ITEM 1. DESCRIPTION OF BUSINESS
(a) Business Development.
Amber Resources Company of Colorado, formerly named "Amber Resources Company" ("Amber," "the Company," "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, 2005, our principal assets include interests in three undeveloped Federal units located in the Santa Barbara Channel and the Santa Maria Basin offshore California. There continue to be uncertainties as to the timing of the development of our offshore properties. (See "Description of Properties," Item 2
ITEM 2. DESCRIPTION OF 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 2003 through 2005. No reserve estimates were prepared for the past three years as all remaining leases are undeveloped.
Offshore Federal Waters: Santa Barbara, California Area -------------------------------------------------------
Unproved Undeveloped Properties -------------------------------
We own interests in three undeveloped federal units located in federal waters offshore California near Santa Barbara. 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 our investment in these properties will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties as discussed herein.
We are not the designated operator of any of these properties but are an active participant in the ongoing activities of each property along with the designated operator and other interest owners. If the designated operator elected not to or was unable to continue as the operator, the other property interest owners would have the right to designate a new operator as well as share in additional property returns prior to the replaced operator being able to receive returns. Based on our size, it would be difficult for us to proceed with exploration and development plans should other substantial interest owners elect not to proceed. However, to the best of our knowledge, we believe the designated operators and other major property interest owners intend to proceed with exploration and development plans under the terms and conditions of the operating agreement.
Even though we are not the designated operator of the properties and regulatory approvals have not been obtained, we believe exploration and development activities on these properties will occur and we and our parent are committed to expending funds attributable to our interests in order to proceed with obtaining the approvals for the exploration and development activities.
Based on the preliminary indicated levels of hydrocarbons present from drilling operations conducted in the past, we believe the fair value of our property interests are in excess of their carrying value at June 30, 2005 and June 30, 2004 and that no impairment in the carrying value has occurred. Should the required regulatory approvals not be obtained or plans for exploration and development of the properties not continue, the carrying value of the properties would likely be impaired and written off.
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. The ownership rights in each of these properties have been retained under various suspension notices issued by the Mineral Management Service (MMS) of the U.S. Federal Government whereby, as long as the owners of each property were progressing toward defined milestone objectives, the owners' rights with respect to the properties continue to be maintained. The issuance of the suspension notices has been necessitated by the numerous delays in the exploration and development process resulting from regulatory requirements imposed on the property owners by federal, state and local agencies.
On June 22, 2001, however, a Federal Court in the case of California v. Norton, et al. ruled that the MMS does not have the power to grant suspensions on the subject leases without first making a consistency determination under the Coastal Zone Management Act ("CZMA"), and ordered the MMS to set aside its approval of the suspensions of our offshore leases and to direct suspensions for a time sufficient for the MMS to provide the State of California with the required consistency determination. The delays have prevented the property owners from submitting for approval an exploration plan on four of the properties. If and when plans are submitted for approval, they are subject to review for consistency with the CZMA, and by the MMS for other technical requirements.
As the ruling in the Norton case currently stands, the United States has made a consistency determination under the CZMA in accordance with the Court's order and the leases are still valid. If the leases are found not to be valid for some reason in the future, 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 that would cause the leases to become impaired, and we will continuously evaluate those factors as they occur.
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 CZMA 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 an adverse determination, it is likely that some or all of these leases would become impaired and written off at that time.
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 the 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 Norton case that a 1990 amendment to the CZMA required the federal 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 suit seeks compensation for the lease bonuses and rentals paid to the federal government, exploration costs and related expenses. In the event that we receive any proceeds as the result of such litigation, we will be obligated to pay a portion of any amount received by us to landowners and other owners of royalties and similar interests, and to pay expenses of litigation and to fulfill certain pre-existing contractual commitments to third parties.
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 $3,170,886, 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. 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. 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. Offshore pipeline distance to access the Las Flores site is approximately six miles. Our share of the estimated capital costs to develop the Gato Canyon field is approximately $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. 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 and would be transported out of Santa Barbara County in the All American Pipeline or the Tosco-Unocal Pipeline. Offshore pipeline distance will be eight to ten miles depending on the point of landfall.
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. Water depths range from 1000 feet to 1800 feet in the area of the field. It is anticipated that the oil and gas produced from the Sword Field will likely be processed at the existing Gaviota consolidated facility and the oil would then be transported out of Santa Barbara County in the All American Pipeline. Access to the Gaviota plant is through Platform Hermosa and the existing Point Arguello Pipeline system. A pipeline proposed to be laid from a platform located in the northern area of the Sword field to Platform Hermosa would be approximately five miles in length. Our share of the estimated capital costs to develop the Sword field is approximately $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.
(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 profitability of our oil and gas production activities is affected by the fluctuations in the sale prices of our oil and gas production. (See "Management's Discussion and Analysis of Financial Condition and Plan of Operations").
Impairment of Long Lived Assets -------------------------------
Unproved 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.
(d) Productive Wells and Acreage ----------------------------
As of June 30, 2005 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, 2005, 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, 2005, 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 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 the event, however, that we receive any proceeds as the result of such litigation, we may be obligated to pay a portion of any amount received by us to landowners and other owners of royalties and similar interests, and to pay expenses of litigation and to fulfill certain pre-existing contractual commitments to third parties.
The Federal Government has not yet filed an answer in this proceeding pending its motion to dismiss the lawsuit, which motion has not yet been heard by the court. More recently, the plaintiffs filed a motion for summary judgment as to certain liability aspects related to their claims. Neither motion has yet been heard by the court.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth quarter of our fiscal year.
PART II
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 quoted on the OTC Bulletin Board or similar quotation service, or listed on NASDAQ or an 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 2005 and 2004 have not been available.
(b) Approximate Number of Holders of Common Stock ---------------------------------------------
The number of holders of record of our securities at October 5, 2005 was approximately 1,000.
(c) Dividends ---------
We have not paid dividends on our stock and we do not expect to do so in the foreseeable future.
(d) Changes in Securities ---------------------
During the quarter ended June 30, 2005, we did not have any sales of securities that were not registered under the Securities Act of 1933, as amended.
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 OF FINANCIAL CONDITION AND PLAN OF OPERATIONS
Liquidity and Capital Resources -------------------------------
At June 30, 2005 and 2004, we essentially had no working capital. The cash used in operating activities of $110,240 during fiscal 2005 remained consistent with fiscal 2004. 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 $47,498 at June 30, 2005 from Delta. If necessary, Delta may repay its obligation to the Company to meet Amber's operating needs and obligations for costs incurred relating to our offshore undeveloped California properties.
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 needs 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 2005 Versus 2004 -----------------------------------------------
Net Income. Our net losses for the years ended June 30, 2005 and 2004 were $110,240 and $109,308, respectively.
As all of our producing properties were sold on July 1, 2001 there were no revenues, production volumes, lease operating expenses or depletion in the years ended June 30, 2005 and June 30, 2004.
Exploration Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals relating to our offshore properties. We incurred exploration costs of $235 and $1,441 for the years ended June 30, 2005 and 2004, respectively.
General and Administrative Expenses. General and administrative expense for the year ended June 30, 2005 was $110,005 compared to $107,867 for the year ended June 30, 2004.
Results of Operations - Fiscal 2004 Versus 2003 -----------------------------------------------
Net Income. Our net losses for the years ended June 30, 2004 and 2003 were $109,308 and $128,936, respectively.
As all of our producing properties were sold on July 1, 2001 there were no revenues, production volumes, lease operating expenses or depletion in the years ended June 30, 2004 and June 30, 2003.
Exploration Expenses. Exploration expenses consist of geological and geophysical costs and lease rentals. We incurred exploration costs of $1,441 and zero for the years ended June 30, 2004 and 2003, respectively.
General and Administrative Expenses. General and administrative expense for the year ended June 30, 2005 was $107,867 compared to $128,936 for the year ended June 30, 2003. The decrease in general and administrative expense was due to additional incorporation fees incurred during fiscal 2003.
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 Advice 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 cost 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, 2005, 2004 or 2003.
Recently Issued Accounting Standards and Pronouncements - -------------------------------------------------------
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections-a replacement of APB Opinion No. 20 and FASB Statement No. 3 ("Statement 154"). SFAS 154 requires retrospective application to prior periods' financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The implementation of FAS 154 is not expected to have a material impact on our consolidated results of operations, financial position or cash flows.
In December 2004, the FASB issued its final standard on accounting for employee stock options, FAS No. 123 (Revised 2004), "Share-Based Payment" ("FAS123(R)"). FAS 123(R) replaces FAS No. 123, "Accounting for Stock-Based Compensation" ("FAS 123"), and supersedes Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." FAS 123(R) requires companies to measure compensation costs for all share-based payments, including grants of employee stock options, based on the fair value of the awards on the grant date and to recognize such expense over the period during which an employee is required to provide services in exchange for the award. The pro forma disclosures previously permitted under FAS 123 will no longer be an alternative to financial statement recognition. FAS 123(R) is effective for all awards granted, modified, repurchased or cancelled after, and to unvested portions of previously issued and outstanding awards vesting after, interim or annual periods, beginning after June 15, 2005, which for us will be the first quarter of fiscal 2006. We are currently evaluating the effect of adopting FAS 123(R) on our financial position and results of operations, and we have not yet determined whether the adoption of FAS 123(R) will result in expenses in amounts that are similar to the current pro forma disclosures under FAS 123.
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. There are no financial statement schedules since they are either not applicable or the information is included in the notes to the financial statements.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures ------------------------------------------------
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms, and that such information is accumulated and communicated to management, including the chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosure. Management necessarily applied its judgment in assessing the costs and benefits of such controls and procedures, which, by their nature, can provide only reasonable assurance regarding management's control objectives.
With the participation of management, our chief executive officer and chief financial officer evaluated the effectiveness of the design and operation of our disclosure controls and procedures at the conclusion of the period ended June 30, 2005. Based upon this evaluation, the chief executive officer and chief financial officer concluded that our disclosure controls and procedures were effective in ensuring that material information required to be disclosed is included in the reports that it files with the Securities and Exchange Commission.
Changes in Internal Controls ----------------------------
There were no significant changes in our internal controls or, to the knowledge of our management, in other factors that could significantly affect internal controls subsequent to the date of the most recent evaluation of our disclosure controls and procedures utilized to compile information included in this filing.
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. 60 Chairman of the Board, May 1987 to Present Secretary, and a Director
Roger A. Parker 43 President, Chief May 1987 to Present Executive Officer and a Director
Jerrie F. Eckelberger 61 Director September 1996 to Present
Kevin K. Nanke 40 Treasurer and Chief December 1999 Financial Officer to Present
The following is biographical information as to the business experience of each of our current officers and directors.
Roger A. Parker has served as the President, Chief Executive Officer and a Director of both Amber and Delta since May of 1987, and as the Chief Executive Officer of both corporations since April of 2002. Since April 1, 2005 he has also served as a Director of DHS Drilling Company, which is an affiliate of Delta. 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 is a board member of the Independent Producers Association of the Mountain States (IPAMS). He also serves on other boards, including Community Banks of Colorado.
Jerrie F. Eckelberger 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 been engaged in the private practice of law 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 engaged in the investment and development of Colorado real estate through several private companies in which he is a principal.
Aleron H. Larson, Jr. has operated as an independent in the oil and gas industry individually and through public and private ventures since 1978. Mr. Larson serves as our Chairman of the Board, Secretary and a Director, and as a Director and Secretary of Delta. 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.
Kevin K. Nanke has served as the Treasurer and Chief Financial Officer of both Amber and Delta since April, 1995. Since April 1, 2005 he has also served as Chief Financial Officer, Treasurer and Director of DHS Drilling Company, which is an affiliate of Delta. 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.
Section 16(a) Beneficial Ownership Reporting Compliance -------------------------------------------------------
Based solely on a review of Forms 3 and 4 and amendments thereto furnished to us during our most recent fiscal year, and Forms 5 and amendments thereto furnished with respect to our most recent fiscal year and certain representations, no persons who were either a director, officer, or beneficial owner of more than 10% of the Company's common stock failed to file on a timely basis reports required by Section 16(a) of the Exchange Act during the most recent fiscal year.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
No officer or director received compensation directly from us during the years ended June 30, 2005, 2004 and 2003. 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) 370 17th Street, Suite 4300
Denver, Colorado 80202
Roger A. Parker 4,277,977 (1) 91.68% (1) 370 17th Street, Suite 4300 Denver, CO 80202
Aleron H. Larson, Jr. 4,277,977 (1) 91.68% (1) 25598 Foothills Drive North Golden, CO 80401
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) 370 17th Street, Suite 4300 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, Nanke and Eckleberger are either officers, directors or shareholders 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 may be cancelled 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, 2005, 2004 and 2003. We had receivables from Delta of $47,498 and $157,159 recorded as reductions in equity at June 30, 2005 and 2004, respectively.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
AUDIT FEES: The aggregate fees billed for professional services rendered by KPMG LLP for the audit of the annual financial statements of the Company for the fiscal year ended June 30, 2005 and the review of the financial statements included in the Company's Forms 10-Q for such fiscal year were paid by Delta, our parent, pursuant to our agreement under which we pay Delta $25,000 per quarter. (See Item 13. Certain Relationships and Related Transactions.)
AUDIT RELATED FEES: None
TAX FEES: None.
ALL OTHER FEES: None.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) (1) Financial Statements --------------------
Independent auditors' reports
Balance Sheets as of June 30, 2005 and 2004
Statements of Operations and Accumulated Deficit Years Ended June 30, 2005, 2004 and 2003
Statements of Cash Flows Years Ended June 30, 2005, 2004 and 2003
Notes to Financial Statements
(a) (2) Financial Statement Schedules -----------------------------
None
(a) (3) Exhibits --------
The Exhibits listed in the Index to Exhibits appearing at page 26 are filed as part of this report. Management contracts and compensatory plans required to be filed as exhibits are marked with an "*."
INDEX TO EXHIBITS
(2) Plan of Acquisitions, Reorganization, Arrangement, Liquidation, or Succession. Not applicable.
(3) Articles of Incorporation and Bylaws.
3.1 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 incorporated by reference to Exhibits 3.1 and 3.2 to the Company's Form 10-KSB for the fiscal year ended June 30, 1997.
3.2 Certificate for Renewal and Revival of Charter. Incorporated by reference from Exhibit 3.2 of the Company's Form 10-K for the fiscal year ended June 30, 2003.
(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. Incorporated by reference to Exhibit 10.4 to the Company's Form 10-K for the fiscal year ended June 30, 2002.
(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.
(31) Rule 13a-14(a)/15d-14(a) Certifications.
31.1 Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.
31.2 Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. Filed herewith electronically.
(32) Section 1350 Certifications.
32.1 Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.
32.2 Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350. Filed herewith electronically.
(99) Additional Exhibits. Not applicable.
- -------------------
* Management contracts and compensatory plans.
Report of Independent Registered Public Accounting Firm
The Board of Directors Amber Resources Company of Colorado:
We have audited the accompanying balance sheets of Amber Resources Company of Colorado, formerly named Amber Resources Company (the "Company"), a subsidiary of Delta Petroleum Corporation, as of June 30, 2005 and 2004 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, 2005. 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 standards of the Public Company Accounting Oversight Board (United States). 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 of Colorado as of June 30, 2005 and 2004, and the results of its operations and its cash flows for each of the years in the three-year period ended June 30, 2005, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP KPMG LLP
Denver, Colorado September 26, 2005
AMBER RESOURCES COMPANY OF COLORADO BALANCE SHEETS June 30, 2005 and 2004 - -----------------------------------------------------------------------------
2005 2004 --------- ---------- ASSETS
Current Assets: Cash $ - $ 579 --------- --------- Total current assets - 579 --------- --------- Property and Equipment: Oil and gas properties, at cost (using the successful efforts method of accounting): Undeveloped offshore California properties 5,006,560 5,006,560 ---------- ---------- $5,006,560 $5,007,139 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY
Liabilities: $ - $ - ---------- ---------- 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, 2005 and 2004 291,637 291,637 Additional paid in capital 5,755,232 5,755,232 Accumulated deficit (992,811) (882,571)
Advance to parent (47,498) (157,159) ---------- ---------- Total stockholders' equity 5,006,560 5,007,139 ---------- ---------- Commitments $5,006,560 $5,007,139 ========== ==========
See accompanying notes to consolidated financial statements.
AMBER RESOURCES COMPANY OF COLORADO STATEMENTS OF OPERATIONS AND ACCUMULATED DEFICIT Years Ended June 30, 2005, 2004 and 2003 - -----------------------------------------------------------------------------
Years Ended June 30, 2005 2004 2003 --------- --------- ---------
Revenue: Oil and gas sales $ - $ - $ - --------- --------- ---------
Total revenue - - -
Operating expenses: Exploration expenses 235 1,441 - General and administrative, including $100,000 in 2005, 2004 and 2003 to parent 110,005 107,867 128,936 --------- --------- --------- Total operating expenses 110,240 109,308 128,936 --------- --------- ---------
Loss from Operations (110,240) (109,308) (128,936)
Other income - - 2 --------- --------- ---------
Net Loss (110,240) (109,308) (128,934)
Accumulated deficit at beginning of the year (882,571) (773,263) (644,329) --------- --------- --------- Accumulated deficit at end of the year $(992,811) $(882,571) $(773,263) ========= ========= =========
Basic loss per share $ (0.02) $ (0.02) $ (0.03) ========= ========= =========
Weighted average number of common shares outstanding 4,666,185 4,666,185 4,666,185 ========= ========= =========
See accompanying notes to consolidated financial statements.
AMBER RESOURCES COMPANY OF COLORADO STATEMENTS OF CASH FLOWS Years Ended June 30, 2005, 2004 and 2003 - -----------------------------------------------------------------------------
Years Ended June 30, 2005 2004 2003 --------- --------- ---------
Cash flows from operating activities: Net loss $(110,240) $(109,308) $(128,934)
Net changes in operating assets and operating liabilities: Decrease in accounts payable trade - - (2,912) --------- --------- --------- Net cash used in operating activities (110,240) (109,308) (131,846) --------- --------- ---------
Cash flows from investing activities - Additions to property and equipment, net - - (284) --------- --------- --------- Net Cash used in investing activities - - (284)
Cash flows from financing activities - Changes in accounts receivable from and accounts payable to parent 109,661 109 020 132,216 --------- --------- --------- Net increase (decrease) in cash (579) (288) 186 --------- --------- ---------
Cash at beginning of period 579 867 681 --------- --------- ---------
Cash at end of period $ - $ 579 $ 867 ========= ========= =========
See accompanying notes to consolidated financial statements.
AMBER RESOURCES COMPANY OF COLORADO (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2005 and 2004 - -----------------------------------------------------------------------------
(1) Summary of Significant Accounting Policies
Organization
Amber Resources Company of Colorado, formerly 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, 2005 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. The Company's remaining properties are all undeveloped offshore California properties, the development of which is currently being delayed by litigation with the US Government. 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 obligations 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, if necessary. However, there can be no assurance that such financing would be available in a timely fashion or on acceptable terms.
Revenue Recognition
The Company uses the sales method of accounting for oil and gas revenues. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers.
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.
AMBER RESOURCES COMPANY OF COLORADO (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2005 and 2004 - -----------------------------------------------------------------------------
(1) Summary of Significant Accounting Policies, Continued
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.
Impairment of Long Lived Assets
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets." SFAS 144 establishes a single accounting model for long-lived assets to be disposed of by sale and requires that those long-lived assets be measured at the lower of carrying amount or fair value less cost to sell, whether reported in continuing operations or in discontinued operations.
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.
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.
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.
AMBER RESOURCES COMPANY OF COLORADO (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2005 and 2004 - ----------------------------------------------------------------------------
(1) Summary of Significant Accounting Policies, Continued
Recently Issued Accounting Standards and Pronouncements
In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error CorrectionsCa replacement of APB Opinion No. 20 and FASB Statement No. 3 ("Statement 154"). SFAS 154 requires retrospective application to prior periods= financial statements for changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, non-financial assets be accounted for as a change in accounting estimate affected by a change in accounting principle. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The implementation of FAS 154 is not expected to have a material impact on the Company's consolidated results of operations, financial position or cash flows.
In December 2004, the FASB issued its final standard on accounting for employee stock options, FAS No. 123 (Revised 2004), "Share-Based Payment" ("FAS123(R)"). FAS 123(R) replaces FAS No. 123, "Accounting for Stock-Based Compensation" ("FAS 123"), and supersedes Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." FAS 123(R) requires companies to measure compensation costs for all share-based payments, including grants of employee stock options, based on the fair value of the awards on the grant date and to recognize such expense over the period during which an employee is required to provide services in exchange for the award. The pro forma disclosures previously permitted under FAS 123 will no longer be an alternative to financial statement recognition. FAS 123(R) is effective for all awards granted, modified, repurchased or cancelled after, and to unvested portions of previously issued and outstanding awards vesting after, interim or annual periods, beginning after June 15, 2005, which for us will be the first quarter of fiscal 2006. The Company is currently evaluating the effect of adopting FAS 123(R) on its financial position and results of operations, and have not yet determined whether the adoption of FAS 123(R) will result in expenses in amounts that are similar to the current pro forma disclosures under FAS 123.
AMBER RESOURCES COMPANY OF COLORADO (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2005 and 2004 - -----------------------------------------------------------------------------
(2) Oil and Gas Properties
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 $5,006,560 on June 30, 2005 and 2004. These property interests are located in proximity to existing producing federal offshore units near Santa Barbara, California and represent the right to explore for, develop and produce oil and gas from offshore federal lease units. Preliminary exploration efforts on these properties have occurred and the existence of substantial quantities of hydrocarbons has been indicated. The recovery of the Company's investment in these properties will require extensive exploration and development activities (and costs) that cannot proceed without certain regulatory approvals that have been delayed and is subject to other substantial risks and uncertainties as discussed herein.
The Company is not the designated operator of any of these properties but is an active participant in the ongoing activities of each property along with the designated operator and other interest owners. If the designated operator elected not to or was unable to continue as the operator, the other property interest owners would have the right to designate a new operator as well as share in additional property returns prior to the replaced operator being able to receive returns. Based on the Company's size, it would be difficult for the Company to proceed with exploration and development plans should other substantial interest owners elect not to proceed. However, to the best of its knowledge, the Company believes the designated operators and other major property interest owners intend to proceed with exploration and development plans under the terms and conditions of the operating agreement.
On June 22, 2001, however, a Federal Court in the case of California v. Norton, et al. ruled that the Minerals Management Services (MMS) does not have the power to grant suspensions on the subject leases without first making a consistency determination under the Coastal Zone Management Act ("CZMA"), and ordered the MMS to set aside its approval of the suspensions of the Company's offshore leases and to direct suspensions for a time sufficient for the MMS to provide the State of California with the required consistency determination. No such consistency determination has as yet been made.
The ownership rights in each of these properties have been retained under various suspension notices issued by the MMS of the U.S. Federal Government whereby as long as the owners of each property were progressing toward defined milestone objectives, the owners' rights with respect to the properties continue to be maintained. The issuance of the suspension notices has been necessitated by the numerous delays in the exploration and development process resulting from regulatory requirements imposed on the property owners by federal, state and local agencies.
AMBER RESOURCES COMPANY OF COLORADO (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2005 and 2004 - -----------------------------------------------------------------------------
(2) Oil and Gas Properties, Continued
The delays have prevented the property owners from submitting for approval an exploration plan on four of the properties. If and when plans are submitted for approval, they are subject to review for consistency with the California Coastal Zone Management Planning (CZMP) and by the MMS for other technical requirements.
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.
Based on the preliminary indicated levels of hydrocarbons present from drilling operations conducted in the past, the Company believes the fair value of its property interests are in excess of their carrying value at June 30, 2005 and June 30, 2004 and that no impairment in the carrying value has occurred. Should the required regulatory approvals not be obtained or plans for exploration and development of the properties not continue, the carrying value of the properties would likely be impaired and written off.
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 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.
As the ruling in the Norton case currently stands, the United States has been ordered to make a consistency determination under the CZMA, but the leases are still valid. If the leases are found not to be valid for some reason, or if the United States either does not comply with the order requiring it to make a consistency determination or finds that development is inconsistent with the CZMA, 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 that would cause the leases to become impaired, and we will continuously evaluate those factors as they occur.
AMBER RESOURCES COMPANY OF COLORADO (A subsidiary of Delta Petroleum Corporation) Notes to Consolidated Financial Statements June 30, 2005, 2004 and 2003 - -----------------------------------------------------------------------------
(2) Oil and Gas Properties, Continued
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 CZMA 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 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 the event, however, that we receive any proceeds as the result of such litigation, we may be obligated to pay a portion of any amount received by us to landowners and other owners of royalties and similar interests, and to pay expenses of litigation and to fulfill certain pre-existing contractual commitments to third parties.
(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, 2005 and 2004, no preferred stock was issued and outstanding.
AMBER RESOURCES COMPANY OF COLORADO (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2005 and 2004 - -----------------------------------------------------------------------------
(4) Income Taxes
At June 30, 2005, 2004 and 2003, the Company's significant deferred tax assets and liabilities are summarized as follows:
2005 2004 2003 ---- ---- ---- Deferred tax assets: Net operating loss Carryforwards $ 402,521 $ 503,000 $ 765,000 --------- --------- --------- Gross deferred tax assets 402,521 503,000 765,000
Less valuation allowance (402,521) (503,000) (765,000) --------- --------- --------- Net deferred tax asset $ - $ - $ - ========= ========= =========
Delta accounts for income tax in accordance with the provisions of Statement of Financial Standards No. 109, "Accounting for Income Taxes" ("SFAS" 109) and includes Amber's attributes in calculating its tax calculations. The Company is consolidated in Delta's income tax return and accounts for its income tax as if it filed a separate return.
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences, net of the existing valuation allowances at June 30, 2005.
At June 30, 2005, the Company had net operating loss carryforwards for regular and alternative minimum tax purposes of approximately $1,048,000. If not utilized, the tax net operating loss carryforwards will expire as follows:
Amount Year of Expiration -------- ------------------
$ 73,000 2006 - 2007 15,000 2008 - 2009 960,000 2010
AMBER RESOURCES COMPANY OF COLORADO (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2005 and 2004 - -----------------------------------------------------------------------------
(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 its 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 the Company for the provision of services by Delta were $100,000 for the year ended June 30, 2005, 2004 and 2003. The Company had a non-interest bearing receivable from Delta of $47,498 and $157,159 recorded as a reduction in equity at June 30, 2005 and 2004, respectively.
(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, 2005 2004 ----------- ----------- Undeveloped offshore California properties $ 5,006,560 $ 5,006,560 =========== ===========
Costs incurred in oil and gas producing activities for the years ended June 30, 2005, 2004 and 2003 are as follows:
2005 2004 2003 ---- ---- ---- Unproved property acquisition costs $ - $ - $ 284 Exploration costs $ 235 $1,441 $ -
A summary of the results of operations for oil and gas producing activities, excluding general and administrative cost, for the years ended June 30, 2005, 2004 and 2003 is as follows:
2005 2004 2003 ---- ---- ---- Revenue: Oil and gas sales $ - $ - $ - Expenses: Lease operating - - - Depletion - - - Exploration 235 1,441 - ------ ------ ------ Results of operations of oil Gas producing activities $ (235) $(1,441) $ - ======= ======== =======
AMBER RESOURCES COMPANY OF COLORADO (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years ended June 30, 2005, 2004 and 2003 - -----------------------------------------------------------------------------
(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.
The Company had sold its producing properties at the beginning of fiscal year 2002. There were no customers in 2005 and 2004.
(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.
AMBER RESOURCES COMPANY OF COLORADO (A subsidiary of Delta Petroleum Corporation) Notes to Financial Statements Years Ended June 30, 2005 and 2004 - -----------------------------------------------------------------------------
(7) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued
(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in underlaid prospects; and (D)crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.
Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.
Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled.
Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.
The Company sold all its producing properties to Delta on July 1, 2001. As such, no reserve estimates were prepared for the past three years.
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 13th day of October, 2005
AMBER RESOURCES COMPANY OF COLORADO
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 ------------------- ----
/s/ Aleron H. Larson, Jr. October 13, 2005 - --------------------------------------- Aleron H. Larson, Jr., Director
/s/ Roger A. Parker October 13, 2005 - --------------------------------------- Roger A. Parker, Director
/s/ Jerrie F. Eckelberger October 13, 2005 - --------------------------------------- Jerrie F. Eckelberger, Director