UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

[x] Annual Report under Section 13 or 15(d) of the Securities Exchange Act of
1934 for the fiscal year ended June 30, 2003
or
[ ] Transition Report under Section 13 or 15(d) of the Securities Exchange Act
of 1934 for the transition period _____________________.

Commission File No. 0-8874

AMBER RESOURCES COMPANY OF COLORADO
(FORMERLY NAMED AMBER RESOURCES COMPANY)
(Exact name of registrant as specified in its charter)

Delaware 84-0750506
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)

Suite 1400, 475 Seventeenth Street, Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (303) 293-9133

Securities registered pursuant to Section 12(b) of the Exchange Act: None

Securities registered pursuant to Section 12(g) of the Exchange Act:

Common Stock, $.0625 par value (Title of Class)

Check whether issuer (1) has filed all reports required to be filed by Section
13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12
months (or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements for the
past 90 days. Yes [X] No [ ]

Check if there is no disclosure of delinquent filers in response to Item 405
of Regulation S-K contained in this form, and no disclosure will be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]

Indicate by a check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act) [ ]Yes [X] No

The aggregate market value as of the Company's voting stock held by non-
affiliates of the Company as of September 26, 2003 could not be determined
because there is no established public trading market.

As of September 26, 2003, 4,666,185 shares of registrant's Common Stock $.0625
par value were issued and outstanding.

The Index to Exhibits appears at Page 36

TABLE OF CONTENTS

PART I

PAGE

ITEM 1. DESCRIPTION OF BUSINESS .................................... 3
ITEM 2. DESCRIPTION OF PROPERTIES................................... 7
ITEM 3. LEGAL PROCEEDINGS .......................................... 22
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ........ 23

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS ........................................ 23
ITEM 6. SELECTED FINANCIAL DATA .................................... 24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS .................................. 24
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK .. 30
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ................ 30
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE ..................... 30
ITEM 9A. CONTROLS AND PROCEDURES..................................... 30

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ......... 31
ITEM 11. EXECUTIVE COMPENSATION ..................................... 33
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT ............................................. 33
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ............. 34
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES ..................... 34

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K ................................................ 35

The terms "Amber," "Company," "we," "our," and "us" refer to Amber
Resources Company of Colorado and its subsidiaries unless the context suggests
otherwise.

CAUTIONARY STATEMENT FOR PURPOSES OF THE PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995 AND OTHER FEDERAL SECURITIES LAWS

GENERAL. We are including the following discussion to inform our existing
and potential security holders generally of some of the risks and
uncertainties that can affect us and to take advantage of the "safe harbor"
protection for forward-looking statements afforded under federal securities
laws. From time to time, our management or persons acting on our behalf make
forward-looking statements to inform existing and potential security holders
about us. These statements may include projections and estimates concerning
the timing and success of specific projects and our future (1) income, (2) oil
and gas production, and (3)capital spending. Forward-looking statements are
generally accompanied by words such as "estimate," "project," "predict,"
"believe," "expect," "anticipate," "plan," "goal" or other words that convey
the uncertainty of future events or outcomes. Sometimes we will specifically
describe a statement as being a forward-looking statement. In addition,
except for the historical information contained in this report, the matters
discussed in this report are forward-looking statements. These statements by
their nature are subject to certain risks, uncertainties and assumptions and
will be influenced by various factors. Should any of the assumptions
underlying a forward-looking statement prove incorrect, actual results could
vary materially.

We believe the factors discussed below are important factors that could
cause actual results to differ materially from those expressed in a forward-
looking statement made herein or elsewhere by us or on our behalf. The factors
listed below are not necessarily all of the important factors. Unpredictable
or unknown factors not discussed herein could also have material adverse
effects on actual results of matters that are the subject of forward-looking
statements. We do not intend to update our description of important factors
each time a potential important factor arises. We advise our shareholders
that they should (1) be aware that important factors not described below could
affect the accuracy of our forward-looking statements and (2) use caution and
common sense when analyzing our forward-looking statements in this document or
elsewhere, and all of such forward-looking statements are qualified by this
cautionary statement.

- Historically, natural gas and crude oil prices have been volatile.
These prices rise and fall based on changes in market demand and
changes in the political, regulatory and economic climate and
other factors that affect commodities markets generally and are
outside of our control.

- Projecting future rates of oil and gas production is inherently
imprecise. Producing oil and gas reservoirs generally have
declining production rates.

- Changes in the legal, political and/or regulatory environment
could have a material adverse effect on our future results of
operations and financial condition. Our ability to economically
produce and sell any future oil and gas production may be affected
and could possibly be restrained by a number of legal, political
and regulatory factors, particularly with respect to our offshore
California properties which are the subject of significant
political controversy due to environmental concerns.

- Our drilling operations are subject to various risks common in the
industry, including cratering, explosions, fires and
uncontrollable flows of oil, gas or well fluids.

PART I

ITEM 1. DESCRIPTION OF BUSINESS

(a) Business Development

Amber Resources Company of Colorado, formerly named "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, 2003, 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 $107,045 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 herein.)

In June 2003, we applied for and received a reinstatement of our charter
with the State of Delaware which had been voided. In connection with our
reinstatement, we were required to change our name to "Amber Resources Company
of Colorado." This was due to the fact that our prior name was taken by
another company during the period our charter was void.

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, 2003, 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, 2003, 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, 2003, 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 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 Minerals Management
Service of the United States Department of the Interior ("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 our inception, we have 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 our operation
since our inception. In addition, we do not anticipate that such expenditures
will be material during the fiscal year ending June 30, 2004.

(12) Employees. We have no full time employees.

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. No reserves estimates were prepared for the past
two 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.

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 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 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.
In the event, however, 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.

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.

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 pre-development, 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.

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 $3,170,886, 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 (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.

On January 9, 2002, we filed a lawsuit against the U.S. government along
with several other companies alleging that the government breached the terms
of some of our undeveloped, offshore California properties. See "Legal
Proceedings."

- --------------

map insert

- --------------

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, 2003 June 30, 2002 June 30, 2001
------------- ------------- -------------
Average sales price:
Oil (per barrel) $ - $ - $29.61
Natural Gas (per Mcf) - - 4.85
Production costs (per
Mcf equivalent) - - 1.96

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, 2003 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, 2003, 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, 2003, we did not participate in any
drilling activities.

ITEM 3. LEGAL PROCEEDINGS

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.

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. 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 2003 and
2002 have not been available.

(b) Approximate Number of Holders of Common Stock
---------------------------------------------

The number of holders of record of our securities at September 26, 2003
was approximately 1,000.

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, 2003, we did not have any sale of
securities that were not registered under the Securities Act of 1933, as
amended.

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial information should be read in
conjunction with our financial statements and the accompanying notes.

Fiscal Years Ended June 30,
--------------------------------------------------------------------------------
2003 2002 2001 2000 1999
---- ---- ---- ---- ----

Total Revenues $ - $ 73,960 $ 119,405 $ 100,245 $ 989,390
Income/(Loss) from
Operations $(128,936) $ (54,622) $ (42,648) $ (67,494) $ 659,149
Income/(Loss)
Per Share $ (0.03) $ (0.01) $ * $ (0.01) $ 0.14
Total Assets $5,007,427 $5,006,957 $5,062,208 $5,050,869 $5,059,825
Total Liabilities $ - $ 2,912 $ 16,532 $ 64,565 $ 134,020
Stockholders' Equity $5,007,427 $5,004,045 $5,045,676 $4,986,304 $4,925,805
Total Long Term Debt $ - $ - $ - $ - $ -
____________________
* Less than $0.01 per share.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND PLAN
OF OPERATIONS

Liquidity and Capital Resources
-------------------------------

At June 30, 2003, we had working capital of $867 compared to a working
capital deficit of $2,231 at June 30, 2002. The cash used in operating
activities of $131,846 during fiscal 2003 remained consistent with fiscal
2002. 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 $266,179
at June 30, 2003 from Delta. If necessary, Delta will repay its obligation to
the Company to meet Amber's operating needs and obligations for costs incurred
with 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 2003 Versus 2002
-----------------------------------------------

Net Income. Our net losses for the years ended June 30, 2003 and 2002
were $128,934 and $46,765 respectively.

Revenue. Total revenue for the year ended June 30, 2003 was zero
compared to $73,960 for the year ended June 30, 2002. Oil and gas sales for
both years were zero as we sold all of our producing properties on July 1,
2001.

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 the properties to a third party.

Production volumes and average prices received for the years ended June
30, 2003 and 2002. Production was zero for both periods as we sold our
onshore producing properties on July 1, 2002.

Lease Operating Expenses. Lease operating expenses for the years ended
June 30, 2003 and June 30, 2002 both were zero as we sold all of our producing
properties.

Depletion Expense. There was no depletion in either year 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 zero and $19,772 for the years ended June 30,
2003 and 2002, respectively.

General and Administrative Expenses. General and administrative expense
for the year ended June 30, 2003 was $128,936 compared to $108,810 for the
year ended June 30, 2002. The increase in general and administrative expense
was due to additional filing and recording fees incurred during fiscal 2003.

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 $73,960
compared to $119,405 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. The decrease in oil and gas sales for the year ended June 30,
2002 compared to the year ended June 30, 2001 is attributable to the sale of
our producing properties on July 1, 2001.

Other Revenue. Other revenue includes amounts recognized from the
production of gas previously deferred pending determination of our interest in
the properties. We recognized zero in fiscal 2002 and $51,667 in fiscal 2001.

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 expense for the year ended
June 30, 2002 was zero compared to $22,827 for the year ended June 30, 2001.
On an MCF equivalent basis production expenses and taxes were zero for the
year ended June 30, 2002 and $1.64 per Mcf equivalent for the year ended June
30, 2001.

Depletion Expense. Depletion expense for the year ended June 30, 2002
was zero compared to $10,608 for the year ended June 30, 2001.

Exploration Expenses. Exploration expenses consist of geological and
geophysical costs and lease rentals. 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.

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, 2003, 2002 or 2001.

Recently Issued or Proposed Accounting Standards and Pronouncements
--------------------------------------------------------------------

We have been made aware that an issue has arisen within the industry
regarding the application of provisions of SFAS No. 142 and SFAS No. 141,
"Business Combinations," to companies in the extractive industries, including
oil and gas companies. The issue is whether SFAS No. 142 requires companies to
reclassify costs associated with mineral rights, including both proved and
unproved leasehold acquisition costs, as intangible assets in the balance
sheet, apart from other capitalized oil and gas property costs. Historically,
we and other oil and gas companies have included the cost of these oil and gas
leasehold interests as part of oil and gas properties. Also under
consideration is whether SFAS No. 142 requires registrants to provide the
additional disclosures prescribed by SFAS No. 142 for intangible assets for
costs associated with mineral rights.

If it is ultimately determined that SFAS No. 142 requires us to
reclassify costs associated with mineral rights from property and equipment to
intangible assets, the amounts that would be reclassified are as follows:

June 30,
2003 2002
----------- -----------
INTANGIBLE ASSETS:
Proved leasehold acquisition costs $ - $ -
Unproved leasehold acquisition costs 5,006,560 5,006,276
----------- -----------
Total leasehold acquisition costs 5,006,560 5,006,276

Less: Accumulated depletion - -
----------- -----------
Net leasehold acquisition costs $ 5,006,560 $ 5,006,276
----------- -----------

The reclassification of these amounts would not affect the method in
which such costs are amortized or the manner in which we assess impairment of
capitalized costs. As a result, net income would not be affected by the
reclassification.

Statement 145, Rescission 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 this statement will have a material impact on our Financial
Statements.

In November 2002, the FASB issued Financial Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others - an interpretation of FASB
Statements Nos. 5, 57, and 107 and rescission of FASB Interpretation No. 34"
("FIN 45"). FIN 45 elaborates on the disclosures to be made by a guarantor in
its interim and annual financial statements about its obligations under
certain guarantees that it has issued. It also clarifies that a guarantor is
required to recognize, at the inception of a guarantee, a liability for the
fair value of the obligation undertaken in issuing the guarantee. The initial
recognition and initial measurement provisions of FIN 45 are applicable on a
prospective basis to guarantees issued or modified after December 31, 2002,
irrespective of the guarantor's fiscal year-end. The disclosure requirements
are effective for financial statements of interim or annual periods ending
after December 15, 2002. The adoption of FIN 45 has not had any effect on our
financial position or results of operations.

In January 2003, the FASB issued Financial Interpretation No. 46,
"Consolidation of Variable Interest Entities - an interpretation of ARB No.
51" ("FIN 46"). FIN 46 is an interpretation of Accounting Research Bulletin
51, "Consolidated Financial Statements," and addresses consolidation by
business enterprises of variable interest entities ("VIE's"). The primary
objective of FIN 46 is to provide guidance on the identification of, and
financial reporting for, entities over which control is achieved through means
other than voting rights. Such entities are known as VIE's. FIN 46 requires an
enterprise to consolidate a VIE if that enterprise has a variable interest
that will absorb a majority of the entity's expected losses if they occur,
receive a majority of the entity's expected residual returns if they occur, or
both.

An enterprise shall consider the rights and obligations conveyed by its
variable interests in making this determination. This guidance applies
immediately to variable interest entities created after January 31, 2003, and
to variable interest entities in which an enterprise obtains an interest after
that date. It applies in the first fiscal year or interim period beginning
after June 15, 2003 to variable interest entities in which an enterprise holds

a variable interest that it acquired before February 1, 2003. At this time, we
do not have a VIE.

In April 2003, FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities under SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities." SFAS No. 149 is effective for contracts entered into
or modified after June 30, 2003 and for hedging relationships designated after
June 30, 2003. We adopted SFAS No. 149 on July 1, 2003 and do not expect it
to have a material impact on our financial condition and results of
operations.

In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics of Both Liabilities and Equity."
SFAS No. 150 changes the accounting for certain financial instruments that,
under previous guidance, issuers could account for as equity. FASB No. 150
requires that those instruments be classified as liabilities in statements of
financial position. SFAS No. 150 is effective for financial instruments
entered into or modified after May 31, 2003, and otherwise is effective at the
beginning of the first interim period beginning after June 15, 2003. SFAS No.
150 is not expected to have a material impact on our financial condition and
results of operations.

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. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial Statements are included beginning on Page F-1. 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. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

Not applicable.

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, 2003. 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 most recent evaluation of our
disclosure controls and procedures utilized to compile information included in
this filing.

PART III

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. 58 Chairman of the Board, May 1987 to Present
Secretary, and a Director

Roger A. Parker 41 President, Chief May 1987 to Present
Executive Officer and
a Director

Jerrie F. Eckelberger 59 Director September 1996
to Present

Kevin K. Nanke 38 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. 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 of Colorado ("Amber"), as well as Delta, which is
our majority shareholder/parent. 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 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 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, 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.

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. EXECUTIVE COMPENSATION

No officer or director received compensation directly from us during the
years ended June 30, 2003, 2002 and 2001. 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. 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, Nanke and
Eckleberger are either officers, directors or shareholders of Delta.

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 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, 2003, 2002 and 2001. We had a receivable from Delta of $266,179 and
$398,495 recorded as a reduction in equity at June 30, 2003 and 2002,
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 $107,045 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 third party, 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.

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, 2003 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.)

FINANCIAL INFORMATION SYSTEMS DESIGN AND IMPLEMENTATION FEES: No fees
were billed for professional services rendered by KPMG LLP for financial
information systems design and implementation services for the fiscal year
ended June 30, 2003.

ALL OTHER FEES: No fees were billed for services rendered by KPMG LLP,
other than the services referred to above, for the fiscal year ended June 30,
2003.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) Financial Statements
--------------------

Independent auditors' report F-1

Balance Sheet as of June 30, 2003 and 2002 F-2

Statements of Operations and Accumulated Deficit
Years Ended June 30, 2003, 2002 and 2001 F-3

Statements of Cash Flows F-4

Notes to Financial Statements F-5

Financial Statement Schedules
-----------------------------

None

(b) Reports on Form 8-K
-------------------

None

The Exhibits listed in the Index to Exhibits appearing at page 36 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.

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. Filed
herewith electronically.

(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.

Independent Auditors' Report

The Board of Directors and Stockholders
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, 2003 and 2002 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, 2003. 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 of
Colorado as of June 30, 2003 and 2002, and the results of its operations and
its cash flows for each of the years in the three-year period ended June 30,
2003, in conformity with accounting principles generally accepted in the
United States of America.

KPMG LLP

Denver, Colorado
August 22, 2003

F-1

AMBER RESOURCES COMPANY OF COLORADO
BALANCE SHEETS
June 30, 2003 and 2002
- -----------------------------------------------------------------------------

2003 2002
--------- ----------
ASSETS

Current Assets:
Cash $ 867 $ 681
--------- ----------
Total current assets $ 867 $ 681
--------- ----------
Property and Equipment:
Oil and gas properties, at cost (using
the successful efforts method
of accounting):
Undeveloped offshore California properties $5,006,560 $5,006,276
---------- ----------
$5,007,427 $5,006,957
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities:
Accounts payable $ - $ 2,912
---------- ----------
Total current liabilities $ - $ 2,912
---------- ----------
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, 2003 and 2002 $ 291,637 $ 291,637
Additional paid-in capital $5,755,232 $5,755,232
Accumulated deficit $ (773,263) $ (644,329)
Advance to parent $ (266,179) $ (398,495)
---------- ----------
Total stockholders' equity $5,007,427 $5,004,045
---------- ----------
Commitments
$5,007,427 $5,006,957
========== ==========

See accompanying notes to consolidated financial statements.

F-2

AMBER RESOURCES COMPANY OF COLORADO
STATEMENTS OF OPERATIONS AND ACCUMULATED DEFICIT
Years Ended June 30, 2003, 2002 and 2001
- -----------------------------------------------------------------------------

Year Ended June 30
2003 2002 2001
--------- --------- ---------

Revenue:
Oil and gas sales $ - $ - $ 67,738
Gain on sale of oil and gas properties - 73,960 -
Other revenue - - 51,667
--------- ---------- ----------
Total revenue $ - 73,960 119,405

Operating expenses:
Lease operating expenses - - 22,827
Depreciation and depletion - - 10,608
Exploration expenses - 19,772 17,482
General and administrative, including
$100,000 in 2003, 2002 and 2001 to parent 128,936 108,810 111,136
--------- ---------- ----------
Total operating expenses 128,936 128,582 162,053
--------- ---------- ----------

Loss from Operations (128,936) (54,622) (42,648)

Other Income:
Other income 2 7,857 20

--------- ---------- ----------

Net Loss (128,934) (46,765) (42,628)

Accumulated deficit at
beginning of the year (644,329) (597,564) (554,936)
--------- ---------- ----------
Accumulated deficit at
end of the year $ (773,263) $ (644,329) $ (597,564)
========== ========== ==========

Basic loss per share $ (0.03) $ (0.01) $ *
========== ========== ==========
Weighted average number of common
shares outstanding $4,666,185 4,666,185 4,666,185
========== ========== ==========

*loss per share is less than $0.01

See accompanying notes to consolidated financial statements.

F-3

AMBER RESOURCES COMPANY OF COLORADO
STATEMENTS OF CASH FLOWS
Years Ended June 30, 2003, 2002 and 2001
- -----------------------------------------------------------------------------

Year Ended June 30
2003 2002 2001
--------- --------- ---------

Cash flows from operating activities:
Net loss $(128,934) $ (46,765) $ (42,628)
Adjustments to reconcile net loss to cash
used in operating activities:
Gain on sale of oil and gas properties - (73,960) -
Depletion - - 10,608
Net changes in operating assets and operating
liabilities:
(Increase) decrease in trade accounts receivable - 7,855 (4,855)
Increase (decrease) in accounts payable trade (2,912) (13,620) 3,634
Deferred revenue - - (51,667)
--------- --------- ---------

Net cash used in operating activities (131,846) (126,490) (84,908)
--------- --------- ---------
Cash flows from investing activities-
Additions to property and equipment, net (284) - (7,522)
Proceeds from sale of oil and gas properties - 107,045 -
--------- --------- ---------
Net Cash used in investing activities (284) 107,045 (7,522)

Cash flows from financing activities-
Changes in accounts receivable from and
accounts payable to parent 132,316 5,135 102,000
--------- --------- ---------

Net increase (decrease) in cash 186 (14,311) 9,570
--------- --------- ---------

Cash at beginning of period 681 14,992 5,422
--------- --------- ---------

Cash at end of period $ 867 $ 681 $ 14,992
--------- --------- ---------

See accompanying notes to consolidated financial statements.

F-4

AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Years Ended June 30, 2003 and 2002
- -----------------------------------------------------------------------------

(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, 2003, 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 $107,045 an amount
equal to the properties net present value discounted at 10% as determined by
third party independent 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.

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.

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.

F-5

(1) Summary of Significant Accounting Policies, Continued

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 No. 144 supersedes SFAS
No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-
Lived Assets to Be Disposed Of." 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.

F-6

(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

The Company has been made aware that an issue has arisen within the
industry regarding the application of provisions of SFAS No. 142 and SFAS No.
141, "Business Combinations," to companies in the extractive industries,
including oil and gas companies. The issue is whether SFAS No. 142 requires
registrants to reclassify costs associated with mineral rights, including both
proved and unproved leasehold acquisition costs, as intangible assets in the
balance sheet, apart from other capitalized oil and gas property costs.
Historically, the Company and other oil and gas companies have included the
cost of these oil and gas leasehold interests as part of oil and gas
properties. Also under consideration is whether SFAS No. 142 requires
registrants to provide the additional disclosures prescribed by SFAS No. 142
for intangible assets for costs associated with mineral rights.

If it is ultimately determined that SFAS No. 142 requires the Company to
reclassify costs associated with mineral rights from property and equipment to
intangible assets, the amounts that would be reclassified are as follows:

Less: Accumulated depletion - -
----------- -----------
Net leasehold acquisition costs $ 5,006,560 $ 5,006,276
----------- -----------

F-7

(1) Summary of Significant Accounting Policies, Continued

The reclassification of these amounts would not effect the method in
which such costs are amortized or the manner in which the Company assesses
impairment of capitalized costs. As a result, net income would not be affected
by the reclassification.

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.

F-8

(1) Summary of Significant Accounting Policies, Continued

Such entities are known as VIE's. FIN 46 requires an enterprise to
consolidate a VIE if that enterprise has a variable interest that will absorb
a majority of the entity's expected losses if they occur, receive a majority
of the entity's expected residual returns if they occur, or both.

It applies in the first fiscal year or interim period beginning after
June 15, 2003, to variable interest entities in which an enterprise holds a
variable interest that it acquired before February 1, 2003. At this time, the
Company does not have a VIE.

In April 2003, FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities." SFAS No. 149 amends and
clarifies financial accounting and reporting for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities under SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Activities." SFAS No. 149 is effective for contracts entered into
or modified after June 30, 2003 and for hedging relationships designated after
June 30, 2003. The Company adopted SFAS No. 149 on July 1, 2004 and does not
expect to have a material impact on the Company's financial condition and
results of operations.

F-9

(2) Oil and Gas Properties

On July 1, 2001, the Company sold all of its producing properties to
Delta Petroleum Corporation, our Parent, for $107,045. 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 $5,006,560 on June 30, 2003. 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. 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.

F-10

(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,
2003 and June 30, 2002 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 Coastal Zone
Management Act, 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 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 that would cause the leases to become impaired, and we will continuously
evaluate those factors as they occur.

F-11

AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Consolidated Financial Statements
June 30, 2003, 2002 and 2001
- -----------------------------------------------------------------------------

(2) Oil and Gas Properties, Continued

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, 2003 and 2002, no preferred stock was issued and outstanding.

F-12

(4) Income Taxes

At June 30, 2003 and 2002,the Company's significant deferred tax assets
and liabilities are summarized as follows:

2003 2002
---- ----
Deferred tax assets:
Net operating loss
carryforwards $ 765,000 $ 841,000

--------- ----------
Gross deferred tax assets 765,000 841,000

Less valuation allowance (765,000) (841,000)
--------- ----------
- -
Deferred tax liability:
Oil and gas properties,
principally due to differences
in basis and depreciation and
depletion - -
--------- ---------
Net deferred tax asset $ - $ -
========= =========

No income tax expense or benefit has been recorded for the years ended
June 30, 2003 and 2002 since the deferred income taxes that would have
otherwise been provided were offset by the change in the valuation allowance
for such 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, 2003, the Company had net operating loss carryforwards for
regular and alternative minimum tax purposes of approximately $2,020,000. If
not utilized, the tax net operating loss carryforwards will expire during the
period from 2004 through 2023. If not utilized, approximately $1.0 million of
net operating losses will expire over the next five years.

F-13

(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, 2003, 2002 and
2001. The Company had a non-interest bearing receivable from Delta of
$266,179 and $398,494 recorded as a reduction in equity at June 30, 2003 and
2002, respectively.

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 $107,045 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 third party
engineers. Management believes that the terms of this transaction were 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,
2003 2002
----------- -----------
Undeveloped offshore
California properties $ 5,006,560 $ 5,006,276
Developed onshore
domestic properties - -
----------- -----------
5,006,560 5,006,276
Accumulated depreciation
and depletion - -
----------- -----------
$ 5,006,560 $ 5,006,276
=========== ===========

Costs incurred in oil and gas producing activities for the years ended
June 30, 2003, 2002 and 2001 are as follows:

2003 2002 2001
---- ---- ----
Unproved property acquisition
costs $ 284 $ - $ -
Intangible drilling costs $ - $ - $ 7,522
Exploration costs $ - $19,772 $17,482

F-14
AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Years ended June 30, 2003, 2002 and 2001
- -----------------------------------------------------------------------------

(6) Disclosures About Capitalized Costs, Costs Incurred and Major Customers
(Continued)

A summary of the results of operations for oil and gas producing
activities, excluding general and administrative cost, for the years ended
June 30, 2003, 2002 and 2001 is as follows:

2003 2002 2001
---- ---- ----
Revenue:
Oil and gas sales $ - $ - $67,738
Expenses:
Lease operating - - 22,827
Depletion - - 10,608
Exploration - 19,772 17,482
------ ------- -------
Results of operations of oil
Gas producing activities $ - $(19,772) $16,821
======= ======== =======

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 at the beginning of
fiscal year 2002, there were no 2003 and 2002 customers, but in 2001, sales to
three major customers accounted for approximately 44%, 12% 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.

F-15

(7) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued

(i) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion
delineated by drilling and defined by gas-oil and/or oil-water contacts,
if any; and (B) the immediately adjoining portions not yet drilled, but
which can be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of hydrocarbons
controls the lower proved limit of the reservoir.

(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in
the "proved" classification when successful testing by a pilot project,
or the operation of an installed program in the reservoir, provides
support for the engineering analysis on which the project or program was
based.

(iii) Estimates of proved reserves do not include the following: (A) oil
that may become available from known reservoirs but is classified
separately as "indicated additional reserves"; (B) crude oil, natural
gas, and natural gas liquids, the recovery of which is subject to
reasonable doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors; (C) crude oil, natural gas, and
natural gas liquids, that may occur in underlaid prospects; and (D) crude
oil, natural gas, and natural gas liquids, that may be recovered from oil
shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves are reserves that can be expected
to be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the
application of fluid injection or other improved recovery techniques for
supplementing the natural forces and mechanisms of primary recovery should be
included as "proved developed reserves" only after testing by a pilot project
or after the operation of an installed program has confirmed through
production response that increased recovery will be achieved.

Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells where
a relatively major expenditure is required for recompletion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting
productive units that are reasonably certain of production when drilled.

F-16

AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Years Ended June 30, 2003 and 2001
- -----------------------------------------------------------------------------

(7) Information Regarding Proved Oil and Gas Reserves (Unaudited), Continued

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, 2003, 2002 and 2001 are as follows:

Onshore
--------------------
GAS OIL
(MCF) (BBLS)
---------------------
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 - -
======== ======

Balance at June 30, 2003 - -
======== ======

Proved developed reserves:
June 30, 2001 130,070 1,682
June 30, 2002 - -
June 30, 2003 - -

F-17

(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, 2003 or June 30,
2002. As such, certain disclosures at June 30, 2003 and 2002 have been
eliminated.

Future corporate overhead expenses and interest expense have not been
included.

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
==========

F-18

AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Years Ended June 30, 2003, 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, 2003, 2002 and 2001
are as follows:

2003 2002 2001
---- ---- ----

Beginning of year $ - $ 107,044 $ 231,936
Sales of oil and gas produced during the
period, net of production costs - - (44,911)
Net change in prices and production costs - - (51,512)
Changes in estimated future development costs - - -
Revisions of previous quantity estimates,
estimated timing of development and other - - (51,663)
Sale of reserves in place - (107,044) -
Accretion of discount - - 23,194
-------- --------- ---------
End of year $ - $ - $ 107,044
======== ========= =========

F-19

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 29th day of September, 2003

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. September 29, 2003
- -------------------------------
Aleron H. Larson, Jr., Director

/s/ Roger A. Parker September 29, 2003
- -------------------------------
Roger A. Parker, Director

/s/ Jerrie F. Eckelberger September 29, 2003
- -------------------------------
Jerrie F. Eckelberger, Director