ITEM 1. DESCRIPTION OF BUSINESS
(a) Business Development
Amber Resources Company ("Amber," "we" or "us") is engaged in the exploration, development and production of oil and gas properties. Our business is conducted onshore in the continental United States and in the U.S. coastal waters offshore California. As of June 30, 2002, our principal assets include interests in three undeveloped Federal units located in the Santa Barbara Channel and the Santa Maria Basin offshore California. On July 1, 2001 we sold all of our proved producing properties for $107,044 to Delta Petroleum Corporation ("Delta"). The sale price was calculated at the properties' net present value discounted at 10% (PV10%)as determined by third party, independent engineers. There continue to be uncertainties as to the timing of the development of our offshore properties. (See "Description of Properties"; Item 2
Item 2 herein.)
We were established as a Delaware corporation on January 17, 1978. Our offices are located at Suite 1400, 475 17th Street, Denver, Colorado 80202. As of June 30, 2002, Delta owned 4,277,977 shares (91.68%) of our outstanding common stock. We are managed by Delta under a management agreement effective October 1, 1998 which provides for the sharing of the management between the two companies and allocation of related expenses.
At June 30, 2002, we had an authorized capital of 5,000,000 shares of $0.10 par value preferred stock of which no shares were issued and 25,000,000 shares of $0.0625 common stock of which 4,666,185 shares were issued and outstanding.
(b) Business of Issuer.
During the year ended June 30, 2002, we were engaged in only one industry, namely the acquisition, exploration and development of offshore oil and gas properties and related business activities. Our oil and gas operations now are comprised solely of the development of our offshore interests in undeveloped offshore Federal leases and units near Santa Barbara, California. We have no production and no proved reserves.
(1) Principal Products or Services and Their Markets. Although we do not currently have any production, we anticipate that the principal products to be produced by us will be crude oil and natural gas. It is anticipated that these products will be generally sold at the wellhead to purchasers in the immediate area where the product would be 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. We do not currently have any oil or gas production. Generally, when a company does have production, oil is picked up and transported by the purchaser from the wellhead. In some instances a fee is charged for the cost of transporting the oil, which fee is deducted from or accounted for in the price paid for the oil. Natural gas wells are connected to pipelines generally owned by the natural gas purchasers. A variety of pipeline transportation charges are usually included in the calculation of the price paid for the natural gas.
(3) Status of Any Publicly Announced New Product or Service. We have not made a public announcement of, and no information has otherwise become public about, a new product or industry segment requiring the investment of a material amount of our total assets.
(4) Competitive Business Conditions. Oil and gas exploration and development 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. The loss of any customer would not have a material adverse effect on our business because of the availability of alternative customers and the marketability of the oil and gas in the regions where our undeveloped properties are located. We currently do not have any oil or gas production and consequently we do not currently have any customers.
(7) Patents, Trademarks, Licenses, Franchises, Concessions, Royalty Agreements and 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. Governmental approval, however, has been a major impediment to the development of our undeveloped properties.
(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.
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 participate, we are subject to numerous federal, state, and local environmental laws and regulations concerning our oil and gas operations, products and other activities. In particular, these laws and regulations require the acquisition of permits, restrict the type, quantities, and concentration of various substances that can be released into the environment, limit or prohibit activities on certain lands lying within wilderness, wetlands and other protected areas, regulate the generation, handling, storage, transportation, disposal and treatment of waste materials and impose criminal or civil liabilities for pollution resulting from oil, natural gas and petrochemical operations.
Governmental approvals and permits are currently, and may in the future be, required in connection with our operations. The duration and success of obtaining such approvals are contingent upon a significant number of variables, many of which are not within our control. To the extent such approvals are required and not obtained, operations may be delayed or curtailed, or we may be prohibited from proceeding with planned exploration or development.
Environmental laws and regulations are expected to have an increasing impact on our operations, although it is impossible to predict accurately the effect of future developments in such laws and regulations on our future earnings and operations. Some risk of environmental costs and liabilities is inherent in our operations and products, as it is with other companies engaged in similar businesses, and there can be no assurance that material costs and liabilities will not be incurred. However, we do not currently expect any material adverse effect upon our results of operations or financial position as a result of compliance with such laws and regulations.
Although future environmental obligations are not expected to have a material adverse effect on our results of operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur substantial environmental liabilities or costs.
Hazardous Substances and Waste Disposal. ---------------------------------------
We do not currently own or lease any interests in any producing properties. It is possible, however, that we might acquire interests in producing properties or that some of our non-producing properties may become productive in the future. 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 sites where hydrocarbons or other waste is found to have been disposed of or released on or under their properties. The Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the management and disposal of wastes.
Although CERCLA currently excludes petroleum from cleanup liability, many state laws affecting our operations impose clean-up liability regarding petroleum and petroleum related products.
In addition, although RCRA currently classifies certain exploration and production wastes as "non-hazardous," such wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. If such a change in legislation were to be enacted, it could have a significant impact on our operating costs, as well as the gas and oil industry in general.
Oil Spills. ----------
Under the Federal Oil Pollution Act of 1990, as amended ("OPA"), (i) owners and operators of onshore facilities and pipelines, (ii) lessees or permittees of an area in which an offshore facility is located and (iii) owners and operators of tank vessels ("Responsible Parties") are strictly liable on a joint and several basis for removal costs and damages that result from a discharge of oil into the navigable waters of the United States. These damages include, for example, natural resource damages, real and personal property damages and economic losses. OPA limits the strict liability of Responsible Parties for removal costs and damages that result from a discharge of oil to $350 million in the case of onshore facilities, $75 million plus removal costs in the case of offshore facilities, and in the case of tank vessels, an amount based on gross tonnage of the vessel. However, these limits do not apply if the discharge was caused by gross negligence or willful misconduct, or by the violation of an applicable Federal safety, construction or operating regulation by the Responsible Party, its agent or subcontractor or in certain other circumstances.
In addition, with respect to certain offshore facilities, OPA requires evidence of financial responsibility in an amount of up to $150 million. Tank vessels must provide such evidence in an amount based on the gross tonnage of the vessel. Failure to comply with these requirements or failure to cooperate during a spill event may subject a Responsible Party to civil or criminal enforcement actions and penalties.
The operators of our undeveloped offshore California properties will be primarily liable for oil spills and are required by the MMS to carry certain types of insurance and to post bonds in that regard. We are generally liable for oil spills as a non-operating working interest owner.
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. Our leases are undeveloped and currently pose no liability for pollution damages.
(10) Research and Development. We do not engage in any research and development activities. Since its inception, Amber 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 the business of acquiring, operating, exploring for and developing natural resources, we are subject to various state and local provisions regarding environmental and ecological matters. Therefore, compliance with environmental laws may necessitate significant capital outlays, may materially affect our earnings potential, and could cause material changes in our proposed business. At the present time, however, these laws do not materially hinder nor adversely affect our business. Capital expenditures relating to environmental control facilities have not been material to the operation of Amber since its inception. In addition, we do not anticipate that such expenditures will be material during the fiscal year ending June 30, 2003.
(12) Employees. We have no full time employees.
ITEM 2. PROPERTIES
(a) Office Facilities:
We share offices with Delta under a management agreement with Delta. Under this agreement, we pay Delta a quarterly management fee of $25,000 for our share of rent, secretarial and administrative, accounting and management services of Delta's officers and employees.
(b) Oil and Gas Properties
We own interests in undeveloped offshore Federal leases and units located near Santa Barbara, California. We sold all of our onshore producing properties to Delta on July 1, 2001. As such, no oil and gas revenues were recorded during fiscal 2002. We did not file oil and gas reserve estimates with any Federal authority or agency other than the SEC during the years ended June 30, 2001 and 2000. No reserves estimates were prepared for the year ended June 30, 2002 as all remaining leases are undeveloped.
Offshore Federal Waters: Santa Barbara, California Area -------------------------------------------------------
We own interests in three undeveloped federal units located in federal waters offshore California near Santa Barbara.
The Santa Barbara Channel and the offshore Santa Maria Basin are the seaward portions of geologically well-known onshore basins with over 90 years of production history. These offshore areas were first explored in the Santa Barbara Channel along the near shore three mile strip controlled by the state. New field discoveries in Pliocene and Miocene age reservoir sands led to exploration into the federally controlled waters of the Pacific Outer Continental Shelf ("POCS"). Although significant quantities of oil and gas have been produced and sold from drilling conducted on POCS leases between 1966 and 1989, we do not, however, own any interest in any offshore California production and there is no assurance that any of our undeveloped properties will ever achieve production.
Most of the early offshore production was from Pliocene age sandstone reservoirs. The more recent developments are from the highly fractured zones of the Miocene age Monterey Formation. The Monterey is productive in both the Santa Barbara Channel and the offshore Santa Maria Basin. It is the principal producing horizon in the Point Arguello field, the Point Pedernales field, and the Hondo and Pescado fields in the Santa Ynez Unit. Because the Monterey is capable of relatively high productive rates, the Hondo field, which has been on production since late 1981, has already surpassed 224 million Bbls of oil production and 411 Bcf of gas production. All told, offshore fields producing from the Monterey as of the end of calendar 2000 have produced 526 million Bbls of oil and 544 Bcf of gas.
California's active tectonic history over the last few million years has formed the large linear anticlinal features which trap the oil and gas. Marine seismic surveys have been used to locate and define these structures offshore. Recent seismic surveying utilizing modern 3-D seismic technology, coupled with exploratory well data, has greatly improved knowledge of the size of reserves in fields under development and in fields for which development is planned. Currently, 11 fields are producing from 18 platforms in the Santa Barbara Channel and offshore Santa Maria Basin. Implementation of extended high-angle to horizontal drilling methods is reducing the number of platforms and wells needed to develop reserves in the area. Use of these new drilling methods and seismic technologies is expected to continue to improve development economics.
Leasing, lease administration, development and production within the Federal POCS all fall under the Code of Federal Regulations administered by the MMS. The EPA controls disposal of effluents, such as drilling fluids and produced waters. Other Federal agencies, including the Coast Guard and the 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 three units in which we own interests are located in the POCS seaward of the three mile limit, leasing, drilling, and development of these units are not directly regulated by the State of California. However, to the extent that any production is transported to an on-shore facility through the state waters, our pipelines (or other transportation facilities) would be subject to California state regulations. Construction and operation of any such pipelines would require permits from the state. Additionally, all development plans must be consistent with the Federal Coastal Zone Management Act ("CZMA"). In California the decision of CZMA consistency is made by the California Coastal Commission.
The Santa Barbara County Energy Division and the Board of Supervisors will have a significant impact on the method and timing of any offshore field development through its permitting and regulatory authority over the construction and operation of on-shore facilities. In addition, the Santa Barbara County Air Pollution Control District has authority in the federal waters off Santa Barbara County through the Federal Clean Air Act as amended in 1990.
Each working interest owner will be required to pay its proportionate share of these costs based upon the amount of the interest that it owns. The size of our working interest in these units varies from .87% to 6.97%. We may be required to farm out all or a portion of our interests in these properties to a third party if we cannot fund our share of the development costs. There can be no assurance that we can farm out our interests on acceptable terms.
These units have been formally approved and are regulated by the MMS. While the Federal Government has recently attempted to expedite the process of obtaining permits and authorizations necessary to develop the properties, there can be no assurance that it will be successful in doing so.
We do not act as operator of any offshore California properties and consequently will not generally control the timing of either the development of the properties or the expenditures for development unless we choose to unilaterally propose the drilling of wells under the relevant operating agreements.
The MMS initiated the California Offshore Oil and Gas Energy Resources (COOGER) Study at the request of the local regulatory agencies of the three counties (Ventura, Santa Barbara and San Luis Obispo) affected by offshore oil and gas development. A private consulting firm completed the study under a contract with the MMS. The COOGER Study presents a long-term regional perspective of potential onshore constraints that should be considered when developing existing undeveloped offshore leases. The COOGER Study projects the economically recoverable oil and gas production from offshore leases which have not yet been developed. These projections are utilized to assist in identifying a potential range of scenarios for developing these leases. These scenarios are compared to the projected infrastructural, environmental and socioeconomic baselines between 1995 and 2015.
No specific decisions regarding levels of offshore oil and gas development or individual projects will occur in connection with the COOGER Study. Information presented in the study is intended to be utilized as a reference document to provide the public, decision makers and industry with a broad overview of cumulative industry activities and key issues associated with a range of development scenarios. We have attempted to evaluate the scenarios that were studied with respect to properties located in the eastern and central subregions (which include the Sword Unit and the Gato Canyon Unit) and the results of such evaluation are set forth below:
Scenario 1 No new development of existing offshore leases. If this scenario were ultimately to be adopted by governmental decision makers as the proper course of action for development, our offshore California properties would in all likelihood have little or no value. In this scenario we would seek to cause the Federal government to reimburse us for all money spent by us and our predecessors for leasing and other costs and for the value of the oil and gas reserves found on the leases through our exploration activities and those of our predecessors.
Scenario 2 Development of existing leases, using existing onshore facilities as currently permitted, constructed and operated (whichever is less) without additional capacity. This scenario includes modifications to allow processing and transportation of oil and natural gas with different qualities. It is likely that the adoption of this scenario by the industry as the proper course of action for development would result in lower than anticipated costs, but would cause the subject properties to be developed over a significantly extended period of time.
Scenario 3 Development of existing leases, using existing onshore facilities by constructing additional capacity at existing sites to handle expanded production. This scenario is currently anticipated by our management to be the most reasonable course of action although there is no assurance that this scenario will be adopted.
Scenario 4 Development of existing leases after decommissioning and removal of some or all existing onshore facilities. This scenario includes new facilities, and perhaps new sites, to handle anticipated future production. Under this scenario we would incur increased costs but that revenues would be received more quickly.
We have also evaluated our position with regard to the scenarios with respect to properties located in the northern sub-region (which includes the Lion Rock Unit), the results of which are as follows:
Scenario 1 No new development of existing offshore leases. If this scenario were ultimately to be adopted by governmental decision-makers as the proper course of action for development, our offshore California properties would in all likelihood have little or no value. In this scenario we would seek to cause the Federal government to reimburse us for all money spent by us and our predecessors for leasing and other costs and for the value of the oil and gas reserves found on the leases through our exploration activities and those of our predecessors.
Scenario 2 Development of existing leases, using existing onshore facilities as currently permitted, constructed and operated (whichever is less) without additional capacity. This scenario includes modifications to allow processing and transportation of oil and natural gas with different qualities. It is likely that the adoption of this scenario by the industry as the proper course of action for development would result in lower than anticipated costs, but would cause the subject properties to be developed over a significantly extended period of time.
Scenario 3 Development of existing leases, using existing onshore facilities by constructing additional capacity at existing sites to handle expanded production. This scenario that is currently anticipated by our management to be the most reasonable course of action although there is no assurance that this scenario will be adopted.
Scenario 4 Development of existing offshore leases, using existing onshore facilities with additional capacity or adding new facilities to handle a relatively low rate of expanded development. This scenario is similar to #3 above but would entail increased costs for any new facilities.
Scenario 5 Development of existing offshore leases, using existing onshore facilities with additional capacity or adding new facilities to handle a relatively higher rate of expanded development. Under this scenario we would incur increased costs but revenues would be received more quickly.
The development plans for the various units (which have been submitted to the MMS for review) currently provide for 22 wells from one platform set in a water depth of approximately 300 feet for the Gato Canyon Unit; 63 wells from one platform set in a water depth of approximately 1,100 feet for the Sword Unit; and 183 wells from two platforms for the Lion Rock Unit (in which we own only a 1% net profits interest and do not own any working interest).
On the Lion Rock Unit, Platform A would be set in a water depth of approximately 507 feet, and Platform B would be set in a water depth of approximately 484 feet. The reach of the deviated wells from each platform required to drain each unit falls within the reach limits now considered to be "state-of-the-art." The development plans for the Rocky Point Unit provide for the inclusion of the Rocky Point leases in the Point Arguello Unit upon which the Rocky Point leases would be drilled from existing Point Arguello platforms with extended reach drilling technology. The approximate distances required to drain the Rocky Point leases range from 2,276 feet to 13,999 feet at proposed total vertical depths ranging from 6,620 feet to 7,360 feet.
Current Status. On October 15, 1992 the MMS directed a Suspension of Operations (SOO), effective January 1, 1993, for the POCS undeveloped leases and units. The SOO was directed for the purpose of preparing what became known as the COOGER Study. Two-thirds of the cost of the Study was funded by the participating companies in lieu of the payment of rentals on the leases. Additionally, all operations were suspended on the leases during this period. On November 12, 1999, as the COOGER Study drew to a conclusion, the MMS approved requests made by the operating companies for a Suspension of Production (SOP) status for the POCS leases and units. During the period of a SOP, the lease rentals resume and each operator is generally required to perform exploration and development activities in order to meet certain milestones set out by the MMS. The milestones that were established by the MMS for the properties in which we own an interest were established through negotiations by the MMS on behalf of the United States government and the operators on behalf of the working interest owners. We did not directly participate in these negotiations. Until recently, progress toward the milestones was monitored by the operator in quarterly reports submitted to the MMS. In February 2000 all operators completed and timely submitted to the MMS a preliminary "Description of the Proposed Project". This was the first milestone required under the SOP. Quarterly reports were also prepared and submitted for all the subsequent quarters.
On June 22, 2001, however, a Federal Court in the case of California v. Norton, et al (discussed below) ordered the MMS to set aside its approval of the suspensions of our offshore leases and to direct suspensions, including all milestone activities, for a time sufficient for the MMS to provide the State of California with a consistency determination under federal law. As a result of this order, on July 2, 2001 the MMS directed suspensions of operations for all of our offshore California leases for an indefinite period of time and suspended all of the related milestones. The ultimate outcome and effects of this litigation are not certain at the present time. To continue to carry out the requirements of the MMS, all operators of the units in which we own non-operating interests are prepared to meet the next milestone leading to development of the leases, but the status of the milestones is presently uncertain in light of the Norton ruling. The United States government has filed a notice of its intent to appeal the court's order in the Norton case.
On January 9, 2002, we and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of forty undeveloped federal leases, some of which are part of our Offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their Offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case that a 1990 amendment to the Coastal Zone Management Act required the Government to make a consistency determination prior to granting lease suspension requests in 1999 constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations.
The forty undeveloped leases are located in the Offshore Santa Maria Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the Santa Barbara Channel off Santa Barbara and Ventura counties. None of these leases is currently impaired, but in the event that there is some future adverse ruling by the California Coastal Commission under the Coastal Zone Management Act and we decide not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear our appeal of any such ruling or ultimately makes a determination adverse to us, it is likely that some or all of these leases would become impaired and written off at that time.
In addition, it should be noted that our pending litigation against the United States is predicated on the ruling of the lower court in California v. Norton. The United States has appealed the decision of the lower court to the 9th Circuit Court of Appeals. In the event that the United States is not successful in its appeal(s) of the lower court's decision in the Norton case and the pending litigation with us is not settled, it would be necessary for us to reevaluate whether the leases should be considered impaired at that time.
As the ruling in the Norton case currently stands, the United States has been ordered to make a consistency determination under the Coastal Zone Management Act, but the leases are still valid. If through the appellate process the leases are found not to be valid for some reason, or if the United States is finally ordered to make a consistency determination and either does not do so or finds that development is inconsistent with the Coastal Zone Management Act, it would appear that the leases would become impaired even though we would undoubtedly proceed with our litigation. It is also possible that other events could occur during the appellate process that would cause the leases to become impaired, and we will continuously evaluate those factors as they occur.
The suit seeks compensation for the lease bonuses and rentals paid to the Federal Government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. In addition, our claim for exploration costs and related expenses will also be substantial.
On May 18, 2001 (prior to the Norton decision), a revised Development and Production Plan for the Point Arguello Unit was submitted to the MMS and the California Coastal Commission ("CCC") for approval. If approved by the CCC, this plan would enable development of the Rocky Point Unit from the Point Arguello platforms that are already in existence.
Under law, the CCC is typically required to make a determination as to whether or not the Plan is "consistent" with California's Coastal Plan within three months of submission, with a maximum of three months' extension (a total of six months). By correspondence dated August 7, 2001, however, the Unit operator requested that the CCC suspend the consistency review for the revised Development and Production Plan since the MMS had temporarily stopped work on the processing of the plan as the result of the Norton decision.
Although it currently appears likely that the CCC may require some additional supplemental information to be provided with respect to some aspects of air and water quality when its review continues, we believe that the Rocky Point Development and Production Plan that was submitted meets the requirements established by applicable federal regulations. In accordance with these regulations, the Plan includes very specific information regarding the planned activities, including a description of and schedule for the development and production activities to be performed, including plan commencement date, date of first production, total time to complete all development and production activities, and dates and sequences for drilling wells and installing facilities and equipment, and a description of the drilling vessels, platforms, pipelines and other facilities and operations located offshore which are proposed or known by the lessee (whether or not owned or operated by the lessee) to be directly related to the proposed development, including the location, size, design, and important safety, pollution prevention, and environmental monitoring features of the facilities and operations. The current Development and Production Plan calls for drilling activities to be conducted from the existing Point Arguello platforms using extended reach drilling techniques with oil and gas production to be transported through existing pipelines to existing onshore production facilities. The plan does not require the construction of new platforms, pipelines or production facilities.
In accordance with applicable federal regulations, the following supporting information accompanies the Development and Production Plan: (1) geological and geophysical data and information, including: (i) a plat showing the surface location of any proposed fixed structure or well; (ii) a plat showing the surface and bottomhole locations and giving the measured and true vertical depths for each proposed well; (iii) current interpretations of relevant geological and geophysical data; (iv) current structure maps showing the surface and bottomhole location of each proposed well and the depths of expected productive formations; (v) interpreted structure sections showing the depths of expected productive formations; (vi) a bathymetric map showing surface locations of fixed structures and wells or a table of water depths at each proposed site; and (vii) a discussion of seafloor conditions including a shallow hazards analysis for proposed drilling and platform sites and pipeline routes.
As required by federal regulations, the information contained in the Plan contains proposed precautionary measures, including a classification of the lease area, a contingency plan, a description of the environmental safeguards to be implemented, including an updated oil-spill response plan; and a discussion of the steps that have been or will be taken to satisfy the conditions of lease stipulations, a description of technology and reservoir engineering practices intended to increase the ultimate recovery of oil and gas, i.e., secondary, tertiary, or other enhanced recovery practices; a description of technology and recovery practices and procedures intended to assure optimum recovery of oil and gas; a discussion of the proposed drilling and completion programs; a detailed description of new or unusual technology to be employed; and a brief description of the location, description, and size of any offshore and land-based operations to be conducted or contracted for as a result of the proposed activity; including the acreage required in California for facilities, rights-of-way, and easements, the means proposed for transportation of oil and gas to shore; the routes to be followed by each mode of transportation; and the estimated quantities of oil and gas to be moved along such routes; an estimate of the frequency of boat and aircraft departures and arrivals, the onshore location of terminals, and the normal routes for each mode of transportation.
As required, the Plan also provides a list of the proposed drilling fluids, including components and their chemical compositions, information on the projected amounts and rates of drilling fluid and cuttings discharges, and methods of disposal, and specifies the quantities, types, and plans for disposal of other solid and liquid wastes and pollutants likely to be generated by offshore, onshore, and transport operations and, regarding any wastes which may require onshore disposal, the means of transportation to be used to bring the wastes to shore, disposal methods to be utilized, and the location of onshore waste disposal or treatment facilities.
In order to comply with federal regulations, the Plan also addresses the approximate number of people and families to be added to the population of local nearshore areas as a result of the planned development, provides an estimate of significant quantities of energy and resources to be used or consumed including electricity, water, oil and gas, diesel fuel, aggregate, or other supplies which may be purchased within California, and specifies the types of contractors or vendors which will be needed, although not specifically identified, and which may place a demand on local goods and services.
The Plan also identifies the source, composition, frequency, and duration of emissions of air pollutants and provides a narrative description of the existing environment with an emphasis placed on those environmental values that may be affected by the proposed action. This section of the Plan contains a description of the physical environment of the area covered by the Plan and includes data and information obtained or developed by the lessee together with other pertinent information and data available to the lessee from other sources. The environmental information and data includes a description of the aquatic biota, including fishery and marine mammal use of the lease, the significance of the lease and identifies the threatened and endangered species and their critical habitat.
The Plan also addresses environmentally sensitive areas (e.g., refuges, preserves, sanctuaries, rookeries, calving grounds, coastal habitats, beaches, and areas of particular environmental concern) which may be affected by the proposed activities, the predevelopment, ambient water-column quality and temperature data for incremental depths for the areas encompassed by the plan, the physical oceanography, including ocean currents described as to prevailing direction, seasonal variations, and variations at different water depths in the lease, and describes historic weather patterns and other meteorological conditions, including storm frequency and magnitude, wave height and direction, wind direction and velocity, air temperature, visibility, freezing and icing conditions, and ambient air quality listing, where possible, the means and extremes of each.
The Plan further identifies other uses of the area, including military use for national security or defense, subsistence hunting and fishing, commercial fishing, recreation, shipping, and other mineral exploration or development and describes the existing and planned monitoring systems that are measuring or will measure impacts of activities on the environment in the planning area. As required, the Plan provides an assessment of the effects on the environment expected to occur as a result of implementation of the Plan, and identifies specific and cumulative impacts that may occur both onshore and offshore, and describes the measures proposed to mitigate these impacts. These impacts are quantified to the fullest extent possible including magnitude and duration and are accumulated for all activities for each of the major elements of the environment (e.g., water and biota). The Plan also provides a discussion of alternatives to the activities proposed that were considered during the development of the Plan, including a comparison of the environmental effects.
As required, the Plan provides certain supporting information with respect to the projected emissions from each proposed or modified facility for each year of operation and the bases for all calculations, including, for each source, the amount of the emission by air pollutant expressed in tons per year and frequency and duration of emissions; for each proposed facility, the total amount of emissions by air pollutant expressed in tons per year, the frequency distribution of total emissions by air pollutant expressed in pounds per day and, in addition for a modified facility only, the incremental amount of total emissions by air pollutant resulting from the new or modified source(s); and a detailed description of all processes, processing equipment and storage units, including information on fuels to be burned; and a schematic drawing which identifies the location and elevation of each source.
In order to continue to carry out the requirements of the MMS when they resume, all operators of the units in which we own non-operating interests are prepared to complete any studies and project planning necessary to commence development of the leases. Where additional drilling is needed, the operators will bring a mobile drilling unit to the POCS to further delineate the undeveloped oil and gas fields.
Cost to Develop Offshore California Properties. The cost to develop all of the offshore California properties in which we own an interest, including delineation wells, environmental mitigation, development wells, fixed platforms, fixed platform facilities, pipelines and power cables, onshore facilities and platform removal over the life of the properties (assumed to be 38 years), is estimated to be slightly in excess of $3 billion. Our share of such costs over the life of the properties is estimated to be approximately $27,000,000.
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 our offshore California properties), reduce our ownership interest in the properties through sales of interests in the property or as the result of farmouts, industry financing arrangements or other partnership or joint venture relationships, or to enter into various transactions which will result in some combination of the foregoing. In the event that we are not able to pay our share of expenses as a working interest owner as required by the respective operating agreements, it is possible that we might lose some portion of our ownership interest in the properties under some circumstances, or that we might be subject to penalties which would result in the forfeiture of substantial revenues from the properties.
While the costs to develop the offshore California properties in which we own an interest are anticipated to be substantial in relation to our small size, management believes that the opportunities for us to increase our asset base and ultimately improve our cash flow are also substantial in relation to our size. Although there are several factors to be considered in connection with our plans to obtain funding from outside sources as necessary to pay our proportionate share of the costs associated with developing our offshore properties (not the least of which is the possibility that prices for petroleum products could decline in the future to a point at which development of the properties is no longer economically feasible), we believe that the timing and rate of development in the future will in large part be motivated by the prices paid for petroleum products.
To the extent that prices for petroleum products were to decline below their recent levels, it is likely that development efforts will proceed at a slower pace such that costs will be incurred over a more extended period of time. If petroleum prices remain at current levels, however, we believe that development efforts will intensify. Our ability to successfully negotiate financing to pay our share of development costs on favorable terms will be inextricably linked to the prices that are paid for petroleum products during the time period in which development is actually occurring on each of the subject properties.
Gato Canyon Unit. We hold a 6.97% working interest, with capitalized costs of $3,170,602, 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. Our share of the estimated capital costs to develop the Gato Canyon field is approximately $20 million.
As a result of the Norton case, the Gato Canyon Unit leases are under directed suspensions of operations with no specified end date. An updated Exploration Plan is expected to include plans to drill an additional delineation well when activities are resumed. This well will be used to determine the final location of the development platform. Following the platform decision, a Development Plan will be prepared for submittal to the MMS and the other involved agencies. Two to three years will likely be required to process the Development Plan and receive the necessary approvals.
Lion Rock Unit. We hold a 1% net profits interest, with capitalized costs of $1,554,898, in the Lion Rock Unit. The Lion Rock Unit is operated by Aera Energy LLC.
The Lion Rock Unit is 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 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.
As a result of the Norton case, the Lion Rock Unit is held under a directed suspension of operations with no specified end date. It is anticipated that upon the resumption of activities there will be an interpretation of the 3D seismic survey and the preparation of an updated Plan of Development leading to production. Additional delineation wells may or may not be drilled depending on the outcome of the interpretation of the 3D survey.
Sword Unit. We hold a .87% working interest, with capitalized costs of $280,776, in the Sword Unit. This 12,240 acre unit is operated by Conoco, Inc. In aggregate, three wells have been drilled on this unit of which two wells were completed and tested in the Monterey formation with calculated flow rates of from 4,000 to 5,000 Bbls per day with an estimated average gravity of 10.6E API. The two 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 field's 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. Our share of the estimated capital costs to develop the Sword field is approximately $7 million.
As a result of the Norton case, the Sword Unit leases are held under directed suspensions of operations with no specified end date. An updated Exploration Plan is expected to include plans to drill an additional delineation well when activities are resumed.
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map insert
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(c) Production ----------
Since we sold our producing properties, we no longer have any sales contracts in place. During the last three fiscal years 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, 2002 June 30, 2001 June 30, 2000 ------------- ------------- ------------- Average sales price: Oil (per barrel) $ - $29.61 $22.50 Natural Gas (per Mcf) - 4.85 2.32 Production costs (per Mcf equivalent) - 1.96 1.08
The profitability of our oil and gas production activities is affected by the fluctuations in the sale prices of our oil and gas production. (see "Managements Discussion and Analysis of Plan of Operation").
Impairment of Long Lived Assets -------------------------------
Undeveloped Offshore California Properties ------------------------------------------
We acquired many of our offshore properties in a series of transactions from 1992 to the present. These properties are carried at our cost bases and have been subject to an impairment review on an annual basis.
These properties will be expensive to develop and produce and have been subject to significant regulatory restrictions and delays. Substantial quantities of hydrocarbons are believed to exist based on estimates reported to us by the operator of the properties and the U.S. government's Mineral Management Services. The classification of these properties depends on many assumptions relating to commodity prices, development costs and timetables. We annually consider impairment of properties assuming that properties will be developed. Based on the range of possible development and production scenarios using current prices and costs, we have concluded that the cost bases of our offshore properties are not impaired at this time. There are no assurances, however, that when and if development occurs, we will recover the value of our investment in such properties.
We annually consider impairment of properties assuming that properties will be developed. Based on the range of possible development and production scenarios using current prices and costs, we have concluded that the cost bases of our offshore properties are not impaired at this time. There are no assurances, however, that when and if development occurs, we will recover the value of our investment in such properties.
(d) Productive Wells and Acreage. ----------------------------
As of June 30, 2002 we had no producing oil and gas wells or developed acreage. Productive wells are producing wells capable of production, including shut-in wells. Developed acreage consists of acres spaced or assignable to productive wells.
(e) Undeveloped Acreage. ------------------- At June 30, 2002, we held undeveloped acreage by state as set forth below: Undeveloped Acres (1) Location Gross Net -------- ----- ---
California (1) 22,340 811
(1) Consists of Federal leases offshore near Santa Barbara, California.
(f) Drilling Activities -------------------
During the year ended June 30, 2002, we did not participate in any drilling activities.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
On January 9, 2002, we and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of forty undeveloped federal leases, some of which are part of our Offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their Offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case that a 1990 amendment to the Coastal Zone Management Act required the Government to make a consistency determination prior to granting lease suspension requests in 1999 constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations.
The forty undeveloped leases are located in the Offshore Santa Maria Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the Santa Barbara Channel off Santa Barbara and Ventura counties. None of these leases is currently impaired, but in the event that there is some future adverse ruling by the California Coastal Commission under the Coastal Zone
Management Act and we decide not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear our appeal of any such ruling or ultimately makes a determination adverse to us, it is likely that some or all of these leases would become impaired and written off at that time.
In addition, it should be noted that our pending litigation against the United States is predicated on the ruling of the lower court in California v. Norton. The United States has appealed the decision of the lower court to the 9th Circuit Court of Appeals. In the event that the United States is not successful in its appeal(s) of the lower court's decision in the Norton case and the pending litigation with us is not settled, it would be necessary for us to reevaluate whether the leases should be considered impaired at that time.
As the ruling in the Norton case currently stands, the United States has been ordered to make a consistency determination under the Coastal Zone Management Act, but the leases are still valid. If through the appellate process the leases are found not to be valid for some reason, or if the United States is finally ordered to make a consistency determination and either does not do so or finds that development is inconsistent with the Coastal Zone Management Act, it would appear that the leases would become impaired even though we would undoubtedly proceed with our litigation. It is also possible that other events could occur during the appellate process that would cause the leases to become impaired, and we will continuously evaluate those factors as they occur.
The suit seeks compensation for the lease bonuses and rentals paid to the Federal Government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. In addition, our claim for exploration costs and related expenses will also be substantial.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
(a) Market or Markets: -----------------
We currently have, and have had for the past three years, only limited trading in the over-the-counter market and there is no assurance that this trading market will expand or even continue. Recent regulations and rules by the SEC and the National Association of Securities Dealers virtually assure that there will be little or no trading in our stock unless and until we are listed on NASDAQ or another exchange. There is no assurance that we will be able to meet the requirements for such listing in the foreseeable future. Further, our capital stock may not be able to be traded in certain states until and unless we are able to qualify, exempt or register our stock. Quotations during 2002 and 2001 have not been available.
(b) Approximate Number of Holders of Common Stock: ---------------------------------------------
The number of holders of record of our securities at October 1, 2002 was approximately 1,000.
(c) Dividends: ---------
We have not declared any cash dividends and have no plan for the payment of dividends on our Common Stock in the foreseeable future. Future payment of such dividends, if any, will depend on the applicable legal and contractual restrictions including those discussed above, as well as our financial condition and financial requirements and general conditions.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following selected financial information should be read in conjunction with our financial statements and the accompanying notes.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATIONS.
Liquidity and Capital Resources. -------------------------------
General -------
At June 30, 2002, we had a working capital deficit of $2,231 compared to working capital of $6,315 at June 30, 2001. Our working capital deficit and our cash used in operating activities of $126,490 during fiscal 2002 was primarily a result of decreased cash flow occurring after sale of our producing properties at the beginning of the year. The lack of cash flow from operations may inhibit the Company from meeting its obligations in a timely manner unless additional financing or the sale of properties occurs. However, the Company has a receivable of $398,495 at June 30, 2002 from Delta. If necessary, Delta will repay its obligation to the Company to meet its obligations for costs incurred with its offshore undeveloped California properties.
Offshore Undeveloped Properties -------------------------------
On January 9, 2002, we and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of forty undeveloped federal leases, some of which are part of our Offshore California properties. The suit seeks compensation for the lease bonuses and rentals paid to the Federal Government, exploration costs and related expenses. The total amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with additional amounts for exploration costs and related expenses. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their Offshore California leases by attempting to deviate significantly from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case that a 1990 amendment to the Coastal Zone Management Act required the Government to make a consistency determination prior to granting lease suspension requests in 1999 constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations. The forty undeveloped leases are located in the Offshore Santa Maria Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the Santa Barbara Channel off Santa Barbara and Ventura counties. None of these leases are currently impaired, but in the event that there is some future adverse ruling by the California Coastal Commission under the Coastal Zone Management Act and we decide not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear our appeal of any such ruling or ultimately makes a determination adverse to us, it is likely that some or all of these leases would become impaired and written off at that time. In addition, it should be noted that our pending litigation against the United States is predicated on the ruling of the lower court in California v. Norton. The United States has appealed the decision of the lower court to the 9th Circuit Court of Appeals. In the event that the United States is not successful in its appeal(s) of the lower court's decision in the Norton case and the pending litigation with us is not settled, it would be necessary for us to reevaluate whether the leases should be considered impaired at that time. As the ruling in the Norton case currently stands, the United States has been ordered to make a consistency determination under the Coastal Zone Management Act, but the leases are still valid. If through the appellate process the leases are found not to be valid for some reason, or if the United States is finally ordered to make a consistency determination and either does not do so or finds that development is inconsistent with the Coastal Zone Management Act, it would appear that the leases would become impaired even though Delta would undoubtedly proceed with its litigation. It is also possible that other events could occur during the appellate process that would cause the leases to become impaired, and we will continuously evaluate those factors as they occur.
Capital Resources -----------------
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 remaining properties. Together with Delta, we will continue to seek 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 and/or sale of equity or debt securities although there can be no assurance that we will be successful in our efforts. 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 that our existing cash balances and funding from the advance to Delta and other sources of funds will be adequate to fund our operating expenses and satisfy our other current liabilities over the next year.
Results of Operations - Fiscal 2002 Versus 2001 -----------------------------------------------
Net Income. Our net losses for the years ended June 30, 2002 and 2001 were $46,765 and $42,628 respectively.
Revenue. Total revenue for the year ended June 30, 2002 was $81,817 compared to $119,425 for the year ended June 30, 2001. Oil and gas sales for the year ended June 30, 2002 were zero compared to $67,738 for the year ended June 30, 2001 as we sold all of our producing properties.
Gain on sale of oil and gas properties. In fiscal 2002 we sold all of our onshore producing properties to Delta at a gain of $73,960 which was recognized after Delta sold to a third party.
Other Revenue. Other revenue includes amounts recognized from the production of gas previously deferred pending determination of our interest in the properties and proceeds from the sale of oil and gas properties.
Production volumes and average prices received for the years ended June 30, 2002 and 2001 are as follows:
Year Ended Year Ended June 30, 2002 June 30, 2001 ------------- ------------- Production: Oil (barrels) - 381 Gas (Mcf) - 11,630
Average Price: Oil (per barrel) $ - $ 29.61 Gas (per Mcf) $ - $ 4.85
Lease Operating Expenses. Lease operating expenses for the year ended June 30, 2002 were zero as we sold all of our producing properties compared to $22,827 for the year ended June 30, 2001. On an MCF equivalent basis production expenses and taxes were $1.96 per Mcf equivalent for the year ended June 30, 2001.
Depletion Expense. Depletion expense for the year ended June 30, 2001 was $10,608. There was no depletion in the year ended June 30, 2002 as all properties were sold on July 1, 2002.
Exploration Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals relating to our offshore properties. We incurred exploration costs of $19,772 and $17,482 for the years ended June 30, 2002 and 2001, respectively.
General and Administrative Expenses. General and administrative expense for the year ended June 30, 2002 was $108,810 compared to $111,136 for the year ended June 30, 2001.
Results of Operations - Fiscal 2001 Versus 2000 -----------------------------------------------
Net Income. Our net losses for the years ended June 30, 2001 and 2000 were $42,628 and $67,494, respectively.
Revenue. Total revenue for the year ended June 30, 2001 was $119,425 compared to $100,245 for the year ended June 30, 2000. Oil and gas sales for the year ended June 30, 2001 were $67,738 compared to $37,579 for the year ended June 30, 2000. The increase in oil and gas sales for the year ended June 30, 2001 compared to the year ended June 30, 2000 is attributable to the increase in oil and gas price during fiscal 2001.
Other Revenue. Other revenue includes amounts recognized from the production of gas previously deferred pending determination of our interest in the properties.
Production volumes and average prices received for the years ended June 30, 2001 and 2000 are as follows:
Year Ended Year Ended June 30, 2001 June 30, 2000 ------------- ------------- Production: Oil (barrels) 381 488 Gas (Mcf) 11,630 11,443
Average Price: Oil (per barrel) $ 29.61 $ 22.50 Gas (per Mcf) $ 4.85 $ 2.32
Lease Operating Expenses. Lease operating expenses for the year ended June 30, 2001 was $22,827 compared to $15,528 for the year ended June 30, 2000. On an MCF equivalent basis production expenses and taxes were $1.96 per Mcf equivalent during the year ended June 30, 2001 compared to $1.08 for the year ended June 30, 2000.
Depletion Expense. Depletion expense for the year ended June 30, 2001 was $10,608 compared to $14,417 for the year ended June 30, 2000.
Exploration Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals. We incurred exploration costs of $17,482 and $7,189 for the years ended June 30, 2001 and 2000, respectively.
General and Administrative Expenses. General and administrative expense for the year ended June 30, 2001 was $111,136 compared to $130,605 for the year ended June 30, 2000.
Critical Accounting Policies and Estimates ------------------------------------------
The discussion and analysis of our financial condition and results of operations were based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. Our significant accounting policies are described in Note 1 to our financial statements. In response to SEC Release No. 33-8040, "Cautionary Advise Regarding Disclosure About Critical Accounting Policies," we have identified certain of these policies as being of particular importance to the portrayal of our financial position and results of operations and which require the application of significant judgment by management. We analyze our estimates, including those related to oil and gas reserves, bad debts, oil and gas properties, marketable securities, income taxes, derivatives, contingencies and litigation, and base our estimates on historical experience and various other assumptions that we believe reasonable under the circumstances. Actual results may differ from these estimates under different assumptions or conditions. We believe the following critical accounting policies affect our more significant judgments and estimates used in the preparation of the Company's financial statements.
Successful Efforts Method of Accounting ---------------------------------------
We account for our natural gas and crude oil exploration and development activities utilizing the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Gas and oil lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for gas and oil leases, are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. A gain or loss is recognized for all other sales of producing properties.
The application of the successful efforts method of accounting requires managerial judgment to determine that proper classification of wells designated as developmental or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver gas and oil in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and
exploratory in nature and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and gas field is typically considered a development costs and capitalized but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of gas and oil leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.
The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding a gas and oil field that will be the focus of future development drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.
Reserve Estimates -----------------
We do not currently own any reserves and we do not currently have any estimates of any gas or oil reserves.
Impairment of Gas and Oil Properties ------------------------------------
We review our gas and oil properties for impairment whenever events and circumstances indicate a decline in the recoverability of their carrying value. We estimate the expected future cash flows of our gas and oil properties and compare such future cash flows to the carrying amount of the gas and oil properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the gas and oil properties to their fair value. The factors used to determine fair value include, but are not limited to, estimates of hydrocarbons that we believe are recoverable even though they are not proved reserves, future commodity pricing, future production estimates, anticipated capital expenditures, and a discount rate commensurate with the risk associated with realizing the expected cash flows projected.
Given the complexities associated with such estimates and the history of price volatility in the gas and oil markets, events may arise that would require us to record an impairment of the book values associated with our gas and oil properties. As a result of our review, we did not record an impairment during the years ended June 30, 2002, 2001 or 2000.
Recently Issued or Proposed Accounting Standards and Pronouncements. --------------------------------------------------------------------
In July 2001, the Financial Accounting Standards Board issued and approved for issuance SFAS No. 143, "Accounting for Asset Retirement Allocations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset and is effective for fiscal years beginning after June 15, 2002. We are currently assessing the impact SFAS No. 143 will have on our financial condition and results of operations.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, that superseded SFAS No. 121 and APB Opinion No. 30. SFAS 144 provides guidance on differentiating between assets held and used, held for sale, and held for disposal other than by sale, and the required valuation of such assets. SFAS 144 is effective for fiscal years beginning after December 15, 2001. We are currently assessing the impact SFAS No. 144 will have on our financial condition and results of operations.
Statement 145, Recission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections (SFAS No. 145) was issued in April 2002. This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of income taxes. As a result, the criteria in APB 30 will now be used to classify those gains and losses. Any gain or loss on the extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB 30 for classification as an extraordinary item shall be reclassified. The provisions of this Statement are effective for fiscal years beginning after January 1, 2003. We do not believe the Company will be materially impacted by this statement.
Statement 146, Accounting for Exit or Disposal Activities (SFAS No. 146), was issued in June 2002. SFAS No. 146 addresses significant issues regarding the recognition, measurement and reporting of disposal activities, including restructuring activities that are currently accounted in EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Activity." SFAS No. 146 will be effective in January 2003. We are currently assessing the impact of SFAS No. 146.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Market risk is the potential loss arising from adverse changes in market rates and prices, such as foreign currency exchange and interest rates and commodity prices. We do not use financial instruments to any degree to manage foreign currency exchange and interest rate risks and do not hold or issue financial instruments to any degree for trading purposes. All of our revenue and related receivables are payable in U.S. dollars.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements are included beginning on Page.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
Not applicable.
PART III
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
Information with respect to our executive officers and directors is set forth below:
Name Age Positions Period of Service - --------------------- --- ------------------------ -------------------
Aleron H. Larson, Jr. 57 Chairman of the Board, May 1987 to Present Secretary, and a Director
Roger A. Parker 40 President, Chief May 1987 to Present Executive Officer and a Director
Jerrie F. Eckelberger 58 Director September 1996 to Present
Kevin K. Nanke 37 Treasurer and Chief December 1999 Financial Officer to Present
The following is biographical information as to the business experience of each of our current officers and directors.
Aleron H. Larson, Jr., age 57, has operated as an independent in the oil and gas industry individually and through public and private ventures since 1978. Mr. Larson served as the Chairman, Secretary, CEO and a Director of Chippewa Resources Corporation, a public company then listed on the American Stock Exchange from July 1990 through March 1993 when he resigned after a change of control. Mr. Larson serves as Chairman of the Board, Secretary and Director of Amber Resources Company ("Amber"), as well as Delta, which is our majority-owned owner. Mr. Larson practiced law in Breckenridge, Colorado from 1971 until 1974. During this time he was a member of a law firm, Larson & Batchellor, engaged primarily in real estate law, land use litigation, land planning and municipal law. In 1974, he formed Larson & Larson, P.C., and was engaged primarily in areas of law relating to securities, real estate, and oil and gas until 1978. Mr. Larson received a Bachelor of Arts degree in Business Administration from the University of Texas at El Paso in 1967 and a Juris Doctor degree from the University of Colorado in 1970.
Roger A. Parker, age 40, served as the President, a Director and Chief Operating Officer of Chippewa Resources Corporation from July of 1990 through March 1993 when he resigned after a change of control. Mr. Parker serves as President, Chief Executive Officer and Director of Amber and also Delta. He also serves as a Director and Executive Vice President of P & G Exploration, Inc., a private oil and gas company (formerly Texco Exploration, Inc.). Mr. Parker has also been the President, a Director and sole shareholder of Apex Operating Company, Inc. since its inception in 1987. He has operated as an independent in the oil and gas industry individually and through public and private ventures since 1982. He was at various times, from 1982 to 1989, a Director, Executive Vice President, President and shareholder of Ampet, Inc. He received a Bachelor of Science in Mineral Land Management from the
University of Colorado in 1983. He is a member of the Rocky Mountain Oil and Gas Association and the Independent Producers Association of the Mountain States (IPAMS).
Jerrie F. Eckelberger, age 58, is an investor, real estate developer and attorney who has practiced law in the State of Colorado since 1971. He graduated from Northwestern University with a Bachelor of Arts degree in 1966 and received his Juris Doctor degree in 1971 from the University of Colorado School of Law. From 1972 to 1975, Mr. Eckelberger was a staff attorney with the eighteenth Judicial District Attorney's Office in Colorado. From 1975 to present, Mr. Eckelberger has practiced law in Colorado and is presently a member of the law firm of Eckelberger & Jackson, LLC. 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. He also serves on the Board of Directors of Delta.
Kevin K. Nanke, age 37, Treasurer and Chief Financial Officer of both Amber and Delta, joined us in April 1995. Since 1989, he has been involved in public and private accounting with the oil and gas industry. Mr. Nanke received a Bachelor of Arts in Accounting from the University of Northern Iowa in 1989. Prior to working with us, he was employed by KPMG LLP. He is a member of the Colorado Society of CPA's and the Council of Petroleum Accounting Society.
There is no family relationship among or between any of our Officers and/or Directors.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION.
No officer or director received compensation directly from us during the years ended June 30, 2002, 2001 and 2000. Messrs. Larson, Parker, Nanke, Chairman, President and Chief Financial Officer, respectively, are compensated by Delta, which compensation is paid under a management agreement with us. No officer or director received stock appreciation rights, restricted stock awards, options, warrants or other similar compensation reportable under this section during any of the above referenced periods.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) & (b) Security Holdings of Management and Persons Controlling more than 5% of shares of Common Stock Outstanding on a Fully-Diluted Basis.
Name and Address of Amount & Nature of Beneficial Owners Beneficial Ownership Percent of Class - ------------------- -------------------- ----------------
Delta Petroleum Corporation 4,277,977 (1) 91.68% (1) 475 17th Street, Suite 1400 Denver, Colorado 80202
Roger A. Parker 4,277,977 (1) 91.68% (1) 475 17th St., Ste. 1400 Denver, CO 80202
Aleron H. Larson, Jr. 4,277,977 (1) 91.68% (1) 475 17th St., Ste. 1400 Denver, CO 80202
Jerrie F. Eckelberger 4,277,977(1) 91.68% (1) 7120 East Orchard Road Englewood, CO 80111
Kevin K. Nanke 4,277,977 (1) 91.68% (1) 475 17th St., Ste 1400 Denver, Colorado 80202
Management as a Group (4 people) 4,277,977(1) 91.68% (1)
(1) All shares are owned by Delta; Messrs. Larson, Parker and Nanke are either officers, directors or shareholders of Delta. Mr. Eckelberger is also a director of Delta.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Effective October 1, 1998, we entered into an agreement with Delta which provides for the sharing of management between the two companies. Under this agreement we pay Delta $25,000 per quarter for our share of rent, administrative, accounting and management services of Delta officers and employees. This agreement is cancellable by either party at any time. It is our opinion that fees paid to Delta for services rendered are comparable to fees that would be charged by similarly qualified non-affiliated persons. This agreement replaces a previous agreement which allocated similar expenses based on our proportionate share of oil and gas production. The charges to us for the provision of services by Delta were $100,000 for the years ended June 30, 2002, 2001 and 2000. We had a receivable from Delta of $398,000 and $404,000 recorded as a reduction in equity at June 30, 2002 and 2001, respectively.
On July 1, 2001, we sold all of our proved producing properties to Delta, which owns over 91% of our issued and outstanding shares, for $107,044 as an increase in the amount receivable from Delta. The sale price was calculated as being an amount equal to the net present value of the estimated hydrocarbons beneath the properties using a discount rate of 10% as determined by independent engineers. Management believes that the terms of this transaction were on terms no less favorable to us than could have been obtained from an independent third party.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Financial Statements: --------------------
Independent auditors' report
Balance Sheet as of June 30, 2002 and 2001
Statements of Operations and Accumulated Deficit Years Ended June 30, 2002, 2001 and 2000
Statements of Cash Flows
Notes to Financial Statements
Financial Statement Schedules: None -----------------------------
(b) Reports on Form 8-K: None -------------------
(c) Exhibits: --------
The Exhibits listed in the Index to Exhibits appearing at page 34 are filed as part of this report.
INDEX TO EXHIBITS
(2) Plan of Acquisitions, Reorganization, Arrangement, Liquidation, or Succession. Not applicable.
(3) Articles of Incorporation and Bylaws. The Articles of Incorporation (Certificate of Incorporation) and Bylaws of the Registrant filed as Exhibits 4 and 5 to Registrant's Form S-1 Registration Statement filed August 28, 1978 with the Securities and Exchange Commission are incorporated herein by reference. The Restated Articles of Incorporation (Restated Certificate of Incorporation) dated January 26, 1988 and Amendment to Restated Certificate of Incorporation dated September 18, 1989 are attached hereto as Exhibits 3.1 and 3.2, respectively.
(4) Instruments Defining the Rights of Security Holders.
4.1 Certificate of Designation of the Relative Rights of the Class A Preferred Stock of Amber Resources Company dated July 25, 1989. Incorporated by reference to Exhibit 4.1 of the Company's Form 10-KSB for the fiscal year ended June 30, 1997.
(9) Voting Trust Agreement. Not applicable.
(10) Material Contracts.
10.1 Agreement dated March 31, 1993 between Delta Petroleum Corporation and Amber Resources Company. Incorporated by reference from Exhibit 10.1 of the Company's Form 10-KSB for the fiscal year ended June 30, 1997.
10.2 Amber Resources Company 1996 Incentive Plan. Incorporated by reference from Exhibit 99.1 of the Company's December 4, 1996 Form 8-K.
10.3 Agreement between Amber Resources Company and Delta Petroleum Corporation dated effective October 1, 1998. Incorporated by reference from Exhibit 10.2 of the Company's Form 10-KSB for the fiscal year ended June 30, 1999.
10.4 Purchase and Sale Agreement between Amber Resources Company and Delta Petroleum Corporation dated July 1, 2001. Filed herewith electronically.
(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 Principals. 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. Not applicable.
(24) Power of Attorney. Not applicable.
(27) Financial Data Schedule. Not applicable.
(99) Additional Exhibits. Not applicable.
Independent Auditors' Report
The Board of Directors and Stockholders Amber Resources Company:
We have audited the accompanying balance sheets of Amber Resources Company (the "Company"), a subsidiary of Delta Petroleum Corporation, as of June 30, 2002 and 2001 and the related statements of operations and accumulated deficit, and cash flows for each of the years in the three-year period ended June 30, 2002. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material 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 financial statements referred to above present fairly, in all material respects, the financial position of Amber Resources Company as of June 30, 2002 and 2001, and the results of its operations and its cash flows for each of the years in the three-year period ended June 30, 2002, in conformity with accounting principles generally accepted in the United States of America.
s/KPMG KPMG LLP
Denver, Colorado September 12, 2002
AMBER RESOURCES COMPANY BALANCE SHEETS June 30, 2002 and 2001
2002 2001 ---------- ---------- ASSETS
Current Assets: Cash $ 681 $ 14,992 Accounts receivable - 7,855 ---------- ---------- Total current assets 681 22,847 ---------- ---------- Property and Equipment: Oil and gas properties, at cost (using the successful efforts method of accounting): Undeveloped offshore California properties 5,006,276 5,006,276 Developed onshore domestic properties - 203,053 ---------- ---------- 5,006,276 5,209,329 Less accumulated depreciation and depletion - (169,968) ---------- ---------- Net property and equipment 5,006,276 5,039,361 ---------- ---------- $5,006,957 $5,062,208 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities: Accounts payable $ 2,912 $ 16,532 ---------- ---------- Total current liabilities 2,912 16,532 ---------- ---------- Stockholders' Equity: Preferred stock, $.10 par value; authorized 5,000,000 shares of Class A convertible preferred stock, none issued - - Common stock, $.0625 par value; authorized 25,000,000 shares, issued 4,666,185 shares at June 30, 2002 and 2001 291,637 291,637 Additional paid-in capital 5,755,232 5,755,232 Accumulated deficit (644,329) (597,564) Advance to parent (398,495) (403,629) ---------- ---------- Total stockholders' equity 5,004,045 5,045,676 ---------- ---------- Commitments $5,006,957 $5,062,208 ========== ==========
See accompanying notes to consolidated financial statements.
AMBER RESOURCES COMPANY STATEMENTS OF OPERATIONS AND ACCUMULATED DEFICIT Years Ended June 30, 2002, 2001 and 2000
See accompanying notes to consolidated financial statements.
AMBER RESOURCES COMPANY STATEMENTS OF CASH FLOWS Years Ended June 30, 2002, 2001 and 2000
See accompanying notes to consolidated financial statements.
AMBER RESOURCES COMPANY (A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements Years Ended June 30, 2002 and 2001 - ----------------------------------------------------------------------------
(1) Summary of Significant Accounting Policies
Organization
Amber Resources Company ("the Company") was incorporated in January, 1978, and is principally engaged in acquiring, exploring, developing, and producing offshore oil and gas properties. The Company owns interests in three undeveloped oil and gas properties in federal units offshore California, near Santa Barbara. As of June 30, 2002, Delta Petroleum Corporation ("Delta") owned 4,277,977 shares (91.68%) of the Company's common stock.
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. Additionally, during the year ended June 30, 2002 the Company sold its remaining producing reserves to Delta for $107,044 an amount equal to the properties net present value discounted at 10% as determined by third party engineers. These factors among others may indicate that without increased cash flow from sale of oil and gas properties or additional financing the Company may not be able to meet its obligation in a timely manner or be able to fund exploration and development of its remaining oil and gas properties. 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 in a timely fashion or on acceptable terms.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for its oil and gas activities. Accordingly, costs associated with the acquisition, drilling, and equipping of successful exploratory wells are capitalized.
Geological and geophysical costs, delay and surface rentals and drilling costs of unsuccessful exploratory wells are charged to expense as incurred. Costs of drilling development wells, both successful and unsuccessful, are capitalized.
Upon the sale or retirement of oil and gas properties, the cost thereof and the accumulated depreciation and depletion are removed from the accounts and any gain or loss is credited or charged to operations.
Depreciation and depletion of capitalized acquisition, exploration and development costs is computed on the units-of-production method by individual fields as the related proved reserves are produced. Capitalized costs of undeveloped properties are assessed periodically on an individual field basis and a provision for impairment is recorded, if necessary, through a charge to operations.
AMBER RESOURCES COMPANY (A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements Years Ended June 30, 2002 and 2001 - ----------------------------------------------------------------------------
(1) Summary of Significant Accounting Policies, Continued
Impairment of Long-Lived Assets
Statement of Financial Accounting Standards 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" (SFAS 121) requires that long-lived assets be reviewed for impairment when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. For developed properties, the review consists of a comparison of the carrying value of the asset with the asset's expected future undiscounted cash flows without interest costs.
Estimates of expected future cash flows represent management's best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows exceed the carrying value of the asset, no impairment is recognized. If the carrying value of the asset exceeds the expected future cash flows, an impairment exists and is measured by the excess of the carrying value over the estimated fair value of the asset. Any impairment provisions recognized in accordance with SFAS 121 are permanent and may not be restored in the future.
The Company assesses developed properties on an individual field basis for impairment on at least an annual basis.
For undeveloped properties, the need for an impairment reserve is based on the Company's plans for future development and other activities impacting the life of the property and the ability of the Company to recover its investment. When the Company believes the cost of the undeveloped property is no longer recoverable, an impairment charge is recorded based on the estimated fair value of the property.
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 total estimated reserves of the property. Thereafter, additional amounts received are recorded as a liability.
Earnings (Loss) per Share
Basic earnings (loss) per share is computed by dividing net earnings (loss) attributable to common stock by the weighted average number of common shares outstanding during each period, excluding treasury shares. The Company does not have any dilutive instruments and as such, no diluted earnings per share have been presented.
AMBER RESOURCES COMPANY (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2002 and 2001 - ----------------------------------------------------------------------------
(1) Summary of Significant Accounting Policies, Continued
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 revenue and expenses during the reported period. Significant estimates include oil and gas reserves, bad debts, oil and gas properties, income taxes, contingencies and litigation. Actual results could differ from these estimates.
Recently Issued Accounting Standards and Pronouncements
In July 2001, the Financial Accounting Standards Board approved for issuance SFAS No. 143, "Accounting for Asset Retirement Obligations." SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset and is effective for fiscal years beginning after June 15, 2002. The Company is currently assessing the impact SFAS No. 143 will have on its financial condition and results of operations.
In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, that superseded SFAS No. 121 and APB Opinion No. 30. SFAS 144 provides guidance on differentiating between assets held and used, held for sale, and held for disposal other than by sale, and the required valuation of such assets. SFAS 144 is effective for fiscal years beginning after December 15, 2001. The Company is currently assessing the impact SFAS No. 144 will have on its financial condition and results of operations.
Statement 145, Recission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical Corrections (SFAS No. 145) was issued in April 2002. This statement rescinds SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, which required all gains and losses from extinguishment of debt to be aggregated and, if material, classified as an extraordinary item, net of income taxes. As a result, the criteria in APB 30 will now be used to classify those gains and losses. Any gain or loss on the extinguishment of debt that was classified as an extraordinary item in prior periods presented that does not meet the criteria in APB 30 for classification as an extraordinary item shall be reclassified. The provisions of this Statement are effective for fiscal years beginning after January 1, 2003. The Company does not believe this statement will have a material impact to the Financial Statements.
AMBER RESOURCES COMPANY (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2002 and 2001 - ----------------------------------------------------------------------------
(1) Summary of Significant Accounting Policies, Continued
Statement 146, Accounting for Exit or Disposal Activities (SFAS No. 146), was issued in June 2002. SFAS No. 146 addresses significant issues regarding the recognition, measurement and reporting of disposal activities, including restructuring activities that are currently accounted in EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Activity." SFAS No. 146 will be effective in January 2003. The Company is currently assessing the impact of SFAS No. 146.
(2) Oil and Gas Properties
On July 1, 2001, the Company sold all of its producing properties to Delta Petroleum Corporation, our Parent, for $107,044. The sales price for the properties was fair value based on an evaluation performed by an unrelated engineering firm. The difference between the sales price received and the net cost of the properties resulted in a gain of $73,960. The properties were ultimately sold by the Company's parent during fiscal 2002. As such, the gain was realized during fiscal 2002.
Unproved Undeveloped Offshore California Properties
The Company has ownership interests ranging from 87% to 6.97% in three unproved undeveloped offshore California oil and gas properties with aggregate carrying values of $5,006,000 on June 30, 2002 and 2001. These property interests are located in proximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. Preliminary exploration efforts on these properties have occurred and the existence of substantial quantities of hydrocarbons has been indicated. The recovery of the Company's investment in these properties will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties.
Should the required regulatory approvals not be obtained or plans for exploration and development of the properties not continue, the carrying value of the properties would likely be impaired and written off.
Even though the Company is not the designated operator of the properties and regulatory approvals have not been obtained, the Company believes exploration and development activities on these properties will occur and is committed to expend funds attributable to its interests in order to proceed with obtaining the approvals for the exploration and development activities.
On January 9, 2002, Amber and several other plaintiffs filed a lawsuit in the United States Court of Federal Claims in Washington, D.C. alleging that the U.S. Government has materially breached the terms of forty undeveloped federal leases, some of which are part of Amber's Offshore California properties. The Complaint is based on allegations by the collective plaintiffs that the United States has materially breached the terms of certain of their Offshore California leases by attempting to deviate significantly
AMBER RESOURCES COMPANY (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2002 and 2001 - ----------------------------------------------------------------------------
(2) Oil and Gas Properties, Continued
from the procedures and standards that were in effect when the leases were entered into, and by failing to carry out its own obligations relating to those leases in a timely and fair manner. More specifically, the plaintiffs have alleged that the judicial determination in the California v. Norton case that a 1990 amendment to the Coastal Zone Management Act required the Government to make a consistency determination prior to granting lease suspension requests in 1999 constitutes a material change in the procedures and standards that were in effect when the leases were issued. The plaintiffs have also alleged that the United States has failed to afford them the timely and fair review of their lease suspension requests which has resulted in significant, continuing and material delays to their exploratory and development operations. The forty undeveloped leases are located in the Offshore Santa Maria Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the Santa Barbara Channel off Santa Barbara and Ventura counties. None of these leases is currently impaired, but in the event that there is some future adverse ruling by the California Coastal Commission under the Coastal Zone Management Act and Amber decides not to appeal such ruling to the Secretary of Commerce, or the Secretary of Commerce either refuses to hear Amber's appeal of any such ruling or ultimately makes a determination adverse to Amber, it is likely that some or all of these leases would become impaired and written off at that time. In addition, it should be noted that Amber's pending litigation against the United States is predicated on the ruling of the lower court in California v. Norton. The United States has appealed the decision of the lower court to the 9th Circuit Court of Appeals. In the event that the United States is not successful in its appeal(s) of the lower court's decision in the Norton case and the pending litigation with Amber is not settled, it would be necessary for Amber to reevaluate whether the leases should be considered impaired at that time. As the ruling in the Norton case currently stands, the United States has been ordered to make a consistency determination under the Coastal Zone Management Act, but the leases are still valid. If through the appellate process the leases are found not to be valid for some reason, or if the United States is finally ordered to make a consistency determination and either does not do so or finds that development is inconsistent with the Coastal Zone Management Act, it would appear that the leases would become impaired even though Amber would undoubtedly proceed with its litigation. It is also possible that other events could occur during the appellate process that would cause the leases to become impaired, and Amber will continuously evaluate those factors as they occur.
(3) Preferred Stock
The Board of Directors is authorized to issue 5,000,000 shares of preferred stock having a par value of $0.10 per share. As of the years ended June 30, 2002 and 2001, no preferred stock was issued and outstanding.
(4) Income Taxes
At June 30, 2002 and 2001, the Company's significant deferred tax assets and liabilities are summarized as follows:
AMBER RESOURCES COMPANY (A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements Years Ended June 30, 2002 and 2001 - ----------------------------------------------------------------------------
(4) Income Taxes, Continued
No income tax expense or benefit has been recorded for the years ended June 30, 2002 and 2001 since the deferred income taxes that would have otherwise been provided were offset by a decrease in the valuation allowance for the net deferred tax assets. The Company is consolidated in Delta's income tax return and accounts for its income tax as if it filed a separate return. As Delta has a net operating loss carryforward and a valuation allowance for deferred tax assets, the consolidation for income tax purposes has no financial statement impact to the Company.
At June 30, 2002, the Company had net operating loss carryforwards for regular and alternative minimum tax purposes of approximately $2,215,000. If not utilized, the tax net operating loss carryforwards will expire during the period from 2003 through 2022. If not utilized, approximately $1.0 million of net operating losses will expire over the next five years.
(5) Related Party Transactions
Effective October 1, 1998, the Company and Delta entered into an agreement which provides for the sharing of management between the two companies. Under this agreement the Company pays Delta $25,000 per quarter for our share of rent, administrative, accounting and management services of Delta officers and employees. This agreement replaces a previous agreement which allocated similar expenses based on the Company's proportionate share of oil and gas production. The charges to us for the provision of services by Delta were $100,000 for the year ended June 30, 2002, 2001 and 2000. We had a non-interest bearing receivable from Delta of $398,495 and 403,629 recorded as a reduction in equity at June 30, 2002 and 2001, respectively.
AMBER RESOURCES COMPANY (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2002 and 2001 - ----------------------------------------------------------------------------
(5) Related Party Transactions, Continued
On July 1, 2001, the Company sold all of its proved producing properties to Delta, which owns over 91% of the Company's issued and outstanding shares, for $107,044 in cash. The sale price was calculated as being an amount equal to the net present value of the estimated hydrocarbons beneath the properties using a discount rate of 10% as determined by independent engineers. Management believes that the terms of this transaction were on terms no less favorable to the Company than could have been obtained from an independent third party.
(6) Disclosures About Capitalized Costs, Costs Incurred and Major Customers
Capitalized costs related to oil and gas producing activities are as follows: June 30, June 30, 2002 2001 -------- -------- Undeveloped offshore California properties $ 5,006,276 $ 5,006,276 Developed onshore domestic properties - 203,053 ----------- ----------- 5,006,276 5,209,329 Accumulated depreciation and depletion - (169,968) ----------- ----------- $ 5,006,276 $ 5,039,361 =========== ============
Costs incurred in oil and gas producing activities for the years ended June 30, 2002, 2001 and 2000 are as follows:
2002 2001 2000 ---- ---- ----
Intangible drilling costs $ - $ 7,522 $ - Exploration costs $19,772 $17,482 $ 7,189
A summary of the results of operations for oil and gas producing activities, excluding general and administrative cost, for the years ended June 30, 2002, 2001 and 2000 is as follows:
2002 2001 2000 ---- ---- ---- Revenue: Oil and gas sales $ - $67,738 $37,579 Expenses: Lease operating - 22,827 15,528 Depletion - 10,608 14,417 Exploration 19,772 17,482 7,189 -------- ------- ------- Results of operations of oil Gas producing activities $(19,772) $16,821 $ 445 ======== ======= =======
AMBER RESOURCES COMPANY (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2002 and 2001 - ----------------------------------------------------------------------------
(6) Disclosures About Capitalized Costs, Costs Incurred and Major Customers, Continued
Statement of Financial Accounting Standards 131 "Disclosures about Segments of an Enterprise 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.
As the Company had sold its producing properties in fiscal year 2002, there were no 2002 customers, but in 2001, sales to three major customers accounted for approximately 44%, 12% and 12% of oil and gas sales. In 2000, sales to two major customers accounted for approximately 44% and 12% of oil and gas sales .
(7) 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.
AMBER RESOURCES COMPANY (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2002 and 2001 - ----------------------------------------------------------------------------
(7) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
A summary of changes in estimated quantities of proved reserves for the years ended June 30, 2001 and 2000 are as follows:
Onshore ------------------- GAS OIL (MCF) (BBLS) ------------------- Balance at July 1, 1999 186,590 835 Revisions of quantity estimates (8,148) 1,854 Production (11,443) (488) -------- ------ Balance at June 30, 2000 166,999 2,201
Revisions of quantity estimates (25,299) (138) Production (11,630) (381) -------- ------ Balance at June 30, 2001 130,070 1,682
Sales of Producing Properties (130,070) 1,682) -------- ------ Balance at June 30, 2002 - - ======== ======
Proved developed reserves: June 30, 2000 166,999 2,201 June 30, 2001 130,070 1,682 June 30, 2002 - -
AMBER RESOURCES COMPANY (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2002 and 2000 - ----------------------------------------------------------------------------
(7) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
Future net cash flows presented below are computed using year-end prices and costs. The Company has no proved reserves at June 30, 2002. As such, certain disclosures at June 30, 2002 have been eliminated.
Future corporate overhead expenses and interest expense have not been included.
June 30, 2000
Future cash inflows $ 643,918 Future costs: Production 292,258 Development - Income tax - ---------- 351,660 10% discount factor 119,724 ---------- Standardized measure of discounted net cash flows $ 231,936
June 30, 2001
Future cash inflows $ 343,937 Future costs: Production 172,264 Development - Income taxes - ----------
Future net cash flows 171,673
10% discount factor 64,629 ----------
Standardized measure of discounted future net cash flows $ 107,044 ==========
AMBER RESOURCES COMPANY (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2002 and 2001 - ----------------------------------------------------------------------------
(7) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
The principal sources of changes in the standardized measure of discounted net cash flows during the year ended June 30, 2002, 2001 and 2000 are as follows:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, we have caused this Form 10-K to be signed on our behalf by the undersigned, thereunto duly authorized, in the City of Denver and State of Colorado on the 7th day of October, 2002.
AMBER RESOURCES COMPANY
By: /s/ Roger A. Parker ---------------------------------------- Roger A. Parker, Chief Executive Officer
By: /s/ Kevin K. Nanke --------------------------------------- Kevin K. Nanke, Chief Financial Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, we have duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Signature and Title Date
/a/ Aleron H. Larson, Jr. October 7, 2002 - ------------------------------- Aleron H. Larson, Jr., Director
/s/ Roger A. Parker October 7, 2002 - ------------------------------- Roger A. Parker, Director
- ------------------------------- Jerrie F. Eckelberger, Director
CERTIFICATIONS
I, Roger A. Parker, certify that:
1. I have reviewed this annual report on Form 10-K of Amber Resources Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; and
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.
Dated: October 7, 2002 /s/ Roger A. Parker ------------------------------------- Roger A. Parker Chief Executive Officer (Principal Executive Officer)
I, Kevin K. Nanke, certify that:
1. I have reviewed this annual report on Form 10-K of Amber Resources Company;
2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; and
3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report.
/s/ Kevin K. Nanke Dated: October 7, 2002 ------------------------------------- Kevin K. Nanke Chief Financial Officer (Principal Financial Officer)
CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER OF AMBER RESOURCES COMPANY PURSUANT TO 18 U.S.C. SECTION 1350
We certify that, to the best of our knowledge, the Annual Report on Form 10-K of Amber Resources Company for the period ending June 30, 2002:
(1) complies with the requirements of Section 13(a) or 15(d) of the Securities and Exchange Act of 1934; and
(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Delta Petroleum Corporation.
/s/ Roger A. Parker /s/ Kevin K. Nanke - ----------------------------------- ----------------------------------- Roger A. Parker Kevin K. Nanke Chief Executive Officer Chief Financial Officer
October 7, 2002 October 7, 2002