-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Nw1XD5nyWJYfhHZgDEuz61yrystF3Cmdfrxx0PtJj2UQCYRY3Oh7ZftGNLcVSfln c4Tvon06+hix7ZnQZVmJAw== 0000821483-99-000035.txt : 19991227 0000821483-99-000035.hdr.sgml : 19991227 ACCESSION NUMBER: 0000821483-99-000035 CONFORMED SUBMISSION TYPE: 10KSB PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990630 FILED AS OF DATE: 19990928 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DELTA PETROLEUM CORP/CO CENTRAL INDEX KEY: 0000821483 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 841060803 STATE OF INCORPORATION: CO FISCAL YEAR END: 0630 FILING VALUES: FORM TYPE: 10KSB SEC ACT: SEC FILE NUMBER: 000-16203 FILM NUMBER: 99718872 BUSINESS ADDRESS: STREET 1: 555 17TH ST STE 3310 CITY: DENVER STATE: CO ZIP: 80202 BUSINESS PHONE: 3032939133 MAIL ADDRESS: STREET 1: 555 17TH STREET STREET 2: SUITE 3310 CITY: DENVER STATE: CO ZIP: 80202 10KSB 1 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, 1999. [ ] 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 incorporation or organization) Identification No.) 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, 1999 total $1,717,651. The aggregate market value as of September 15, 1999 of voting stock held by non-affiliates of the registrant was $15,132,592. As of September 15, 1999, 6,653,902 shares of registrant's Common Stock $.01 par value were issued and outstanding. DOCUMENTS INCORPORATED BY REFERENCE: DEFINITIVE PROXY MATERIALS FOR THE 1999 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 24 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 33 ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE 33 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 34 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, 1999, we had varying interests in 72 gross (17.1 net) productive wells located in six states. We have undeveloped properties in five states, and interests in four federal units and one lease offshore California near Santa Barbara. We operate 24 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, 1999, we estimated proved reserves to be approximately 143,000 Bbls of oil and 3.83 Bcf of gas, of which approximately 13,000 Bbls of oil and 2.29 Bcf of gas were proved developed reserves. (See "Description of Property;" Item 2 herein.) At September 15, 1999, 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 6,653,902 shares of common stock were issued and outstanding. We have outstanding warrants and options to purchase 1,054,500 shares of common stock at prices ranging from $1.25 per share to $6.13 per share at September 15, 1999. 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 1,634,063 shares of common stock at prices ranging from $0.05 to $9.75 per share at September 15, 1999. At June 30, 1999, 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 interests in producing oil and gas properties in Oklahoma and 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, 1999, 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 have producing oil and gas interests, undeveloped leasehold interests and related assets in south Texas; interests in undeveloped offshore Federal leases and units near Santa Barbara, California; producing and non-producing interests in the Denver-Julesburg and Piceance Basins of Colorado; the Sacramento Basin of California, the Wind River Basin of Wyoming, the Anadarko Basin in Oklahoma and in the Arkoma Basin in western Arkansas. We intend to continue our emphasis on the drilling of exploratory and development wells primarily in Colorado, California, Texas, Wyoming and Oklahoma. We are in the process of acquiring an interest in a producing offshore Federal unit and an undeveloped offshore Federal unit near Santa Barbara, 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 the purchasers 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 "nonhazardous," 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 wilful 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, 2000. (12) Employees. We have four 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. Currently, we sublease approximately 2,500 square feet to Bion Environmental Technologies, Inc. for $3,575 per month. (b) Oil and Gas Properties. We own interests in oil and gas properties located in California, Colorado, Oklahoma, Texas, Wyoming and elsewhere. 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, 1999, 1998 and 1997. 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%. We sold our interest in a fourth such survey in the area in March of 1998. 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. As of September 15, 1999 leases or options to lease have been acquired within the program areas totaling approximately 3,000 gross acres. Seismic information has been gathered, processed and interpreted on all three surveys. Interpretation of the 90 square miles of seismic information revealed approximately 25 drillable prospects. As of September 15, 1999, 18 wells have been drilled of which nine are now producing and one is waiting on completion. We expect to participate in the drilling of two additional wells during the remainder of fiscal 2000 assuming we have adequate funds. 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 has 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 14,328 net acres in the Piceance Basin in Mesa and Rio Blanco counties, Colorado. We are evaluating the possibility 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 remaining productive lives of 20 to 30 years. During fiscal 1999 we sold interests in 23 wells in Oklahoma for an 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% backin after payout interest in each of the two wells. The first well has been drilled and is producing. The second well was scheduled to be drilled prior to the end of calendar 1997, but has been delayed indefinitely. We will evaluate the results of these first two wells in addition to other factors in making our decisions to participate for our 20% working interest in any subsequent wells. 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 possibility of re-entering one or more of these wells and drilling additional horizontal bores in other untapped zones. Offshore: Offshore Federal Waters: Santa Barbara, California Area Directly and through our subsidiary, Amber Resources Company, we own interests in four 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 1998, 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, 10 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 varies from 2.492% to 15.60%. 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 have a controlling interest in and do not act as the operator of any of the 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 is currently conducting the study under a contract with the MMS. The COOGER study seeks to present a long-term regional perspective of potential onshore constraints that should be considered when developing existing undeveloped offshore leases. COOGER will project the economically recoverable oil and gas production from offshore leases which have not yet been developed. These projections will be utilized to assist in identifying a potential range of scenarios for developing these leases. These scenarios will then be 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. The exact effects upon offshore development of the adoption of any one of the scenarios are not yet capable of analysis because the study has not yet been completed and reviewed. However, we have evaluated our position with regard to the scenarios currently being 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. Although the exact effects upon offshore development are not yet capable of analysis because the study has not yet been completed, it is likely that the adoption of this scenario by governmental decision makers and 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. Although the details of this scenario are not yet available because the study has not been completed, it would appear that this is approximately the scenario that is currently anticipated by our management. 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 potential future production. There is currently insufficient information available to assess the impact of this scenario on us, but it would appear likely that we would incur increased costs and that revenues would be received more quickly. We have also evaluated our position with regard to the scenarios currently being studied with respect to properties located in the northern subregion (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. Although the exact effects upon offshore development are not yet capable of analysis because the study has not yet been completed, it is likely that the adoption of this scenario by governmental decision makers and 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. Although the details of this scenario are not yet available because the study has not been completed, it would appear that this is approximately the scenario that is currently anticipated by our management. 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 allows for a new site(s). There is currently insufficient information available to assess the impact of this scenario on us. 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. This scenario allows for a new site(s). There is currently insufficient information available to assess the impact of this scenario on us, but it would appear likely that we would incur increased costs and that revenues would be received more quickly. Our development plans 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." Current Status. On October 15, 1992 the MMS directed a Suspension of Operations ("SOO") effective January 1, 1993, for the POCS non-producing leases and units, pursuant to CFR 250.110, to enable the lease owners to participate in what became known as the COOGER Study. This allowed the leases to be held under an SOO during the term of the study thereby permitting the owners to cease paying lease payments to the Federal government and suspending the requirements relating to development of these leases during this period. The MMS has extended the SOO from time to time to allow completion of the COOGER Study. Most recently the MMS directed an additional SOO through November 15, 1999 when unit operators are required to have submitted descriptions of their exploration plans for the leases to support their requests for Suspension of Production ("SOP") status for the leases. Each operator has or will submit what the MMS has termed a Schedule of Events for a specific lease or unit that it operates and also a request for an SOP time period to execute the Schedule of Events. In order to carry out the requirements of the MMS, all operators of the units in which we own non-operating interests (described below) are currently engaged in studies to develop a conceptual framework and general timetable for continued delineation and development of the leases. For delineation, the operators will outline the mobile drilling unit well activities, including number and location. For development, the operators' reports will cover the total number of facilities involved, including platforms, pipelines, onshore processing facilities, transportation systems and marketing plans. We are participating with the operators in meeting the MMS schedules through meetings, and consultations and in sharing in the costs as invoiced by the operators. Cost to Develop Offshore California Properties. The cost to develop all of the offshore California properties in which Delta owns an interest, including delineation wells, environmental mitigation, development wells, fixed platforms, fixed platform facilities, pipelines and power cables, onshore facilities and platform removal over the life of the properties (assumed to be 38 years), is estimated to be slightly in excess of $3 billion. Our share of such costs over the life of the properties is estimated to be $216,000,000. 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 its offshore California properties), reduce our ownership interest in the properties through sales of interests in the property or as the result of farm-outs, 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 cost 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 near historic lows, it is likely that development efforts will proceed at a slower pace to the end that costs will be incurred over a more extended period of time. If petroleum prices increase, 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 $45,000,000. The Gato Canyon Unit leases are currently held under a Suspension of Operations until November 15, 1999. Thereafter, the Unit operator intends to carry out a Schedule of Events under a Suspension of Production. The Schedule of Events will include the preparation of an updated Exploration Plan, which 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 Mobil Oil 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 $38,000,000. The Point Sal Unit leases are currently held under a Suspension of Operations until November 15, 1999. Thereafter, the Unit operator intends to carry out a Unit Schedule of Events under a Suspension of Production. The Schedule of Events will include preparation of an updated Exploration Plan which 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 $113,000,000. The Lion Rock Unit and Lease P-0409 are currently held under a Suspension of Operations until November 15, 1999. Thereafter, the Unit operator intends to carry out a Schedule of Events under a Suspension of Production. The Schedule of Events will include 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 $19,300,000. The Sword Unit leases are currently held under a Suspension of Operations until November 15, 1999. Thereafter, the Unit operator intends to carry out a Schedule of Events under a Suspension of Production. Included in the Schedule of Events will be preparation of an updated Exploration Plan which is expected to include plans to drill an additional delineation well. MAP Map depicting Santa Barbara County, California oil and gas facilities in relation to offshore federal units in which the Company owns interests. Acquisition of Interests in the Point Arguello and Rocky Point Units. On June 9, 1999 we announced that we had entered into an agreement which gives us the opportunity to acquire Whiting Petroleum Corporation's ("Whiting") interest in the Point Arguello Unit, with its three platforms (Hidalgo, Harvest, and Hermosa), along with Whiting's interest in the adjacent undeveloped Rocky Point Unit. These properties are also located in Federal waters offshore Santa Barbara, California. Whiting has a 6.07% working interest in the Point Arguello Unit and a 100% working interest in the adjacent OCS Blocks 452 and 453 of the undeveloped Rocky Point Unit. Whiting will retain its proportionate share of future abandonment liability associated with both the onshore and offshore facilities of the Point Arguello Unit. As of August 2, 1999 we had issued 300,000 shares of our common stock and paid Whiting $3,000,000 for 50% of the interest in these properties. We have agreed to pay an additional $3,000,000 by December 1, 1999 for the balance of the interests in these properties. Whiting will retain its proportionate share of future abandonment liability associated with the Point Arguello unit project for both onshore and offshore facilities. The Point Arguello unit platforms are currently producing a combined 22,000 barrels of oil per day. We expect to participate in additional development from the three existing platforms of the Point Arguello unit and in any development of the adjacent undeveloped Rocky Point unit. The effective date of the transfer of these properties under our agreement with Whiting is retroactive to April 1, 1999 after which all revenues and expenses belong to us provided that we pay for and close on the transaction as agreed upon. The purchase price will be adjusted at closing to account for the revenues and expenses from April 1, 1999 to closing. Kazakhstan Acquisition of Exploration Licenses in Kazakhstan. During fiscal year 1999 we acquired two licenses for exploration of approximately 1.9 million acres in the Pavlodar region of Eastern Kazakhstan by agreeing to exchange our common stock and warrants in a private transaction for 100% of Ambir Properties, Inc. ("Ambir"), a private company which held the licenses as its sole asset. The transaction included the exchange of 250,000 shares of restricted Delta common stock and 500,000 warrants to purchase common stock at prices ranging from $3.50 to $5.00 per share. A work plan prepared by Delta was approved by the Kazakhstan government which established minimum work and spending commitments until February 1, 2003. We are in the process of transferring the licenses into the name of Delta and extending 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 may seek other companies in the oil and gas industry to participate in the implementation of the work plan. The acquisition agreement includes a voting agreement under which the officers of Delta, Aleron H. Larson, Jr., Chairman and CEO, and Roger A. Parker, President, vote all shares owned by the selling shareholders of Ambir until December 31, 2002. (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, 1999, 1998 and 1997, 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, 1999 1998 1997 Average sales price: Oil (per barrel) $10.24 16.46 22.36 Natural Gas (per Mcf) $1.97 2.26 2.41 Production costs (per Mcf equivalent) $.73 .67 .85 The profitability of the our oil and gas production activities is affected by the fluctuations in the sale prices of our oil and gas production. (See "Management's Discussion and Analysis or Plan of Operation.") (d) Productive Wells and Acreage. The table below shows, as of June 30, 1999, 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 .0 1,558 1,111 Colorado 8 .8 13 10.3 2,560 2,127 Oklahoma 0 .0 32 2.03 17,120 1,198 California 0 .0 9 1.0 1,200 132 Wyoming 0 .0 6 1.2 960 192 12 2.62 60 14.53 23,398 4,760 (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, 1999, we held undeveloped acreage by state as set forth below: Undeveloped Acres (1) (2) Location Gross Net California, offshore(3) 50,805 4,244 California, onshore 3,000 391 Colorado 16,888 14,265 Wyoming 9,696 1,939 Oklahoma 1,600 112 Total 81,989 20,951 (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, June 30, June 30, 1999 1998 1997 Gross Net Gross Net Gross Net Exploratory Wells(1): Productive: Oil. . . . . . . . . . . . 0 .0 0 .0 0 .0 Gas. . . . . . . . . . . . 4 .44 5 .545 0 .0 Nonproductive. . . . . . . . 7 .77 1 .113 1 1.0 Total. . . . . . . . . . . . 11 1.21 6 .658 1 1.0 Development Wells(1):. Productive: Oil. . . . . . . . . . . . 0 .0 0 .0 0 .0 Gas. . . . . . . . . . . . 0 .0 1 .042 4 .2 Nonproductive. . . . . . . . 0 .0 0 .0 0 .0 Total. . . . . . . . . . . . 0 .0 1 .042 4 .2 Total Wells(1): Productive: Oil. . . . . . . . . . . . 0 .0 0 .0 0 .0 Gas. . . . . . . . . . . . 4 .44 6 .587 4 .2 Nonproductive. . . . . . . . 7 .77 1 .113 1 1.0 Total Wells. . . . . . . . . 11 1.21 7 .700 5 1.2 (1) Does not include wells in which the Company had only a royalty interest. (g) Present Drilling Activity Between July 1, 1999 and September 15, 1999, the Company participated in the drilling of 1 new well on its properties in the Sacramento Basin. The well is successful and will be selling gas within a few weeks. We plan to participate in the drilling of one additional well on these properties during the next 90 days. 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. The operators of the offshore Federal units in which we own interests have each filed Notices of Appeal on behalf of themselves and the co-owners of the various units, including Delta, with the United States Department of Interior of a June 25, 1999 order issued by the Regional Director, Pacific OCS Region, terminating existing Suspensions of Production in effect prior to the present Suspension of Operations. We do not expect that the outcome of any later appeal that might be filed pursuant to the Notice of Appeal will have any material affect upon our property interests because the operators are in the process of requesting new Suspension of Production status for each of the units which, if granted, will replace the existing Suspension of Operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS The 1998 Annual Meeting of the shareholders of the Company was held on June 30, 1999. 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. 5,165,994 63,509 Roger A. Parker 5,165,994 63,509 Jerrie F. Eckelberger 5,165,994 63,509 Terry D. Enright 5,165,994 63,509 At the Annual Meeting the shareholders also voted to ratify, approve and adopt an amendment to the Delta 1993 Incentive Plan, as amended, revising the compensation formula for non-employee directors with 4,979,731 votes in the affirmative, 198,266 votes in the negative, 0 abstentions, and 0 votes withheld for the proposition. Also ratified, approved, and adopted was the appointment of KPMG, LLP for our auditors for the year ended June 30, 1999 with 5,207,376 affirmative votes, 26,505 negative votes, 0 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. 54 Chairman of the Board, May 1987 Chief Executive Officer, to present Secretary, Treasurer, and a Director Roger A. Parker 37 President and May 1987 a Director to present Terry D. Enright 50 Director November 1987 to Present Jerrie F. Eckelberger 55 Director September 1996 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 54, 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 13.8% 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 37, 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 50, 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 55, is an investor, real estate developer and attorney who has practiced law in the State of Colorado for 28 years. He graduated from Northwestern University with a Bachelor of Arts degree in 1966 and received his Juris Doctor degree in 1971 from the University of Colorado School of Law. From 1972 to 1975, Mr. Eckelberger was a staff attorney with the eighteenth Judicial District Attorney's Office in Colorado. From 1982 to 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. There is no family relationship among or between any of the 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 On September 15, 1999, the closing price of the Common Stock was $3.13. (b) Approximate Number of Holders of Common Stock. The number of holders of record of the Company's Common Stock at September 15, 1999 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 does 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 20, 1996, we issued 63,000 shares of common stock to SOCO Offshore, Inc., an affiliate of Snyder Oil Corporation ("SOCO") in exchange for working interests in undeveloped properties offshore Santa Barbara, California. The transaction was recorded at the estimated fair market value of the common stock issued based upon the quoted market price at the time. 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.) ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION Liquidity and Capital Resources. At June 30, 1999 we had a working capital deficit of $295,635 compared to a working capital deficit of $465,854 at June 30, 1998. Our current liabilities include royalties payable of $127,166 at June 30, 1999 which represent our estimate of royalties payable on production attributable to Amber's interest in certain wells in Oklahoma, including production prior to the acquisition of Amber. We believe that the operators of the affected wells have paid some of the royalties on behalf of us and have withheld such amounts from revenues attributable to our interest in the wells. We have contacted the operators of the wells in an attempt to determine what amounts the operators have paid on behalf of us over the past five years, which amounts would reduce the amounts owed by us. To date we have not received information adequate to allow us to determine the amounts paid by the operators. We have been informed by our legal counsel that the applicable statute of limitations period for actions on written contracts arising in the state of Oklahoma is five years. 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, these amounts have been written off and recorded as other income in 1999 and 1998. We believe that it is unlikely that all claims that might be made for payment of royalties payable in suspense or for recoupment royalties payable would be made at one time. Further, Amber, rather than Delta, would be directly liable for payment of any such claims. We believe, although there can be no assurance, that Amber may ultimately be able to settle with potential claimants for less than the amounts recorded for royalties payable. We estimate our capital expenditures for onshore properties to be approximately $1,000,000 for the year ended June 30, 2000. 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. Our working interest share of the future estimated development costs relating to our undeveloped offshore California properties approximates $217 million. No significant amounts are expected to be incurred during fiscal 2000 and $1.0 million and $4.2 million are expected to be incurred during fiscal 2001 and 2002, respectively. 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 its interest. If we were to farmout our interests, our interest in the properties would be decreased substantially. 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. On December 23, 1997, we completed a sale of 156,950 shares of our Common stock to Evergreen Resources, Inc., another oil and gas company, for net proceeds to the Company of $350,000. We received the proceeds from the exercise of options to purchase shares of our common stock of $160,000 and $163,536 during the years ended June 30, 1999 and 1998, 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 an annual interest rate of 18% from our officers maturing on June 1, 2001. We agreed to make monthly principal and interest payments of $29,375 commencing on December 1, 1999 with the remaining principal amount payable at the maturity date. 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 undeveloped properties during the next twelve months. We also expect to raise additional capital for the acquisition of additional oil and gas properties. 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 do not currently have a credit facility with any bank and 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 working capital deficit and our capital requirements for development of our properties, including establishing a credit facility, sale of equity or debt securities and sale of non-strategic 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 believe our existing cash balances, 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, 1999 was $2,998,759 compared to the net loss of $962,003 for the year ended June 30, 1998. The losses for the years ended June 30, 1999 and 1998 were effected by numerous items described in detail below. Revenue. Total revenue for the year ended June 30, 1999 was $1,717,651 compared to $2,211,955 for the year ended June 30, 1998. Oil and gas sales for the year ended June 30, 1999 were $557,503 compared to $1,225,115 for the year ended June 30, 1998. The decrease in oil and gas sales during the year ended June 30, 1999 resulted from the sale of certain properties, which resulted in a gain of $957,147, and the decrease in oil and gas prices during fiscal 1999. Production volumes and average prices received for the years ended June 30, 1999 and 1998 are as follows: 1999 1998 Production: Oil (barrels) 5,574 11,632 Gas (Mcf) 254,291 457,758 Average Price: Oil (per barrel) $10.24 $16.46 Gas (per Mcf) $ 1.97 $ 2.26 Lease Operating Expenses. Lease operating expenses for the year ended June 30, 1999 were $209,438 compared to $349,551 for the year ended June 30, 1998. On an Mcf equivalent basis, production expenses and taxes were $.73 per Mcf equivalent during the year ended June 30, 1999 compared to $.67 per Mcf equivalent for the year ended June 30, 1998. The increase in lease operating costs on an equivalent basis compared to 1998 resulted primarily from the selling of lower operated properties. Depreciation and Depletion Expense. Depreciation and depletion expense for the year ended June 30, 1999 was $229,292 compared to $303,563 for the year ended June 30, 1998. On a Mcf equivalent basis, the depletion rate was $.80 per Mcf equivalent during the year ended June 30, 1999 compared to $.58 per Mcf equivalent for the year ended June 30, 1998. The increase in depreciation and depletion expense is a result of lower average lives on newly drilled wells. Exploration Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals. Exploration expenses were $74,670 for the year ended June 30, 1999 compared to $515,383 for the year ended June 30, 1998. The exploration expenses during fiscal 1998 were abnormally high and primarily represent costs associated with our participation in the shooting of 3-D seismic on prospects in the Sacramento Basin of Northern California. Abandonment and Impairment of Oil and Gas Properties. We recorded an expense for the abandonment and impairment of oil and gas properties for the year ended June 30, 1999 of $273,041 compared to $128,993 in 1998. Our proved properties were assessed for impairment on an individual field basis and we recorded impairment provisions attributable to certain producing properties of $103,230 and $128,993 for the years ended June 30, 1999 and 1998, respectively. The expense in 1999 also includes a provision for impairment of the costs associated with the Sacramento Basin of Northern California of $169,811. We made a determination based on drilling results that it will not be economical to develop certain prospects and as such we will not proceed with these prospects. General and Administrative Expenses. General and administrative expenses for the year ended June 30, 1999 were $1,506,683 compared to $1,433,461 for the year ended June 30, 1997. Stock Option Expense. Stock option expense has been recorded for the years ended June 30, 1999 and 1998 of $2,080,923 and $46,402, respectively, for options granted to certain officers, directors, employees and consultants at option prices below the market price at the date of grant. The most significant amount of the stock option expense for fiscal 1999 can be attributed to a grant by the Incentive Plan Committee ("Committee") of options to purchase 89,686 shares of our common stock and the repricing of 980,477 options to purchase shares of our common stock for the two officers of the Company at a price of $.05 per share under the Incentive Plan. The Committee also repriced 150,000 options to purchase shares of our common stock to two employees at a price of $1.75 per share under the Incentive Plan. Stock option expense of $1,985,414 has been recorded based on the difference between the option price and the quoted market price on the date of grant and repricing of the options. Royalty to Related Party. The royalty to related party represents the $350,000 paid in 1998 pursuant to the terms of the agreement with Ogle to acquire interests in three undeveloped offshore Santa Barbara, California federal oil and gas units. On December 17, 1998, we amended our Purchase and Sale Agreement with Burdette A. Ogle ("Ogle") dated January 3, 1995. As a result of this amended agreement, at the time of each minimum annual payment we will be assigned an interest in three undeveloped offshore Santa Barbara, California, federal oil and gas units proportionate to the total $8,000,000 production payment. Accordingly, the annual $350,000 minimum payment has been recorded as an addition to undeveloped offshore California properties. In addition, pursuant to this agreement, we extended and repriced a previously issued warrant to purchase 100,000 shares of our common stock. The $60,000 fair value placed on the extension and repricing of this warrant was recorded as an addition to undeveloped offshore California properties. As of June 30, 1999, we have paid a total of $1,550,000 in minimum royalty payments. Year 2000 We have completed a review of our computer system and applications (which began in fiscal 1997) to identify the systems that could be affected by the "Year 2000" issue. The Year 2000 problem is the result of computer programs being written using two digits rather than four to define the applicable year. Any of our programs that have time-sensitive software may recognize a date using "00" as the year 1900 rather than the year 2000. This could result in a major system failure or miscalculations. On the basis of our review, we currently believe that the Year 2000 issue will not pose material operational problems for the Company. To our knowledge, after investigation, no "embedded technology" (such as microchips in an electronic control system) of the Company poses a material Year 2000 concern. Because we believe that we have no material internal Year 2000 problems, we have not and do not expect to expend a significant amount of funds to address Year 2000 issues. It is our policy to continue to review our suppliers' Year 2000 compliance and require assurance of Year 2000 compliance from new suppliers; however, such monitoring does not involve a significant cost to us. In addition to the foregoing, we have contacted our major vendors and have received either oral or written assurances from our major vendors or have reviewed assurances contained on vendors' web sites that they have no material Year 2000 problems. We believe that our vendors are largely fungible; therefore, in the event a vendor's representations regarding its Year 2000 compliance were untrue for any reason, we believe that we could find adequate Year 2000-compliant vendors as substitutes. We have also received either oral or written assurances from our customers or have reviewed assurances contained on our customers' web sites that they have no Year 2000 problems which would materially adversely affect the business or operations of the Company. The information contained in this Year 2000 discussion is forward-looking and involves risks and uncertainties that may cause actual results to vary materially from those projected. Some factors that could significantly impact our expected Year 2000 compliance and the estimated cost thereof include internal computer hardware or software problems which have not as yet been identified by us, and currently undisclosed and unanticipated problems which may be encountered by third parties with whom Delta has business relationships. Recently Issued or Proposed Accounting Standards and Pronouncements 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 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. The Financial Accounting Standards Board issued an exposure draft of the proposed interpretation, Accounting for Certain Transactions involving Stock Compensation: an interpretation of APB Opinion 25 on March 31, 1999. The exposure draft addresses outstanding practice issues relating to stock based compensation including but not limited too, option repricing, independent directors and contractors, vesting changes and plan modifications. The exposure draft if adopted as currently released would require prospective adoption for all events subsequent to December 15, 1998. The Company has not completed a full assessment of the impact o the exposure draft on its consolidated financial statement. However, if the exposure draft is adopted as currently released, the Company would be required to account for a signification portion of their stock options outstanding under variable plan accounting and as such a compensation charge would be recognized in the financial statements as the Companies stock price fluctuated. 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 "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 dated October 16, 1998; Items 5 & 7. Form 8-K dated November 23, 1998; Items 2 & 7. Form 8-K dated June 9, 1999; Items 5 & 7. Form 8-K dated August 25, 1999; 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, 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, Controller and Principal Accounting 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 09/27/99 By (Signature and Title) s/Roger A. Parker Roger A. Parker, Director Date 09/27/99 By (Signature and Title) s/Terry D. Enright Terry D. Enright, Director Date 09/27/99 By (Signature and Title) s/Jerrie F. Eckelberger Jerrie F. Eckelberger, Director Date 09/27/99 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 Agreement with Bion Environmental Technologies, Inc. dated June 26, 1995 including an agreement to convert a portion of a promissory note to common stock and a stock voting agreement in favor of the Company's President and Chairman. Incorporated by reference to Exhibit 99.3 to the Company's Form 8-K dated August 18, 1995. 10.10 Agreement with Howard Jenkins dated July 20, 1995 for purchase of warrant. Incorporated by reference to Exhibit 99.6 to the Company's Form 8-K dated August 18, 1995. 10.11 Agreement with LoTayLingKyur, Inc. dated June 29, 1995 relating to note extension and option grant. Incorporated by reference to Exhibit 99.9 to the Company's Form 8-K dated August 18, 1995. 10.12 Copies of Aleron H. Larson, Jr. and Roger A. Parker Employment Agreements, previously filed on Form 10-KSB for the fiscal year ended June 30, 1998. 10.13 Letter agreement (without exhibits) with Slawson Exploration Company, Inc. dated September 30, 1996 for an interest in the West Orion prospect. Incorporated by reference from Exhibit 99.3 to the Company's Form 8-K dated October 10, 1996. 10.14 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. 10.15 Letter agreement (without exhibits) with Slawson Exploration Company, Inc. dated February 10, 1997 for an interest in the Bali prospect. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated March 3, 1997. 10.16 Letter agreement (without exhibits) with Slawson Exploration Company, Inc. dated February 12, 1997 for an interest in the Fiji prospect. Incorporated by reference from Exhibit 99.2 to the Company's Form 8-K dated March 3, 1997. 10.17 Letter agreement (without exhibits) with KCS Resources, Inc., a subsidiary of KCS Energy and doing business as KCS Mountain Resources, Inc. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated April 24, 1997. 10.18 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. 10.19 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. 10.20 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. 10.21 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. 10.22 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. 10.23 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. 10.24 Agreement between Anadarko Minerals, Inc., and Delta Petroleum Corporation dated October 29, 1998. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated November 23, 1998. 10.25 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. 10.26 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. 10.27 Promissory Note dated May 24, 1999. Incorporated by reference from Exhibit 99.2 to the Company's Form 8-K dated June 9, 1999. 10.28 Promissory Note dated July 30, 1999. Incorporated by reference from Exhibit 99.1 to the Company's Form 8-K dated August 25, 1999. 10.29 Guarantee of Payment and Performance of Roger A. Parker dated August 1, 1999. Incorporated by reference from Exhibit 99.2 to the Company's Form 8-K dated August 25, 1999. 10.30 Guarantee of Payment and Performance of Aleron H. Larson, Jr. dated August 1, 1999. Incorporated by reference from Exhibit 99.3 to the Company's Form 8-K dated August 25, 1999. 10.31 Agreement between Delta Petroleum Corporation and Roger A. Parker and Aleron H. Larson, Jr. dated July 30, 1999. Incorporated by reference from Exhibit 99.4 to the Company's Form 8-K dated August 25, 1999. 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 Consent of 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, 1999 and 1998 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, 1999 and 1998 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 September 21, 1999 DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS June 30, 1999 and 1998 1999 1998 ASSETS Current Assets: Cash $ 99,545 17,135 Trade accounts receivable, net of allowance for doubtful accounts of $50,000 in 1999 and 1998 113,841 224,285 Accounts receivable - related parties 116,855 127,415 Other current assets 10,100 10,100 Total current assets 340,341 378,935 Property and Equipment: Oil and gas properties, at cost (using the successful efforts method of accounting) (Note 7 and 9): Undeveloped offshore California properties 7,369,830 6,959,830 Undeveloped onshore domestic properties 506,363 726,127 Undeveloped foreign properties 623,920 - Developed onshore domestic properties 2,231,187 3,369,881 Office furniture and equipment 82,489 80,446 10,813,789 11,136,284 Less accumulated depreciation and depletion (1,650,228) (2,234,525) Net property and equipment 9,163,561 8,901,759 Investment in Bion Environmental 257,180 1,069,149 Deposit on purchase of oil and gas properties 1,616,050 - $11,377,132 10,349,843 1999 1998 LIABILITIES AND STOCKHOLDERS' EQUITY Current Liabilities: Accounts payable trade $ 393,542 570,469 Other accrued liabilities 10,000 10,000 Royalties payable 127,166 264,320 Note payable to related party-current (Note 3) 105,268 - Total current liabilities 635,976 844,789 Note payable to related party (Note 3) 894,732 - Stockholders' Equity (Note 4): Preferred stock, $.10 par value; authorized 3,000,000 shares, none issued - - Common stock, $.01 par value; authorized 300,000,000 shares, issued 6,390,302 shares in 1999 and 5,513,858 shares in 1998 63,903 55,139 Additional paid-in capital 29,476,275 25,571,921 Accumulated other comprehensive income (loss) (Note 2) (115,395) 457,594 Accumulated deficit (19,578,359) (16,579,600) Total stockholders' equity 9,846,424 9,505,054 Commitments (Note 8) $11,377,132 10,349,843 DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF OPERATIONS Years Ended June 30, 1999 and 1998 1999 1998 Revenue: Oil and gas sales $ 557,503 1,225,115 Gain on sale of oil and gas properties 957,147 650,417 Other revenue 203,001 288,083 Total revenue 1,717,651 2,163,615 Operating expenses: Lease operating expenses 209,438 349,551 Depreciation and depletion 229,292 303,563 Exploration expenses 74,670 515,383 Abandoned and impaired properties 273,041 128,993 Dry hole costs 226,084 46,605 Royalty to related party (Note 7) - 350,000 General and administrative 1,506,683 1,433,461 Stock option expense 2,080,923 46,402 Total operating expenses 4,600,131 3,173,958 Loss from operations (2,882,480) (1,010,343) Other income and expenses: Interest expense (19,726) - Gain/(loss) on sale of securities available for sale (96,553) 48,340 Total other income and expenses (116,279) 48,340 Net loss $(2,998,759) (962,003) Basic and diluted loss per common share $ (0.51) (0.18) Weighted average number of common shares outstanding 5,854,758 5,361,900 DELTA PETROLEUM CORPORATION AND SUBSIDIARY Consolidated Statement of Stockholders' Equity Years ended June 30, 1999 and 1998 Additional Common Stock paid-in Shares Amount capital Balance, July 1, 1997 5,230,631 $ 52,306 24,950,128 Comprehensive income: Net loss - - - Other comprehensive income, net of tax Unrealized gain on equity securities - - - Less: Reclassification adjustment for gains included in net loss - - - Comprehensive income - - - Stock options granted as compensation - - 46,402 Shares issued for cash upon exercise of options 114,100 1,141 202,395 Shares issued for cash 156,950 1,570 348,430 Shares issued for services 22,500 225 64,463 Shares reacquired and retired (10,323) (103) (39,897) Balance, June 30, 1998 5,513,858 55,139 25,571,921 Comprehensive income: Net loss - - - Other comprehensive income, net of tax Unrealized loss on equity securities - - - Less: Reclassification adjustment for losses included in net loss - - - Comprehensive income - - - 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 properies 250,000 2,500 621,420 Shares issued for deposit on oil and gas properies 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
Accumulated other comprehensive income Comprehensive Accumulated (loss) Income deficit Total Balance, July 1, 1997 (213,969) (15,617,597) 9,170,868 Comprehensive income: (962,003) (962,003) (962,003) Net loss Other comprehensive income, net of tax Unrealized gain on equity securities 719,903 Less: Reclassification adjustment for gains included in net loss (48,340) 671,563 671,563 Comprehensive income (290,440) Stock options granted as compensation - - 46,402 Shares issued for cash upon exercise of options - - 203,536 Shares issued for cash - - 350,000 Shares issued for services - - 64,688 Shares reacquired and retired - - (40,000) Balance, June 30, 1998 457,594 (16,579,600) 9,505,054 Comprehensive income: Net loss (2,998,759) (2,998,759) (2,998,759) Other comprehensive income, 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 income (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 properies - - 623,920 Shares issued for deposit on oil and gas properies - - 616,050 Fair value of warrant extended and repriced - - 60,000 Balance, June 30, 1999 (115,395) (19,578,359) 9,846,424 DELTA PETROLEUM CORPORATION AND SUBSIDIARY CONSOLIDATED STATEMENTS OF CASH FLOWS Years Ended June 30, 1999 and 1998 1999 1998 Cash flows operating activities: Net loss $(2,998,759) (962,003) Adjustments to reconcile net loss to cash used in operating activities: Gain on sale of oil and gas properties (957,147) (650,417) Write-off royalties payable (137,154) (204,648) (Gain) Loss on sale of securities available for sale 96,553 (48,340) Depreciation and depletion 229,292 303,563 Abandoned and impaired properties 273,041 128,993 Common stock issued for services 15,750 64,688 Stock option expense 2,080,923 46,402 Bad debt expense - 29,754 Net changes in operating assets and and operating liabilities: Decrease in trade accounts receivable 84,432 36,566 Decrease in other current assets - - Decrease in accounts payable trade (176,927) (206,233) Decrease in other accrued liabilities - (11,835) Net cash used in operating activities (1,489,996) (1,473,510) Cash flows from investing activities: Additions to property and equipment (507,068) (628,387) Deposit on purchase of oil and gas properties (1,000,000) - - Proceeds from sale of securities available for sale 174,602 197,012 Proceeds from sale of oil and gas properties 1,384,000 1,023,432 Net cash provided by investing activities 51,534 592,057 Cash flows from financing activities: Stock issued for cash upon exercise of options 160,000 163,536 Issuance of common stock for cash 356,475 350,000 Borrowings from related parties 1,000,000 - Increase in borrowing 400,000 - Payment of borrowing (400,000) - Decrease (increase) in accounts receivable from related parties 4,397 (7,996) Net cash provided by financing activities 1,520,872 505,540 Net increase (decrease) in cash 82,410 (375,913) Cash at beginning of year 17,135 393,048 Cash at end of year $ 99,545 17,135 Supplemental cash flow information - Cash paid for interest $ 19,726 - Non-cash financing activities: Common stock and options issued for oil and gas properties $ 683,920 - Common stock issued for deposit on purchase of oil and gas properties $ 616,050 - See accompanying notes to consolidated financial statements. DELTA PETROLEUM CORPORATION AND SUBSIDIARY Notes to Consolidated Financial Statements June 30, 1999 and 1998 (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 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 owns interests in undeveloped properties in Kazakhstan. At June 30, 1999, 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, 1999, the Company had a working capital deficit of $295,635. 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. 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 unproved properties are assessed periodically 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. 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. Impairment of Long-Lived Assets 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 impairment provisions attributable to certain producing properties of $103,230 and $128,993 for the years ended June 30, 1999 and 1998, respectively. The Company's undeveloped properties were assessed for impairment on an individual field basis and the Company recorded impairment provisions attributed to certain undeveloped onshore properties of $169,811 for the year ended June 30, 1999. Gas Balancing The Company uses the sales method of accounting for gas balancing of gas production. Under this method, all proceeds from production 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, 1999, the Company had produced and recognized as revenue approximately 19,000 Mcf more than its entitled share of production. The undiscounted value of this imbalance is approximately $43,000 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, these amounts have been written off and recorded as other income in 1999 and 1998. Comprehensive Income Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 130, Reporting Comprehensive Income establishes standards for reporting and display of comprehensive income and its components in a full set of general-purpose financial statements. The Company adopted Statement No. 130 effective July 1, 1998 and, accordingly, has reported accumulated other comprehensive income (loss) as a separate line item in the stockholders' equity section of its consolidated balance sheets. 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) attributes 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 dilative effect, if any, of convertible preferred stock, stock options and warrant. The effect of potentially dilative securities outstanding were antidilutive in 1999 and 1998. 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 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 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. Reclassifications Certain amounts in the 1998 financial statements have been reclassified to conform to the 1999 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 1999 and 1998 the Company received an additional 10,249 and 40,747 shares, respectively, of Bion's common stock for rent and other services provided by the Company. The Company realized a loss of $96,553 for the year ended June 30, 1999 and gain of $48,340 for the year ended June 30, 1998 on the sale of securities available for sale. The cost and estimated market value of the Company's investment in Bion at June 30, 1999 and 1998 are as follows: Estimated Unrealized Market Cost Gain/(Loss) Value 1999 $372,575 (115,395) 257,180 1998 611,555 457,594 1,069,149 As of September 15, 1999, the estimated market value of the Company's investment in Bion, based on the quoted bid price of Bion's common stock, was approximately $250,000. (3) Note Payable to Related Party On May 24, 1999, the Company borrowed $1,000,000 at 18% per annum from the Company's officers maturing on June 1, 2001. 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. (4) 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, 1999 and 1998, no preferred stock was issued. Common Stock On December 23, 1997 and again on January 1, 1999, the Company completed a sale of 156,950 and 194,444 shares, respectively, of the Company s Common stock to another oil company for net proceeds for each issuance to the Company of $350,000. 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. During the year ended June 30, 1998, the Company issued 22,500 shares of the Company's common stock to a former employee as a part of a severance package. This transaction was recorded at its estimated fair market value of the common stock issued of approximately $65,000, which was based on the quoted market price of the stock at the time of issuance. The Company also agreed to forgive approximately $20,000 in debt owed to the Company by the former employee. 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. 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. The Company received proceeds from the exercise of options to purchase shares of its common stock of $160,000 during the year ended June 30, 1999 and $163,536 during the year ended June 30, 1998. In addition during the years ended June 30, 1999 and 1998, the Company issued shares of its common stock in exchange for oil and gas properties and for services. 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. 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, 1999 and 1998 are as follows: 1999 1998 Weighted- Weighted- Average Average Exercise Exercise Options Price Options Price Outstanding-beginning of year 1,162,977 $2.25 1,262,077 $3.25 Granted 477,186 1.43 15,000 1.88 Exercised - - (114,100) 1.78 Repriced 2,110,954 .68 1,621,054 2.47 Returned for repricing (2,110,954) (1.47) (1,621,054) (3.27) Outstanding-end of year 1,640,163 $1.05 1,162,977 $2.25 Exercisable at end of year 1,385,163 $2.32 1,132,977 $2.27 Exercise prices for options outstanding under the plan as of June 30, 1999 ranged from $0.05 to $9.75 per share. The weighted-average remaining contractual life of those options is 8.95 years. A summary of the outstanding and exercisable options at June 30, 1999, 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 - $3.25 1,500,163 $0.52 9.07 1,385,163 $0.38 $3.26 - $9.75 140,000 6.74 7.31 - - 1,640,163 $1.05 8.95 1,385,163 $0.38 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 5.5% and 6.0%, dividend yields of 0% and 0%, volatility factors of the expected market price of the Company's common stock of 56.07% and 44.35%, and a weighted- average expected life of the options of 6.6 and 6.0 years. The Company applies APB Opinion 25 and related Interpretations in accounting for its plans. Accordingly, no compensation cost is recognized for options granted at a price equal or greater to the fair market value of the common stock. Had compensation cost for the Company's stock-based compensation plan been determined using the fair value of the options at the grant date, the Company's net loss for the years ended June 30, 1999 and 1998, would have been $2,242,511 and $1,333,745, and basic loss per common share would have been $.38 and $.25 per share, respectively. During the year ended, June 30, 1998, the Company s president exercised options to purchase 32,000 shares of the Company's common stock. Payment for the shares of common stock purchased upon exercise of the option was made in shares of the Company s common stock previously owned by the Company s president, valued at the market price on the date of exercise. The Company recorded the 10,323 shares of the Company s common stock reacquired at cost, which shares were subsequently retired. Stock Options and Warrants In addition to options outstanding under the Company's Incentive Plan, the following options and warrants were outstanding at June 30, 1999: Number Exercise Expiration Outstanding Price Date 7,000 $ 1.25 05/20/00 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 08/31/04 380,000 1.25-5.50 12/31/99 500,000 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. (5) 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, 1999 and 1998, the Company contributed $16,631 and $24,304 under the Plan. (6) Income Taxes At June 30, 1999 and 1998, the Company s significant deferred tax assets and liabilities are summarized as follows: 1999 1998 Deferred tax assets: Net operating loss carryforwards $8,163,000 7,999,000 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 1,058,000 2,206,000 Gross deferred tax assets 9,240,000 10,224,000 Less valuation allowance ( 9,240,000) (10,224,000) Net deferred tax asset $ - - No income tax benefit has been recorded for the years ended June 30, 1999 and 1998 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, 1999, the Company had net operating loss carryforwards for regular and alternative minimum tax purposes of approximately $22,952,000 and $21,552,000. If not utilized, the tax net operating loss carryforwards will expire during the period from 2000 through 2019. If not utilized, approximately $2.4 million of net operating losses will expire over the next five years. Net operating loss carryforwards attributable to Amber prior to 1993 of approximately $2,676,000, 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. (7) Related Party Transactions Transactions with Officers 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 the 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 $89,032. 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, 1999, the Company had $116,855 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 $23,911 and $23,846 for the years ended June 30, 1999 and 1998, respectively. Transactions with Other Stockholders The Company entered into a consulting agreement with Messrs. Burdette A. Ogle and Ronald Heck (collectively "Ogle") effective December 1, 1992 which provides for a monthly fee of $10,000 for a period of five years. The Company has agreed to extend the term of the consulting agreement through December 1, 1999. Effective February 24, 1994, Ogle granted the Company an option to acquire working interests in three proved undeveloped offshore Santa Barbara, California, federal oil and gas units. In August 1994, the Company issued a warrant to Ogle to purchase 100,000 shares of the Company's common stock for five years at a price of $8 per share in consideration of the agreement by Ogle to extend the expiration date of the option to January 3, 1995. On January 3, 1995, the Company exercised the option from Ogle to acquire the working interests in three proved undeveloped offshore Santa Barbara, California, federal oil and gas units. The purchase price of $8,000,000 is represented by a production payment reserved in the documents of Assignment and Conveyance and will be paid out of three percent (3%) of the oil and gas production from the working interests with a requirement for minimum annual payments. Delta paid Ogle $1,200,000 through fiscal 1998 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. Under the terms of the agreement, the Company may reassign the working interests to Ogle upon notice of not more than 14 months nor less than 12 months, thereby releasing the Company of any further obligations to Ogle after the reassignment. On December 17, 1998, the Company amended its Purchase and Sale Agreement with Ogle dated January 3, 1995. As a result of this amended agreement, at the time of each minimum annual payment 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, 1999, the Company has paid a total of $1,550,000 in minimum royalty payments. (8) 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, 1999 and 1998 was approximately $53,000 and $42,000, respectively. Future minimum payments under noncancelable operating leases are as follows: 2000 120,462 2001 116,142 2002 94,840 2003 12,504 2004 8,336 (9) 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, 1999 1998 Undeveloped offshore California properties $7,369,830 6,959,830 Undeveloped onshore domestic properties 506,363 726,127 Undeveloped foreign properties 623,920 - Developed onshore domestic properties 2,231,187 3,369,881 10,731,300 11,055,838 Accumulated depreciation and depletion (1,571,705) (1,311,719) $9,159,595 9,744,119 Cost incurred in oil and gas producing activities for the years ended June 30,1999 and 1998 are as follows: 1999 1998 Unproved property acquisition costs $1,033,920 156,681 Proved property acquisition costs 16,518 40,876 Development costs 140,550 430,830 Exploration costs 74,670 515,383 $1,265,658 1,143,770 A summary of the results of operations for oil and gas producing activities for the years ended June 30, 1999 and 1998 is as follows: 1999 1998 Revenue: Oil and gas sales $ 557,503 1,225,115 Expenses: Lease operating 209,438 349,551 Depletion 229,292 303,563 Exploration 74,670 515,383 Abandoned and impaired properties 273,041 128,993 Dry hole costs 226,084 46,605 Minimum royalty to related party - 350,000 Results of operations of oil and gas producing activities ($455,022) (468,980) Statement of Financial Accounting Standards 131 "Disclosures about segments of an enterprises and Related Information" (SFAS 131) establishes standards for reporting information about operating segments in annual and interim financial statements. SFAS 131 also establishes standards for related disclosures about products and services, geographic areas and major customers. The Company manages its business through one operating segment. The Company's sales of oil and gas to individual customers which exceeded 10% of the Company's total oil and gas sales for the years ended June 30, 1999 and 1998 were: 1999 1998 A 38% 4% B 17% 42% (10) 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 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, 1999 and 1998 are as follows: GAS OIL (MCF) (BBLS) Balance at July 1, 1997 5,417,203 162,812 Extension and discoveries 3,995,565 - Revisions of quantity estimates 1,285,573 (2,364) Sales of properties (807,472) (1,375) Production (457,758) (11,632) Balance at June 30, 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 Proved developed reserves: June 30, 1997 3,419,077 34,176 June 30, 1998 3,905,228 22,273 June 30, 1999 2,289,024 13,140 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. June 30, 1998 Future cash inflows $21,864,136 Future costs: Production 6,341,210 Development 3,058,005 Income taxes - Future net cash flows 12,464,921 10% discount factor 5,902,279 Standardized measure of discounted future net cash flows $6,562,642 June 30, 1999 Future cash inflows $10,147,136 Future costs: Production 3,353,561 Development 1,287,211 Income taxes - Future net cash flows 5,506,364 10% discount factor 2,154,142 Standardized measure of discounted future net cash flows $3,352,222 The principal sources of changes in the standardized measure of discounted net cash flows during the years ended June 30, 1999 and 1998 are as follows: 1999 1998 Beginning of year $6,562,642 4,319,526 Sales of oil and gas produced during the period, net of production costs (348,065) (875,564) Net change in prices and production costs (376,526) (134,318) Changes in estimated future development costs 891,498 628,160 Extensions, discoveries and improved recovery - 2,661,463 Revisions of previous quantity estimates, estimated timing of development and other (2,558,107) 374,627 Sales of reserves in place (1,475,484) (843,205) Accretion of discount 656,264 431,953 End of year $3,352,222 6,562,642 (11) Subsequent Events During the year ended June 30, 1999, the Company entered into an agreement to acquire a 6.07% working interest in the Point Arguello Unit, its three platforms (Hidalgo, Harvest and Hermosa), along with a 100% interest in two of the three leases within the adjacent undeveloped Rocky Point Unit. The unrelated entity will retain its proportionate share of future abandonment liability associated with both the onshore and offshore facilities of the Point Arguello Unit. The agreement called for an initial issuance of 300,000 shares of restricted common stock and a $1,000,000 deposit which the Company completed in the current fiscal year. In addition, the agreement called for $2,000,000 to be paid by August 2, 1999 and the final payment of $3,000,000, net of operating expenses and permitted capital expenditures of the working interest from April 1, 1999, to be paid on or before December 1, 1999. On August 2, 1999, as required by the agreement, the Company paid an additional $2,000,000. Under the agreement, if Delta does not make the final payment of approximately $3,000,000 Delta would, upon closing, acquire an approximate 3.035% net operating interest in the Point Arguello Unit and one half of the sellers working interest in the undeveloped Rocky Point Unit. In addition, the agreement provides that if development and operating expenses are not covered by production revenues then, at Delta's election, until December 21. 2000, the seller will invest up to $2,000,000 in Delta through the purchase of Delta Preferred Stock to cover such costs. The funds used to make the above payment were borrowed at 18% per annum from an unrelated entity which was personally guaranteed by the officers of the Company. The Company agreed to make monthly payments of interest only for the first six months and thereafter, make principle and interest payments of $58,750 until August 1, 2000 at which time the remaining principle and interest is due and payable. As consideration for the guarantee of the Company indebtedness, the Company entered into an agreement with its officers, under which a 1% overriding royalty interest (proportionately reduced to the interest in each property acquired) will be assigned to each of the officers. This agreement also granted the two officers the right, under certain circumstances and at their election, to cause the Company to sell these properties to pay the Company's loans and eliminate the officer's personal liability if the $2,000,000 loan is not repaid.
EX-23.1 2 Consent of Independent Auditors The Board of Directors Delta Petroleum Corporation: We consent to the incorporation by reference in the registration statement No. 33-87106 on Form S-8 of Delta Petroleum Corporation of our report dated September 21, 1999 relating to the consolidated balance sheets of Delta Petroleum Corporation and subsidiary as of June 30, 1999 and 1998, and the related consolidated statements of operations, stockholders equity, and cash flows for the years then ended which report appears in the June 30, 1999 Annual Report on Form 10-KSB of Delta Petroleum Corporation. s/KPMG LLP KPMG LLP Denver, Colorado September 24, 1999 EX-27 3
5 YEAR JUN-30-1999 JUN-30-1999 99,545 0 230,696 50,000 0 340,341 10,813,789 1,650,228 11,377,132 635,976 0 0 0 63,903 9,782,521 11,377,132 557,503 1,717,651 0 4,600,131 0 96,553 19,726 (2,998,759) 0 (2,998,759) 0 0 0 (2,998,759) (.51) (.51)
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