interests. 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 workplan. 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. (c) 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 pursuant to which we acted as producer. 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 we have committed to sell 25,000 barrels per month from June 2000 to December 2000 at $14.65 under fixed price contracts with production purchases. (See "Management's Discussion and Analysis or Plan of Operation.") (d) Productive Wells and Acreage. The table below shows, as of June 30, 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. 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 50 4.92 62 14.78 43,138 5,957 (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 thereof. (e) 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. (f) Drilling Activity During the years indicated, we drilled or participated in the drilling of the following productive and nonproductive exploratory and development wells: Year Ended Year Ended Year Ended June 30, 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 the Company had only a royalty interest. (g) Present Drilling Activity We plan on participating in the drilling of five new wells before the end of calendar 2000. ITEM 3. 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. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The 1999 Annual Meeting of the shareholders of the Company was held on March 30, 2000. At the Annual Meeting the following persons, constituting the entire board of directors, were elected as directors of the Company to serve until the next annual meeting: Abstentions, Votes Withheld & Name Affirmative Votes Negative Votes Aleron H. Larson, Jr. 5,540,927 33,895 Roger A. Parker 5,540,927 33,895 Jerrie F. Eckelberger 5,541,046 33,776 Terry D. Enright 5,541,046 33,776 Also ratified, approved, and adopted was the appointment of KPMG, LLP for our auditors for the year ended June 30, 2000 with 5,555,022 affirmative votes, 19,800 negative votes, 3,900 abstentions, and 0 votes withheld for the proposition. ITEM 4A. DIRECTORS AND EXECUTIVE OFFICERS. The following information with respect to Directors and Executive Officers is furnished pursuant to Item 401(a) of Regulation S-B. Name Age Positions Period of Service Aleron H. Larson, Jr. 55 Chairman of the Board, May 1987 to Present Chief Executive Officer, Secretary, Treasurer, and a Director Roger A. Parker 38 President and a Director May 1987 to Present Terry D. Enright 51 Director November 1987 to Present Jerrie F. Eckelberger 56 Director September 1996 to Present Kevin K. Nanke 35 Chief Financial Officer December 1999 to Present The following is biographical information as to the business experience of each current officer and director of the Company. 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 Underwriters Financial Group, Inc. ("UFG") (formerly Chippewa Resources Corporation), a public company then listed on the American Stock Exchange which presently owns approximately 4.9% of the outstanding equity securities of Delta. 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 a majority-owned subsidiary of Delta. He has also served, since 1983, as the President and Board Chairman of Western Petroleum Corporation, a public Colorado oil and gas company which is now inactive. Mr. Larson practiced law in Breckenridge, Colorado from 1971 until 1974. During this time he was a member of a law firm, Larson & Batchellor, engaged primarily in real estate law, land use litigation, land planning and municipal law. In 1974, he formed Larson & Larson, P.C., and was engaged primarily in areas of law relating to securities, real estate, and oil and gas until 1978. Mr. Larson received a Bachelor of Arts degree in Business Administration from the University of Texas at El Paso in 1967 and a Juris Doctor degree from the University of Colorado in 1970. Roger A. Parker, age 38, served as the President, a Director and Chief Operating Officer of Underwriters Financial Group from July of 1990 through March 31, 1993. Mr. Parker resigned from all positions with UFG effective March 31, 1993. Mr. Parker also serves as President, Chief Operating Officer and Director of Amber. He also serves as a Director and Executive Vice President of P & G Exploration, Inc., a private oil and gas company (formerly Texco Exploration, Inc.). Mr. Parker has also been the President, a Director and sole shareholder of Apex Operating Company, Inc. since its inception in 1987. He has operated as an independent in the oil and gas industry individually and through public and private ventures since 1982. He was at various times, from 1982 to 1989, a Director, Executive Vice President, President and shareholder of Ampet, Inc. He received a Bachelor of Science in Mineral Land Management from the 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). Terry D. Enright, age 51, 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 29 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 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 35, appointed Chief Financial Officer in December 1999, joined Delta in April 1995 as Controller. 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 the Officers or Directors. Messrs. Enright and Eckelberger serve as the Audit Committee and as the Compensation Committee. Messrs. Enright and Eckelberger also constitute the Incentive Plan Committee for the Delta 1993 Incentive Plan for the Company. All directors will hold office until the next annual meeting of shareholders. There are no arrangements or understandings among or between any director of the Company and any other person or persons pursuant to which such director was or is to be selected as a director. All officers of the Company will hold office until the next annual directors' meeting of the Company. There is no arrangement or understanding among or between any such officer or any person pursuant to which such officer is to be selected as an officer of the Company. PART II ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS (a) 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. Quarter Ended High Low September 30, 1997 $4.00 2.88 December 31, 1997 3.88 1.66 March 31, 1998 3.13 2.06 June 30, 1998 4.44 3.13 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 On August 7, 2000, the closing price of the Common Stock was $6.25. (b) Approximate Number of Holders of Common Stock. The number of holders of record of the Company's Common Stock at August 7, 2000 was approximately 1,000 which does not include an estimated 2,600 additional holders whose stock is held in "street name". (c) Dividends. We have not paid dividends on our stock and we do not expect to do so in the foreseeable future. (d) 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 pursuant to Section 4(2). On December 23, 1997, we completed a sale of 156,950 shares of the Company's common stock to Evergreen Resources, Inc. ("Evergreen"), another oil and gas company, for net proceeds to the Company of $350,000. During the year ended June 30, 1997, we issued 100,117 shares of our common stock in exchange for oil and gas properties, for services, and in connection with a settlement agreement. These transactions were 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 an unrelated individual for net proceeds to the Company of $6,475. On October 12, 1998, we issued 250,000 shares of our common stock and 500,000 options to purchase our common stock at various 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. On December 1, 1998, we issued 10,000 shares of our common stock to an unrelated entity for public relation services. 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 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.) On November 30, 1999, we completed a sale of 428,000 shares of the Company's common stock to Bank Leu AG, for net proceeds to the Company of $750,000. On January 4, 2000, we completed a sale of 175,000 shares of the Company=s common stock to Evergreen, another oil and gas company, for net proceeds to the Company of $350,000. On June 1, 2000, we issued 90,000 shares of the Company's common stock valued at $273,375 to Whiting as a deposit to acquire certain interest in producing properties in Stark County, North Dakota. During fiscal 2000, we issued 215,000 shares of our common stock to an unrelated entity as a commission for their involvement with the Point Arguello Unit and New Mexico acquisitions completed in fiscal 2000. On July 3, 2000, we completed a sale of 258,621 shares of the Company's common stock to Bank Leu AG, for net proceeds to the Company of $674,000. ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION Liquidity and Capital Resources. At June 30, 2000, we had a working capital deficit of $1,985,141 compared to a working capital deficit of $295,635 at June 30, 1999. Our current assets include accounts receivable from related parties (including affiliated companies) of $142,582 at June 30, 2000 which is primarily for drilling costs, and lease operating expense on wells owned by the related parties and operated by us. The amounts are due on open account and are non- interest bearing. Our current liabilities include current portion of long-term debt of $1,831,469 at June 30, 2000. We borrowed these funds to acquire certain oil and gas properties in fiscal 2000. 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 $217 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 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. We estimate our capital expenditures for onshore properties to be approximately $1,000,000 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. We received the proceeds from the exercise of options to purchase shares of our common stock of $1,377,536 and $160,000 during the years ended June 30, 2000 and 1999, respectively. On August 20, 1998, we entered into a loan agreement with Labyrinth Enterprises, L.L.C., an unrelated entity, for $400,000. The loan bore interest at the annual rate of 10% and was collateralized by all producing oil and gas properties owned by us and was paid in full in November 1998. In addition to the principal and interest payment required, we paid a $50,000 origination fee. Our officers personally guaranteed this loan. On May 24, 1999, we borrowed $1,000,000 at 18% per annum from our officers under a promissory note maturing on June 1, 2001. This promissory note was identical in terms to the promissory note under which these officers borrowed the money from a private lender which they, in turn, loaned to us. On December 1, 1999, we paid the loan in full. On July 30, 1999, we borrowed $2,000,000 at 18% per annum from an unrelated entity maturing on August 1, 2001 which was personally guaranteed by two of our officers. The loan proceeds were used as deposit funds for the Point Arguello acquisition. We paid a 2% origination fee to the lender. In addition, as consideration for the guarantee of our indebtedness, we entered into an agreement with our officers, under which a 1% overriding royalty interest in the properties acquired with the proceeds form the loans (proportionately reduced to the interest in each property acquired) will be assigned to each of the officers. Each overriding royalty had a fair market value of approximately $125,000 which was recorded as an adjustment to the purchase price. At June 30, 2000 the principal balance was $740,462. Subsequent to year-end, the balance was paid in full. On November 1, 1999, we acquired interests in 11 oil and gas producing properties located in New Mexico and Texas for a cost of $2,879,850. Also on November 1, 1999, we borrowed the funds for the above mentioned acquisition at 18% per annum from an unrelated entity maturing on January 31, 2000, which was personally guaranteed by two of our officers. 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 acquired in each property). Each overriding royalty had a fair market value of approximately $37,500 which was recorded as an adjustment to the purchase price. We also paid a 1% origination fee to the lender. On December 1, 1999, we paid the loan in full. 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 1, 1999, we borrowed $8,000,000 at prime rate plus 1-1/2% (11% at June 30, 2000) from an unrelated entity. The loan agreement provides for a 4-1/2 year loan with additional compensation to the lender if paid after September 1, 2000. The proceeds from this loan were used to payoff existing debt and to fund the balance of the Point Arguello Unit purchase. We are required to make monthly payments equal to the greater of $150,000 or 75% of net cash flows from the acquisitions completed on November 1, 1999 and December 1, 1999. The loan is collateralized by our oil and gas properties acquired with the loan proceeds. 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. On July 5, 2000, we completed the sale of 258,621 shares of its restricted common stock to an unrelated entity for $750,000. A fee of $75,000 was paid and options to purchase 100,000 shares of our common stock at $2.50 per share and 100,000 shares at $3.00 per share for one year were issued to an unrelated individual and entity and as consideration for their efforts and consultation related to the transaction. On July 10, 2000, we paid $3,745,000 to acquire interests in producing wells and acreage located in the Eland and Stadium fields in Stark County, North Dakota. The July 10, 2000 payment resulted in the acquisition by us of 67% of the ownership interest in each property to be acquired. An optional payment of $1,845,000, less net production revenues accrued from February 1, 2000, is due September 29, 2000 to purchase the remaining ownership interest in each property. The $3,745,000 payment on July 10, 2000 was financed through borrowings from an unrelated entity and personally guaranteed by two of the our officers. On July 21, 2000, we and an unrelated entity ("the entity") entered into a definitive agreement entitled "Investment Agreement" whereby the entity has given a firm commitment to allow us to issue to the entity up to a total of $20,000,000 of its common stock over three years from time to time as often as monthly in amounts based upon certain market conditions and at prices based upon market prices for our common stock at the time of issuance. As consideration the entity has received a warrant to purchase 500,000 shares of our common stock at $3.00 per share for five years and may receive additional warrants to purchase our common stock under the terms of the Investment Agreement. A warrant to purchase 150,000 shares of the entity common stock at $3.00 per share for five years was issued to an unrelated company as consideration for its efforts and consultation related to potential financing alternatives and this transaction. Proceeds will be used for property acquisitions, debt reduction and working capital. We expect to raise additional capital by selling our common stock in order to fund our capital requirements for our portion of the costs of the drilling and completion of development wells on our proved undeveloped properties during the next twelve months. There is no assurance that we will be able to do so or that we will be able to do so upon terms that are acceptable. We are currently trying to establish a credit facility with a financial institution but we have not determined the amount, if any, that we could borrow against our existing properties. 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, proceeds from the sale of 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. Results of Operations Net Earnings (Loss). The Company's net loss for the year ended June 30, 2000 was $3,367,050 compared to the net loss of $2,998,759 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 $1,717,651 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 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. 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 - *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 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. There was no impairment for oil and gas properties in fiscal 2000. 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 shareholder relations to the Company. 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 the two officers of the Company 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. 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 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 Company has not yet assessed the impact, if any, that FIN 44 might have on its 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 Company has not yet assessed the impact, if any, that SAB 101 might have on its 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 Company has not assessed the impact, if any, that SFAS 133 will have on its financial statements. ITEM 7. FINANCIAL STATEMENTS Financial Statements are included herein beginning on page F-1. ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not applicable. PART III The information required by Part III, Items 9 "Directors, Executive Officers, Promoters and Control Persons; Compliance with Section 16(a) of the Exchange Act", 10 "Executive Compensation", 11 "Security Ownership of Certain Beneficial Owners and Management", and 12 "Certain Relationships and Related Transactions", is incorporated by reference to Registrant's definitive Proxy Statement which will be filed with the Securities and Exchange Commission in connection with the Annual Meeting of Shareholders. For information concerning Item 9 "Directors and Executive Officers"; see Part I; Item 4A. ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits. The Exhibits listed in the Index to Exhibits appearing at Page 37 filed as part of this report. (b) Reports on Form 8-K. Form 8-K; November 1, 1999; Items 2 & 7 Form 8-K/A November 1, 1999; Item 7 Form 8-K; December 1, 1999; Items 2 & 5 & 7 Form 8-K/A; December 1, 1999; Item 7 Form 8-K; January 1, 2000; Items 5 & 7 Form 8-K; July 10, 2000; Items 2 & 5 & 7 Form 8-K; August 3, 2000; Items 5 & 7 FORWARD-LOOKING STATEMENTS This Form 10-KSB contains forward-looking statements within meaning of section 27A of the Securities Act of 1933 and section 21E of the Securities Exchange Act of 1934, including statements regarding, among other items, our growth strategies, anticipated trends in our business and our future results of operations, market conditions in the oil and gas industry, the status of and/or future expectations for our offshore properties, our ability to make and integrate acquisitions and the outcome of litigation and the impact of governmental regulation. These forward-looking statements are based largely on our expectations and are subject to a number of risks and uncertainties, many of which are beyond our control. Actual results could differ materially from these forward-looking statements as a result of, among other things: * a decline in oil and/or gas production or prices, * incorrect estimates of required capital expenditures, * increases in the cost of drilling, completion and gas collection or other costs of production and operations, * an inability to meet growth projections, * government regulations, and * other risk factors discussed or not discussed herein. In addition, the words "believe", "may", "will", "estimate", "continue", "anticipate", "intend", "expect" and similar expressions, as they relate to Delta, our business or our management, are intended to identify forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise after the date of this Form 10-KSB. In light of these risks and uncertainties, the forward-looking events and circumstances discussed in this document may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, we have caused this report to be signed on our behalf by the undersigned, who are authorized to do so. (Registrant) DELTA PETROLEUM CORPORATION By (Signature and Title) s/Aleron H. Larson, Jr. Aleron H. Larson, Jr., Secretary, Chairman of the Board, Treasurer and Principal Financial Officer By (Signature and Title) s/Kevin K. Nanke Kevin K. Nanke, Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on our behalf and in the capacities and on the dates indicated. By (Signature and Title) s/Aleron H. Larson, Jr. Aleron H. Larson, Jr., Director Date 08/15/00 By (Signature and Title) s/Roger A. Parker Roger A. Parker, Director Date 08/15/00 By (Signature and Title) s/Terry D. Enright Terry D. Enright, Director Date 08/15/00 By (Signature and Title) s/Jerrie F. Eckelberger Jerrie F. Eckelberger, Director Date 08/15/00 INDEX TO EXHIBITS 2. Plans of Acquisition, Reorganization, Arrangement, Liquidation, or Succession. Not applicable. 3. Articles of Incorporation and By-laws. The Articles of Incorporation and Articles of Amendment to Articles of Incorporation and By-laws of the Registrant were filed as Exhibits 3.1, 3.2, and 3.3, respectively, to the Registrant's Form 10 Registration Statement under the Securities and Exchange Act of 1934, filed September 9, 1987, with the Securities and Exchange Commission and are incorporated herein by reference. 4. Instruments Defining the Rights of Security Holders. Statement of Designation and Determination of Preferences of Series A Convertible Preferred Stock of Delta Petroleum Corporation is incorporated by Reference to Exhibit 28.3 of the Current Report on Form 8-K dated June 15, 1988. Statement of Designation and Determination of Preferences of Series B Convertible Preferred Stock of Delta Petroleum Corporation is incorporated by reference to Exhibit 28.1 of the Current Report on Form 8-K dated August 9, 1989. Statement of Designation and Determination of Preferences of Series C Convertible Preferred Stock of Delta Petroleum Corporation is incorporated by reference to Exhibit 4.1 of the current report on Form 8-K dated June 27, 1996. 9. Voting Trust Agreement. Not applicable. 10. Material Contracts. 10.1 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. 10.2 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. 10.3 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. 10.4 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. 10.5 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. 10.6 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. 10.7 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. 10.8 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. 10.9 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. 10.10 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. 10.11 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. 10.12 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. 10.13 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. 10.14 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. 10.15 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. 10.16 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. 10.17 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. 10.18 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. 10.19 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. 10.20 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. 10.21 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. 10.22 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. 10.23 Promissory Note dated December 1, 1999. Incorporated by reference from Exhibit 10.3 to the Company's Form 8-K dated December 1, 1999. 10.24 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. 10.25 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. 10.26 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. 10.27 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. 10.28 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. 10.29 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. 10.30 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. 10.31 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. 11. Statement Regarding Computation of Per Share Earnings. Not applicable. 12. Statement Regarding Computation of Ratios. Not applicable. 13. Annual Report to Security Holders, Form 10-Q or Quarterly Report to Security Holders. Not applicable. 16. Letter re: Change in Certifying Accountants. Not applicable. 17. Letter re: Director Resignation. Not applicable. 18. Letter Regarding Change in Accounting Principles. Not applicable. 19. Previously Unfiled Documents. Not applicable. 21. Subsidiaries of the Registrant. Not applicable. 22. Published Report Regarding Matters Submitted to Vote of Security Holders. Not applicable. 23. Consent of Experts and Counsel. 23.1 KPMG LLP, filed herewith electronically. 24. Power of Attorney. Not applicable. 27. Financial Data Schedule. Filed herewith electronically. 99. Additional Exhibits. Not applicable. Independent Auditors' Report The Board of Directors and Stockholders Delta Petroleum Corporation: We have audited the accompanying consolidated balance sheets of Delta Petroleum Corporation (the Company) and subsidiary as of June 30, 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 the years then ended, in conformity with generally accepted accounting principles. s/KPMG LLP KPMG LLP Denver, Colorado August 11, 2000 DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS June 30, 2000 and 1999 2000 1999 ASSETS Current Assets: Cash $ 302,414 99,545 Trade accounts receivable, net of allowance for doubtful accounts of $50,000 in 2000 and 1999 613,527 113,841 Accounts receivable - related parties 142,582 116,855 Prepaid assets 373,334 10,000 Other current assets 198,427 100 Total current assets 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 10,809,310 7,369,830 Undeveloped onshore domestic properties 451,795 506,363 Undeveloped foreign properties 623,920 623,920 Developed offshore California properties 3,285,867 - Developed onshore domestic properties 5,154,295 2,231,187 Office furniture and equipment 89,019 82,489 20,414,206 10,813,789 Less accumulated depreciation and depletion (2,538,030) (1,650,228) Net property and equipment 17,876,176 9,163,561 Long term assets: Deferred financing costs 366,996 - Investment in Bion Environmental 228,629 257,180 Partnership net assets 675,185 - Deposit on purchase of oil and gas properties 280,002 1,616,050 Total long term assets 1,550,812 1,873,230 $21,057,272 $11,377,132 2000 1999 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable 1,636,651 393,542 Other accrued liabilities 154,388 10,000 Royalties payable 58,733 127,166 Current portion of long-term debt: Related party - 105,268 Other 1,765,653 - Total current liabilities 3,615,425 635,976 Long-term debt: Related party - 894,732 Other 6,479,115 - Total long-term debt 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 8,422,079 shares in 2000 and 7,913,379 in 1999 84,221 63,903 Additional paid-in capital 33,746,861 29,476,275 Accumulated other comprehensive income (loss) 77,059 (115,395) Accumulated deficit (22,945,409) (19,578,359) Total shareholders' equity 10,962,732 9,846,424 Commitments $21,057,272 $11,377,132 DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF OPERATIONS June 30, 2000 and 1999 2000 1999 Revenue: Oil and gas sales $ 3,355,783 557,507 Gain on sale of oil and gas properties 75,000 957,147 Other revenue 235,198 203,001 Total revenue 3,665,981 1,717,655 Operating expenses: Lease operating expenses 2,405,469 209,438 Depreciation and depletion 887,802 229,292 Exploration expenses 46,730 74,670 Abandoned and impaired properties - 273,041 Dry hole costs - 226,084 General and administrative 1,777,579 1,506,683 Stock option expense 537,708 2,080,923 Total operating expenses 5,655,288 4,600,131 Loss from operations (1,989,307) (2,882,476) Other income and expenses: Interest and financing costs (1,264,954) (19,726) Loss on sale of securities available for sale (112,789) (96,553) Total other income and expenses (1,377,743) (116,279) Net loss $ (3,367,050) $(2,998,755) Net loss per common share-basic and diluted $(0.46) $(0.51) Weighted average of common Shares outstanding 7,271,336 5,854,758 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Consolidated Statement of Stockholders' Equity and Comprehensive Income (Loss) Years Ended June 30, 2000 and 1999 Additional Common Stock paid-in Shares Amount capital Balance, July 1, 1998 5,513,858 $ 55,139 25,571,921 Comprehensive loss: Net loss - - - Other comprehensive loss, net of tax Unrealized loss on equity securities - - - Less: Reclassification adjustment for losses included in net loss - - - Comprehensive loss - - - Stock options granted as compensation - - 2,081,423 Shares issued for cash upon exercise of options 120,000 1,200 158,800 Shares issued for cash 196,444 1,964 354,011 Shares issued for services 10,000 100 15,650 Shares issued for oil and gas properties 250,000 2,500 621,420 Shares issued for deposit on oil and gas properties 300,000 3,000 613,050 Fair value of warrant extended and repriced - - 60,000 Balance, June 30, 1999 6,390,302 63,903 29,476,275 Comprehensive loss: Net loss - - - Other comprehensive gain, net of tax Unrealized gain on equity securities - - - Less: Reclassification adjustment for losses included in net loss - - - Comprehensive loss - - - Stock options granted as compensation - - 500,208 Shares issued for cash 603,000 6,030 1,017,970 Shares issued for cash upon exercise of options 1,048,777 10,488 1,367,048 Shares and options issued with financing 75,000 750 565,472 Shares issued for oil and gas properties 215,000 2,150 547,413 Shares issued for deposit on oil and gas properties 90,000 900 272,475 Balance, June 30, 2000 8,422,079 $ 84,221 33,746,861
Accumulated other comprehensive income Comprehensive Accumulated (loss) loss deficit Total Balance, July 1, 1998 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 Shares issued for cash upon exercise of options - - 160,000 Shares issued for cash - - 355,975 Shares issued for services - - 15,750 Shares issued for oil and gas properties - - 623,920 # Shares issued for deposit on oil and gas properties - - 616,050 Fair value of warrant extended and repriced - - 60,000 Balance, June 30, 1999 (115,395) (19,578,359) 9,846,424 Comprehensive loss: Net loss (3,367,050) ( 3,367,050) (3,367,050) Other comprehensive gain, net of tax Unrealized gain 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 Shares issued for cash - - 1,024,000 Shares issued for cash upon exercise of options - - 1,377,536 Shares and options issued with financing 566,222 Shares issued for oil and gas properties - - 549,563 Shares issued for deposit on oil and gas properties - - 273,375 Balance, June 30, 2000 77,059 (22,945,409) 10,962,732
DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended June 30, 2000 and 1999 2000 1999 Cash flows operating activities: Net loss $ (3,367,050) (2,998,759) Adjustments to reconcile net loss to cash used in operating activities: Gain on sale of oil and gas properties (75,000) (957,147) Loss on sale of securities available for sale 112,789 96,553 Depreciation and depletion 887,802 229,292 Stock option expense 500,208 2,080,923 Amortization of financing costs 466,568 - Abandoned and impaired properties - 273,041 Common stock issued for services - 15,750 Net changes in operating assets and and operating liabilities: (Increase) decrease in trade accounts receivable (533,074) 84,432 (Increase) decrease in accounts receivable from (19,564) 4,397 related parties Increase in prepaid assets (373,334) - (Increase) decrease in other current assets (62,500) - Increase (decrease) in accounts payable trade 1,243,109 (176,927) Increase (decrease) in other accrued liabilities 144,388 - Royalties payable (68,433) (137,154) Net cash used in operating activities (1,144,091) (1,485,599) Cash flows from investing activities: Additions to property and equipment (7,759,804) (507,068) Deposit on purchase of oil and gas properties (6,627) (1,000,000) Proceeds from sale of securities available for sale 135,441 174,602 Proceeds from sale of oil and gas properties 75,000 1,384,000 Increase in long term assets (675,185) - Net cash provided by (used in) investing activities (8,231,175) 51,534 Cash flows from financing activities: Stock issued for cash upon exercise of options 1,377,536 160,000 Issuance of common stock for cash 1,024,000 356,475 Borrowing from related parties - 1,000,000 Repayment of borrowings to related parties (1,000,000) - Proceeds from borrowings 12,816,851 400,000 Repayment of borrowings and financing costs (4,640,252) (400,000) Net cash provided by financing activities 9,578,135 1,516,475 Net increase in cash 202,869 82,410 Cash at beginning of period 99,545 17,135 Cash at end of period $ 302,414 $99,545 Supplemental cash flow information - Cash paid for interest and financing costs $ 741,348 $19,726 Non-cash financing activities: Common stock and options issued for the purchase of oil and gas properties $ 549,563 $683,920 Common stock, options and overriding royalties issued for services relating to debt financing $ 891,223 $ - Common stock issued for deposit on purchase of oil and gas properties $ 273,375 $616,050
DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements June 30, 2000 and 1999 (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 June 30, 2000, 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. Liquidity The Company has incurred losses from operations over the past several years coupled with significant deficiencies in cash flow from operations, for the same period. As of June 30, 2000, the Company had a working capital deficit of $1,925,750. These factors among others may indicate that without increased cash flow from operations, sale of oil and gas properties or additional financing the Company may not be able to meet its obligation in a timely manner. 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 approximately $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 11) 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 basis or acceptable terms. 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 ($11,885,025 at June 30, 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. This 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 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's proved properties were assessed for impairment on an individual field basis and the Company recorded an impairment provision attributable to certain producing properties of $103,230 for the year ended June 30, 1999. The Company's undeveloped properties were assessed for impairment on an individual field basis and the Company recorded an impairment provision attributed to certain undeveloped onshore properties of $169,811 for the year ended June 30, 1999 as management believed that the costs of such properties would likely not be recovered. Gas Balancing The Company uses the sales method of accounting for gas balancing of gas production. Under this method, all proceeds from production credited to the Company are recorded as revenue until such time as the Company has produced its share of the related estimated remaining reserves. Thereafter, additional amounts received are recorded as a liability. As of June 30, 2000, the Company had produced and recognized as revenue approximately 13,000 Mcf more than its entitled share of production. The undiscounted value of this imbalance is approximately $39,000 using the lower of the price received for the natural gas, the current market price or the contract price, as applicable. Royalties Payable Recoupment gas royalties, included in royalties payable, represent estimated royalties due on recoupment gas produced and delivered to the gas purchaser pursuant to the terms of a recoupment agreement. The Company has estimated an amount that may be due to the royalty owners based on the market price of the gas during the period the gas was produced and delivered to the gas purchaser. Royalties payable also include estimated royalties payable on other properties held in suspense. A significant portion of the estimated royalties has not been paid pending a determination of what amounts may have previously been paid by the operator of the properties on behalf of the Company. The statute of limitation has expired for royalty owners to make a claim for a portion of the estimated royalties that had previously been accrued. Accordingly, royalties payable of $68,433 and $137,154 have been written off and recorded as other income in fiscal 2000 and 1999, respectively. Stock Option Plans The Company accounts for its stock option plans in accordance with the provisions of Accounting Principles Board ("APB") Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations. As such, compensation expense was recorded on the date of grant only if the current market price of the underlying stock exceeded the exercise price. 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 share outstanding for the dilutive effect, if any, of convertible preferred stock, stock options and warrant. The effect of potentially dilutive securities outstanding were antidilutive in 2000 and 1999. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Recently Issued Accounting Standards and Pronouncements In 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 Company has not yet assessed the impact, if any, that FIN 44 might have on its 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 16,1 999 and March 15, 2000. The Company has not yet assessed the impact, if any, that SAB 101 might have on its 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 Company has not assessed the impact, if any, that SFAS 133 will have on its financial statements. Reclassification Certain amounts in the 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 $112,789 and $96,553 for the years ended June 30, 2000 and 1999, respectively, on the sales of securities available for sale. The cost and estimated market value of the Company's investment in Bion at June 30, 2000 and 1999 are as follows: Estimated Unrealized Market Cost Gain/(Loss) Value 2000 $151,570 $ 77,059 $228,629 1999 $372,575 $(115,395) $257,180 As of August 1, 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 $225,000. (3) Oil and Gas Properties On November 1, 1999, the Company acquired interests in 11 oil and gas producing properties located in New Mexico and Texas for a cost of $2,879,850. 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), 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 an unrelated entity. The seller is unrelated and will retain its proportionate share of future abandonment liability associated with both the onshore and offshore facilities of the Point Arguello Unit. The acquisition had a purchase price of approximately $6,758,550 consisting of $5,625,000 in cash and 500,000 shares of the Company's restricted common stock with a fair market value of $1,133,500. As part of the agreement, 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. In addition, the agreement provides that if development and operating expenses are greater than production revenues then, at Delta's election, until December 31, 2000, the seller will invest up to $1,000,000 in Delta through the purchase of Delta Preferred Stock to cover excess expenses incurred by Delta. 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 Operating expense $7,284,217 $9,231,546 Net loss $(3,685,786) $(5,109,588) Net loss per common share-basic and diluted $(.51) $(.84) (4) Long Term Debt Other Related Party 2000 1999 2000 1999 A $7,504,306 - - - B 740,462 - - - C - - - 1,000,000 $8,244,768 - - 1,000,000 Current portion 1,765,653 - - 105,268 Long-term portion $6,479,115 $- $- $894,732 A. On December 1, 1999, the Company borrowed $8,000,000 at prime plus 1-1/2% from an unrelated entity. The loan agreement provides for a 4-1/2 year loan with additional compensation to the lender if paid after September 1, 2000. The proceeds from this loan were used to pay off existing debt and the balance of the Point Arguello Unit purchase. The Company is required to make minimum monthly payments 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 Company has assumed the minimum payments of $150,000 per month for the determination of the current portion of long term debt. The loan is collateralized by the Company's oil and gas properties acquired with the loan proceeds to date in the current fiscal year. B. On July 30, 1999, the Company borrowed $2,000,000 at 18% per annum from an unrelated entity which was personally guaranteed by the officers of the Company. On December 1, 1999, the Company paid a portion of the principal and accrued interest leaving a principal balance of $740,462. 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 interest in each property) will be 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. Subsequent to year end, the Company paid off the loan. C. On May 24, 1999, the Company borrowed $1,000,000 at 18% per annum from the Company's officers 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 $29,375 through June 1, 2001 with the remaining principal amount payable at the maturity date. Loan was paid in full during fiscal 1999. D. 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 of each overriding royalty interest of $37,500 was recorded as a deferred financing cost. The Company also paid a 1% origination fee to the lender. (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 June 30, 2000 and 1999, no preferred stock was issued. Common Stock On July 8, 1998, the Company completed a sale of 2,000 shares of the Company's common stock to an unrelated individual for net proceeds to the Company of $6,475. On October 12, 1998, the Company issued 250,000 shares of the Company's common stock and 500,000 options to purchase the Company's common stock at various 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. On December 1, 1998, the Company issued 10,000 shares of the Company's common stock to an unrelated entity for public relation service. On January 1, 1999 and again on January 4, 2000, the Company completed a sale of 194,444 and 175,000 shares, respectively, of the Company's Common stock to another oil company for net proceeds for each issuance to the Company of $350,000. During fiscal 1999, the Company issued 300,000 shares of the Company's common stock to an unrelated entity, along with a $1,000,000 refundable deposit to acquire a portion of an interest in the offshore California Point Arguello Unit, its three platforms (Hidalgo, Harvest, and Hermosa), along with an interest in the adjacent undeveloped Rocky Point Unit. On December 8, 1999, the Company completed the sale of 428,000 shares of the Company's common stock in a private transaction for net proceeds to the Company of $674,000. On June 1, 2000, the Company issued 90,000 shares of the Company's restricted common stock valued at $273,375 to an unrelated entity as a deposit to acquire certain interests in producing properties in Stark County, North Dakota. During fiscal 2000, the Company issued 215,000 shares of the Company's common stock to an unrelated entity as a commission for their involvement with the Point Arguello Unit and New Mexico acquisitions completed during fiscal 2000. The Company received proceeds from the exercise of options to purchase shares of its common stock of $1,377,536 during the year ended June 30, 2000 and $160,000 during the year ended June 30, 1999. Non-Qualified Stock Options Under its 1993 Incentive Plan (the "Incentive Plan") the Company has reserved the greater of 500,000 shares of common stock or 20% of the issued and outstanding shares of common stock of the Company on a fully diluted basis. Incentive awards under the Incentive Plan may include non-qualified or incentive stock options, limited appreciation rights, tandem stock appreciation rights, phantom stock, stock bonuses or cash bonuses. Options issued to date have been non- qualified stock options as defined in the Incentive Plan. A summary of the Plan's stock option activity and related information for the years ended June 30, 2000 and 1999 are as follows: 2000 1999 Weighted-Average Weighted-Average Exercise Exercise Options Price Options Price Outstanding-beginning of year 1,640,163 $1.05 1,162,977 $2.25 Granted 387,500 1.60 477,186 1.43 Exercised (391,777) (.29) - - Repriced - - 2,110,954 .68 Returned for repricing - - (2,110,954) (1.47) Outstanding-end of year 1,635,886 $1.36 1,640,163 $1.05 Exercisable at end of year 1,510,886 $.95 1,385,163 $2.32 Exercise prices for options outstanding under the plan as of June 30, 2000 ranged from $0.05 to $9.75 per share. 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 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, 1999 and 1998, respectively, risk-free interest rate of 5.1% and 5.5%, dividend yields of 0% and 0%, volatility factors of the expected market price of the Company's common stock of 64.03% and 56.07%, and a weighted-average expected life of the options of 6.15 and 6.6 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 and 1999, would have been $3,499,820 and $2,242,507, and basic loss per common share would have been $.45 and $.38 per share, respectively. Non-Qualified Stock Options - Non-Employee In addition to options outstanding under the Company's Incentive Plan, the following options and warrants were outstanding at June 30, 2000: Number Exercise Expiration Outstanding Price Date 20,000 $3.50 06/09/03 25,000 2.13 02/11/01 50,000 6.00 - (1) 50,000 6.00 - (2) 62,500 6.13 11/06/00 100,000 3.00 08/31/04 140,000 2.00 01/03/02 165,000 2.50-4.00 04/01/01 200,000 2.50 04/10/02 250,000 2.00 12/01/04 500,000 3.50-5.00 10/09/03 (1) The 50,000 options granted at $6.00 expire on the later of the original expiration date or one year after registration of the underlying shares. (2) The 50,000 options granted at $6.00 expire on the later of the original expiration date or thirty days after registration of the underlying shares. During fiscal 2000, the Company issued or repriced options to non-employees at or below market. Accordingly, the Company recorded stock option expense in the amount of $475,378 to non-employees. (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 fiscal years ended June 30, 2000 and 1999, the Company contributed $17,565 and $16,631 under the Plan. (7) Income Taxes At June 30, 2000 and 1999, the Company's significant deferred tax assets and liabilities are summarized as follows: 2000 1999 Deferred tax assets: Net operating loss carryforwards $9,591,000 8,163,000 Allowance for doubtful accounts not deductible for tax purposes 19,000 19,000 Oil and gas properties, principally due to differences in basis and depreciation and depletion 555,000 1,058,000 Gross deferred tax assets 10,165,000 9,240,000 Less valuation allowance ( 10,165,000) (9,240,000) Net deferred tax asset $ - $- No income tax benefit has been recorded for the years ended June 30, 2000 and 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. 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 $1,780,166 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. Accounts Receivable Related Parties At June 30, 2000, the Company had $142,582 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. Transaction 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 $29,521 and $23,911 for the years ended June 30, 2000 and 1999, respectively. Transactions with Other Stockholders 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. On December 17, 1998, the Company amended its Purchase and Sale Agreement , to acquire working interests in three proved undeveloped 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, pursuant to 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. 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 conveyance. (9) 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 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 116,142 2002 94,840 2003 12,504 2004 8,336 (10)Disclosures About Capitalized Costs, Cost Incurred and Major Customers Capitalized costs related to oil and gas producing activities are as follows: June 30, June 30, 2000 1999 Undeveloped offshore California properties $10,809,310 7,369,830 Undeveloped onshore domestic properties 451,795 506,363 Undeveloped foreign properties 623,920 623,920 Developed Offshore California Properties 3,285,867 - Developed onshore domestic properties 5,154,295 2,231,187 20,325,187 10,731,300 Accumulated depreciation and depletion (2,457,480) (1,571,705) $17,867,707 $9,159,595 Cost incurred in oil and gas producing activities for the years ended June 30, 2000 and 1999 are as follows: 2000 1999 Onshore Offshore Onshore Offshore Unproved property acquisition costs $ - 3,439,480 1,033,920 - Proved property acquisition costs 2,755,658 2,607,490 16,518 - Development costs 112,882 678,377 140,550 - Exploration costs 32,533 14,197 74,670 - $2,901,073 $6,739,544 $1,265,658 $- A summary of the results of operations for oil and gas producing activities, excluding general and administrative cost, for the years ended June 30, 2000 and 1999 is as follows: 2000 1999 Onshore Offshore Onshore Offshore Revenue: Oil and gas sales 1,198,334 2,157,449 557,503 - Expenses: Lease operating 345,744 2,059,725 209,438 - Depletion 324,849 560,926 229,292 - Exploration 32,533 14,197 74,670 - Abandonment and impaired properties - - 273,041 - Dry hole costs - - 226,084 - Results of operations of oil and gas producing activities $495,208 $(477,399) $(455,022) $- 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 and 1999 were: 2000 1999 A 71% -% B 13% -% C 7% 38% D -% 17% (11) 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 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 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. 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 and 1999 are as follows: Onshore Offshore GAS OIL GAS OIL (MCF) (BBLS) (MCF) (BBLS) 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
Future net cash flows presented below are computed using year-end prices and costs. Future corporate overhead expenses and interest expense have not been included. Onshore Offshore Combined 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
The principal sources of changes in the standardized measure of discounted net cash flows during the years ended June 30, 2000 and 1999 are as follows: 2000 1999 Beginning of year $ 3,352,222 6,562,642 Sales of oil and gas produced during the period, net of production costs (950,314) (348,065) Purchase of reserves in place 21,678,174 - Net change in prices and production costs 2,079,837 (376,526) Changes in estimated future development costs 218,148 891,498 Extensions, discoveries and improved recovery - - Revisions of previous quantity estimates, estimated timing of development and other 413,465 (2,558,107) Sales of reserves in place - (1,475,484) Accretion of discount 335,222 656,264 End of year $ 27,126,754 $3,352,222 (12) Subsequent Events On July 5, 2000, the Company completed the sale of 258,621 shares of its restricted common stock to an unrelated entity for $750,000. A fee of $75,000 was paid and options to purchase 100,000 shares of the Company's common stock at $2.50 per share and 100,000 shares at $3.00 per share for one year were issued to an unrelated individual and entity and as consideration for their efforts and consultation related to the transaction. On July 10, 2000, the Company paid $3,745,000 to acquire interests in producing wells and acreage located in the Eland and Stadium fields in Stark County, North Dakota. The July 10, 2000 payment resulted in the acquisition by the Company of 67% of the ownership interest in each property to be acquired. An optional payment of $1,845,000, less net production revenues accrued from February 1, 2000, is due September 29, 2000 to purchase the remaining ownership interest in each property. 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. On July 21, 2000, Delta and an unrelated entity ("the entity") entered into a definitive agreement entitled "Investment Agreement" whereby the entity has given a firm commitment to allow the Company to issue to the entity up to a total of $20,000,000 of its common stock over three years from time to time as often as monthly in amounts based upon certain market conditions and at prices based upon market prices for the Company common stock at the time of issuance. As consideration the entity has received a warrant to purchase 500,000 shares of the Company common stock at $3.00 per share for five years and may receive additional warrants to purchase the Company common stock under the terms of the Investment Agreement. A warrant to purchase 150,000 shares of the entity common stock at $3.00 per share for five years was issued to an unrelated company as consideration for its efforts and consultation related to potential financing alternatives and this transaction. Proceeds will be used for property acquisitions, debt reduction and working capital.