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, 2005
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 4300, 370 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

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

The aggregate market value of the registrant's voting stock held by non-
affiliates of the Company as of October 5, 2005 could not be determined
because there is no established public trading market.

As of October 5, 2005, 4,666,185 shares of registrant's Common Stock $.0625
par value were issued and outstanding.

TABLE OF CONTENTS

PART I

PAGE

ITEM 1. DESCRIPTION OF BUSINESS .................................... 4
ITEM 2. DESCRIPTION OF PROPERTIES................................... 8
ITEM 3. LEGAL PROCEEDINGS .......................................... 14
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ........ 15

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS ........................................ 16
ITEM 6. SELECTED FINANCIAL DATA .................................... 16
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS .................................. 17
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK .. 20
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ................ 20
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE ..................... 20
ITEM 9A. CONTROLS AND PROCEDURES..................................... 21

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ......... 22
ITEM 11. EXECUTIVE COMPENSATION ..................................... 23
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT ............................................. 23
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ............. 24
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES ..................... 24

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS
ON FORM 8-K ................................................ 25

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," "the Company," "we" or "us"), is engaged in the
exploration, development and production of oil and gas properties. Our
business is conducted onshore in the continental United States and in the U.S.
coastal waters offshore California. As of June 30, 2005, our principal assets
include interests in three undeveloped Federal units located in the Santa
Barbara Channel and the Santa Maria Basin offshore California. There continue
to be uncertainties as to the timing of the development of our offshore
properties. (See "Description of Properties," Item 2 herein.)

On September 27, 2005, our Board of Directors made a decision to change
our fiscal year end to December 31.

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 4300, 370 17th Street, Denver, Colorado 80202.
As of June 30, 2005, Delta Petroleum Corporation, a Colorado corporation
("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, 2005, 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, 2005, we were engaged in only one
industry, namely the acquisition, exploration and development of 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 industry 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 next year.

(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 through 2005. No reserve estimates were prepared
for the past three years as all remaining leases are undeveloped.

Offshore Federal Waters: Santa Barbara, California Area
-------------------------------------------------------

Unproved Undeveloped Properties
-------------------------------

We own interests in three undeveloped federal units located in federal
waters offshore California near Santa Barbara. These property interests are
located in proximity to existing producing federal offshore units near Santa
Barbara, California and represent the right to explore for, develop and
produce oil and gas from offshore federal lease units. Preliminary
exploration efforts on these properties have occurred and the existence of
substantial quantities of hydrocarbons has been indicated. The recovery of
our investment in these properties will require extensive exploration and
development activities (and costs) that cannot proceed without certain
regulatory approvals that have been delayed and is subject to other
substantial risks and uncertainties as discussed herein.

We are not the designated operator of any of these properties but are an
active participant in the ongoing activities of each property along with the
designated operator and other interest owners. If the designated operator
elected not to or was unable to continue as the operator, the other property
interest owners would have the right to designate a new operator as well as
share in additional property returns prior to the replaced operator being able
to receive returns. Based on our size, it would be difficult for us to
proceed with exploration and development plans should other substantial
interest owners elect not to proceed. However, to the best of our knowledge,
we believe the designated operators and other major property interest owners
intend to proceed with exploration and development plans under the terms and
conditions of the operating agreement.

Even though we are not the designated operator of the properties and
regulatory approvals have not been obtained, we believe exploration and
development activities on these properties will occur and we and our parent
are committed to expending funds attributable to our interests in order to
proceed with obtaining the approvals for the exploration and development
activities.

Based on the preliminary indicated levels of hydrocarbons present from
drilling operations conducted in the past, we believe the fair value of our
property interests are in excess of their carrying value at June 30, 2005 and
June 30, 2004 and that no impairment in the carrying value has occurred.
Should the required regulatory approvals not be obtained or plans for
exploration and development of the properties not continue, the carrying value
of the properties would likely be impaired and written off.

The forty undeveloped leases are located in the Offshore Santa Maria
Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the
Santa Barbara Channel off Santa Barbara and Ventura counties. The ownership
rights in each of these properties have been retained under various suspension
notices issued by the Mineral Management Service (MMS) of the U.S. Federal
Government whereby, as long as the owners of each property were progressing
toward defined milestone objectives, the owners' rights with respect to the
properties continue to be maintained. The issuance of the suspension notices
has been necessitated by the numerous delays in the exploration and
development process resulting from regulatory requirements imposed on the
property owners by federal, state and local agencies.

On June 22, 2001, however, a Federal Court in the case of California v.
Norton, et al. ruled that the MMS does not have the power to grant suspensions
on the subject leases without first making a consistency determination under
the Coastal Zone Management Act ("CZMA"), and ordered the MMS to set aside its
approval of the suspensions of our offshore leases and to direct suspensions
for a time sufficient for the MMS to provide the State of California with the
required consistency determination. The delays have prevented the property
owners from submitting for approval an exploration plan on four of the
properties. If and when plans are submitted for approval, they are subject to
review for consistency with the CZMA, and by the MMS for other technical
requirements.

As the ruling in the Norton case currently stands, the United States has
made a consistency determination under the CZMA in accordance with the Court's
order and the leases are still valid. If the leases are found not to be valid
for some reason in the future, it would appear that the leases would become
impaired even though we would undoubtedly proceed with our litigation.

It is also possible that other events could occur that would cause the leases
to become impaired, and we will continuously evaluate those factors as they
occur.

None of these leases is currently impaired, but in the event that there
is some future adverse ruling by the California Coastal Commission under the
CZMA and we decide not to appeal such ruling to the Secretary of Commerce, or
the Secretary of Commerce either refuses to hear our appeal of any such ruling
or ultimately makes an adverse determination, it is likely that some or all of
these leases would become impaired and written off at that time.

On January 9, 2002, we and several other plaintiffs filed a lawsuit in
the United States Court of Federal Claims in Washington, D.C. alleging that
the U.S. Government has materially breached the terms of the forty undeveloped
federal leases, some of which are part of our Offshore California properties.
The Complaint is based on allegations by the collective plaintiffs that the
United States has materially breached the terms of certain of their Offshore
California leases by attempting to deviate significantly from the procedures
and standards that were in effect when the leases were entered into, and by
failing to carry out its own obligations relating to those leases in a timely
and fair manner. More specifically, the plaintiffs have alleged that the
judicial determination in the Norton case that a 1990 amendment to the CZMA
required the federal government to make a consistency determination prior to
granting lease suspension requests in 1999 constitutes a material change in
the procedures and standards that were in effect when the leases were issued.

The plaintiffs have also alleged that the United States has failed to
afford them the timely and fair review of their lease suspension requests
which has resulted in significant, continuing and material delays to their
exploratory and development operations.

The suit seeks compensation for the lease bonuses and rentals paid to the
federal government, exploration costs and related expenses. In the event that
we receive any proceeds as the result of such litigation, we will be obligated
to pay a portion of any amount received by us to landowners and other owners
of royalties and similar interests, and to pay expenses of litigation and to
fulfill certain pre-existing contractual commitments to third parties.

Cost to Develop Offshore California Properties. The cost to develop all
of the offshore California properties in which we own an interest, including
delineation wells, environmental mitigation, development wells, fixed
platforms, fixed platform facilities, pipelines and power cables, onshore
facilities and platform removal over the life of the properties (assumed to be
38 years), is estimated to be slightly in excess of $3 billion. Our share of
such costs over the life of the properties is estimated to be approximately
$27,000,000.

To the extent that we do not have sufficient cash available to pay our
share of expenses when they become payable under the respective operating
agreements, it will be necessary for us to seek funding from outside sources.
Likely potential sources for such funding are currently anticipated to
include (a) public and private sales of our Common Stock (which may result in
substantial ownership dilution to existing shareholders), (b) bank debt from
one or more commercial oil and gas lenders, (c) the sale of debt instruments
to investors, (d) entering into farm-out arrangements with respect to one or
more of our interests in the properties whereby the recipient of the farm-out

would pay the full amount of our share of expenses and we would retain a
carried ownership interest (which would result in a substantial diminution of
our ownership interest in the farmed-out properties), (e) entering into one or
more joint venture relationships with industry partners, (f) entering into
financing relationships with one or more industry partners, and (g) the sale
of some or all of our interests in the properties.

It is unlikely that any one potential source of funding would be utilized
exclusively. Rather, it is more likely that we will pursue a combination of
different funding sources when the need arises. Regardless of the type of
financing techniques that are ultimately utilized, however, it currently
appears likely that because of our small size in relation to the magnitude of
the capital requirements that will be associated with the development of the
subject properties, we will be forced in the future to issue significant
amounts of additional shares, pay significant amounts of interest on debt that
presumably would be collateralized by all of our assets (including our
offshore California properties), reduce our ownership interest in the
properties through sales of interests in the property or as the result of
farmouts, industry financing arrangements or other partnership or joint
venture relationships, or to enter into various transactions which will result
in some combination of the foregoing. In the event that we are not able to
pay our share of expenses as a working interest owner as required by the
respective operating agreements, it is possible that we might lose some
portion of our ownership interest in the properties under some circumstances,
or that we might be subject to penalties which would result in the forfeiture
of substantial revenues from the properties.

While the costs to develop the offshore California properties in which we
own an interest are anticipated to be substantial in relation to our small
size, management believes that the opportunities for us to increase our asset
base and ultimately improve our cash flow are also substantial in relation to
our size. Although there are several factors to be considered in connection
with our plans to obtain funding from outside sources as necessary to pay our
proportionate share of the costs associated with developing our offshore
properties (not the least of which is the possibility that prices for
petroleum products could decline in the future to a point at which development
of the properties is no longer economically feasible), we believe that the
timing and rate of development in the future will in large part be motivated
by the prices paid for petroleum products.

To the extent that prices for petroleum products were to decline below
their recent levels, it is likely that development efforts will proceed at a
slower pace such that costs will be incurred over a more extended period of
time. If petroleum prices remain at current levels, however, we believe that
development efforts will intensify. Our ability to successfully negotiate
financing to pay our share of development costs on favorable terms will be
inextricably linked to the prices that are paid for petroleum products during
the time period in which development is actually occurring on each of the
subject properties.

Gato Canyon Unit. We hold a 6.97% working interest, with capitalized
costs of $3,170,886, in the Gato Canyon Unit. This 10,100 acre unit is
operated by Samedan Oil Corporation. Seven test wells have been drilled on
the Gato Canyon structure. Five of these were drilled within the boundaries
of the Unit and two were drilled outside the Unit boundaries in the adjacent
State Tidelands. The test wells were drilled as follows: within the
boundaries of the Unit; three wells were drilled by Exxon, two in 1968 and one
in 1969; one well was drilled by Arco in 1985; and one well was drilled

by Samedan in 1989. Outside the boundaries of the Unit, in the State
Tidelands but still on the Gato Canyon Structure, one well was drilled by
Mobil in 1966 and one well was drilled by Union Oil in 1967. In April 1989,
Samedan tested the P-0460 #2 which yielded a combined test flow rate of 5,160
Bbls of oil per day from six intervals in the Monterey Formation between 5,880
and 6,700 feet of drilled depth. The Monterey Formation is a highly fractured
shale formation. The Monterey (which ranges from 500' to 2,900' in thickness)
is the main productive and target zone in many offshore California oil fields
(including our federal leases and/or units).

The Gato Canyon field is located in the Santa Barbara Channel
approximately three to five miles offshore. Water depths range from 280 feet
to 600 feet in the area of the field. Oil and gas produced from the field is
anticipated to be processed onshore at the existing Las Flores Canyon
facility. Las Flores Canyon has been designated a "consolidated site" by
Santa Barbara County and is available for use by offshore operators. Any
processed oil is expected to be transported out of Santa Barbara County in the
All American Pipeline. Offshore pipeline distance to access the Las Flores
site is approximately six miles. Our share of the estimated capital costs to
develop the Gato Canyon field is approximately $20 million.

As a result of the Norton case, the Gato Canyon Unit leases are under
directed suspensions of operations with no specified end date. An updated
Exploration Plan is expected to include plans to drill an additional
delineation well when activities are resumed. This well will be used to
determine the final location of the development platform. Following the
platform decision, a Development Plan will be prepared for submittal to the
MMS and the other involved agencies. Two to three years will likely be
required to process the Development Plan and receive the necessary approvals.

Lion Rock Unit. We hold a 1% net profits interest, with capitalized costs
of $1,554,898, in the Lion Rock Unit. The Lion Rock Unit is operated by Aera
Energy LLC.

The Lion Rock Unit is located in the Offshore Santa Maria Basin eight to
ten miles from the coastline. Water depths range from 300 feet to 600 feet in
the area of the field. It is anticipated that any oil and gas produced at
Lion Rock would be processed at a new facility in the onshore Santa Maria
Basin or at the existing Lompoc facility and would be transported out of Santa
Barbara County in the All American Pipeline or the Tosco-Unocal Pipeline.
Offshore pipeline distance will be eight to ten miles depending on the point
of landfall.

As a result of the Norton case, the Lion Rock Unit is held under a
directed suspension of operations with no specified end date. It is
anticipated that upon the resumption of activities there will be an
interpretation of the 3D seismic survey and the preparation of an updated Plan
of Development leading to production. Additional delineation wells may or
may not be drilled depending on the outcome of the interpretation of the 3D
survey.

Sword Unit. We hold a .87% working interest, with capitalized costs of
$280,776, in the Sword Unit. This 12,240 acre unit is operated by Conoco,
Inc. In aggregate, three wells have been drilled on this unit of which two
wells were completed and tested in the Monterey formation with calculated flow
rates of from 4,000 to 5,000 Bbls per day with an estimated average gravity of
10.6E API. The two completed test wells were drilled by Conoco, one in 1982
and the second in 1985.

The Sword field is located in the western Santa Barbara Channel ten miles
west of Point Conception and five miles south of Point Arguello field's
Platform Hermosa. Water depths range from 1000 feet to 1800 feet in the area
of the field. It is anticipated that the oil and gas produced from the Sword
Field will likely be processed at the existing Gaviota consolidated facility
and the oil would then be transported out of Santa Barbara County in the All
American Pipeline. Access to the Gaviota plant is through Platform Hermosa
and the existing Point Arguello Pipeline system. A pipeline proposed to be
laid from a platform located in the northern area of the Sword field to
Platform Hermosa would be approximately five miles in length. Our share of
the estimated capital costs to develop the Sword field is approximately $7
million.

As a result of the Norton case, the Sword Unit leases are held under
directed suspensions of operations with no specified end date. An updated
Exploration Plan is expected to include plans to drill an additional
delineation well when activities are resumed.

Since we sold our producing properties, we no longer have any sales
contracts in place. During the last three fiscal years we have not had, nor do
we now have, any long-term supply or similar agreements with governments or
authorities pursuant to which we acted as producer.

The profitability of our oil and gas production activities is affected by
the fluctuations in the sale prices of our oil and gas production. (See
"Management's Discussion and Analysis of Financial Condition and Plan of
Operations").

Impairment of Long Lived Assets
-------------------------------

Unproved Undeveloped Offshore California Properties
---------------------------------------------------

We acquired many of our offshore properties in a series of transactions
from 1992 to the present. These properties are carried at our cost bases and
have been subject to an impairment review on an annual basis.

These properties will be expensive to develop and produce and have been
subject to significant regulatory restrictions and delays. Substantial
quantities of hydrocarbons are believed to exist based on estimates reported
to us by the operator of the properties and the U.S. government's Mineral
Management Services. The classification of these properties depends on many
assumptions relating to commodity prices, development costs and timetables.
We annually consider impairment of properties assuming that properties will be
developed. Based on the range of possible development and production
scenarios using current prices and costs, we have concluded that the cost
bases of our offshore properties are not impaired at this time. There are no
assurances, however, that when and if development occurs, we will recover the
value of our investment in such properties.

(d) Productive Wells and Acreage
----------------------------

As of June 30, 2005 we had no producing oil and gas wells or developed
acreage. Productive wells are producing wells capable of production,
including shut-in wells. Developed acreage consists of acres spaced or
assignable to productive wells.

(e) Undeveloped Acreage
-------------------

At June 30, 2005, we held undeveloped acreage by state as set forth
below:

Undeveloped Acres (1)
Location Gross Net
-------- ----- ---

California (1) 22,340 811

(1) Consists of Federal leases offshore near Santa Barbara, California.

(f) Drilling Activities
-------------------

During the year ended June 30, 2005, we did not participate in any
drilling activities.

ITEM 3. LEGAL PROCEEDINGS

On January 9, 2002, we and several other plaintiffs filed a lawsuit in
the United States Court of Federal Claims in Washington, D.C. alleging that
the U.S. Government has materially breached the terms of forty undeveloped
federal leases, some of which are part of our Offshore California properties.
The Complaint is based on allegations by the collective plaintiffs that the
United States has materially breached the terms of certain of their Offshore
California leases by attempting to deviate significantly from the procedures
and standards that were in effect when the leases were entered into, and by
failing to carry out its own obligations relating to those leases in a timely
and fair manner. More specifically, the plaintiffs have alleged that the
judicial determination in the California v. Norton case that a 1990 amendment
to the Coastal Zone Management Act required the government to make a
consistency determination prior to granting lease suspension requests in 1999
constitutes a material change in the procedures and standards that were in
effect when the leases were issued. The plaintiffs have also alleged that the
United States has failed to afford them the timely and fair review of their
lease suspension requests which has resulted in significant, continuing and
material delays to their exploratory and development operations.

The suit seeks compensation for the lease bonuses and rentals paid to the
Federal Government, exploration costs and related expenses. The total amount
claimed by all lessees for bonuses and rentals exceeds $1.2 billion, with
additional amounts for exploration costs and related expenses. In the event,
however, that we receive any proceeds as the result of such litigation, we may
be obligated to pay a portion of any amount received by us to landowners and
other owners of royalties and similar interests, and to pay expenses of
litigation and to fulfill certain pre-existing contractual commitments to
third parties.

The Federal Government has not yet filed an answer in this proceeding
pending its motion to dismiss the lawsuit, which motion has not yet been heard
by the court. More recently, the plaintiffs filed a motion for summary
judgment as to certain liability aspects related to their claims. Neither
motion has yet been heard by the court.

ITEM 4. 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 2005 and
2004 have not been available.

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

The number of holders of record of our securities at October 5, 2005 was
approximately 1,000.

We have not paid dividends on our stock and we do not expect to do so in
the foreseeable future.

(d) Changes in Securities
---------------------

During the quarter ended June 30, 2005, we did not have any sales of
securities that were not registered under the Securities Act of 1933, as
amended.

ITEM 6. 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,
--------------------------------------------------------------------------------
2005 2004 2003 2002 2001
---- ---- ---- ---- ----

Total Revenues $ - $ - $ - $ 73,960 $ 119,405
Income/(Loss) from
Operations $ (110,240) $ (109,308) $ (128,936) $ (54,622) $ (42,648)
Income/(Loss)
Per Share $ (0.02) $ (0.02) $ (0.03) $ (0.01) $ *
Total Assets $5,006,560 $5,007,139 $5,007,427 $5,006,957 $5,062,208
Total Liabilities $ - $ - $ - $ 2,912 $ 16,532
Stockholders' Equity $5,006,650 $5,007,139 $5,007,427 $5,004,045 $5,045,676
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, 2005 and 2004, we essentially had no working capital. The
cash used in operating activities of $110,240 during fiscal 2005 remained
consistent with fiscal 2004. The lack of cash flow from operations may
inhibit the Company from meeting its obligations in a timely manner unless
additional financing or the sale of properties occurs. However, the Company
has a receivable of $47,498 at June 30, 2005 from Delta. If necessary, Delta
may repay its obligation to the Company to meet Amber's operating needs and
obligations for costs incurred relating to our offshore undeveloped California
properties.

We do not currently have a credit facility with any bank and we have not
determined the amount, if any, that we could borrow against our remaining
properties. Together with Delta, we will continue to seek additional sources
of both short-term and long-term liquidity to fund our working capital needs
and our capital requirements for development of our properties, including
establishing a credit facility and/or sale of equity or debt securities
although there can be no assurance that we will be successful in our efforts.
Many of the factors which may affect our future operating performance and
liquidity are beyond our control, including oil and natural gas prices and the
availability of financing.

After evaluation of the considerations described above, we believe that
our existing cash balances and funding from the advance to Delta and other
sources of funds will be adequate to fund our operating expenses and satisfy
our other current liabilities over the next year.

Results of Operations - Fiscal 2005 Versus 2004
-----------------------------------------------

Net Income. Our net losses for the years ended June 30, 2005 and 2004
were $110,240 and $109,308, respectively.

As all of our producing properties were sold on July 1, 2001 there were
no revenues, production volumes, lease operating expenses or depletion in the
years ended June 30, 2005 and June 30, 2004.

Exploration Expenses. Exploration expenses consist of geological and
geophysical costs and lease rentals relating to our offshore properties. We
incurred exploration costs of $235 and $1,441 for the years ended June 30,
2005 and 2004, respectively.

General and Administrative Expenses. General and administrative expense
for the year ended June 30, 2005 was $110,005 compared to $107,867 for the
year ended June 30, 2004.

Results of Operations - Fiscal 2004 Versus 2003
-----------------------------------------------

Net Income. Our net losses for the years ended June 30, 2004 and 2003
were $109,308 and $128,936, respectively.

As all of our producing properties were sold on July 1, 2001 there were
no revenues, production volumes, lease operating expenses or depletion in the
years ended June 30, 2004 and June 30, 2003.

Exploration Expenses. Exploration expenses consist of geological and
geophysical costs and lease rentals. We incurred exploration costs of $1,441
and zero for the years ended June 30, 2004 and 2003, respectively.

General and Administrative Expenses. General and administrative expense
for the year ended June 30, 2005 was $107,867 compared to $128,936 for the
year ended June 30, 2003. The decrease in general and administrative expense
was due to additional incorporation fees incurred during fiscal 2003.

Critical Accounting Policies and Estimates
------------------------------------------

The discussion and analysis of our financial condition and results of
operations were based upon the consolidated financial statements, which have
been prepared in accordance with accounting principles generally accepted in
the United States. The preparation of these financial statements requires us
to make estimates and judgments that affect the reported amounts of assets,
liabilities, revenues and expenses. Our significant accounting policies are
described in Note 1 to our financial statements. In response to SEC Release
No. 33-8040, "Cautionary Advice Regarding Disclosure About Critical Accounting
Policies," we have identified certain of these policies as being of particular
importance to the portrayal of our financial position and results of
operations and which require the application of significant judgment by
management. We analyze our estimates, including those related to oil and gas
reserves, bad debts, oil and gas properties, marketable securities, income
taxes, derivatives, contingencies and litigation, and base our estimates on
historical experience and various other assumptions that we believe reasonable
under the circumstances. Actual results may differ from these estimates under
different assumptions or conditions. We believe the following critical
accounting policies affect our more significant judgments and estimates used
in the preparation of the Company's financial statements.

Successful Efforts Method of Accounting
---------------------------------------

We account for our natural gas and crude oil exploration and development
activities utilizing the successful efforts method of accounting. Under this
method, costs of productive exploratory wells, development dry holes and
productive wells and undeveloped leases are capitalized. Gas and oil lease
acquisition costs are also capitalized. Exploration costs, including
personnel costs, certain geological and geophysical expenses and delay rentals
for gas and oil leases, are charged to expense as incurred. Exploratory
drilling costs are initially capitalized, but charged to expense if and when
the well is determined not to have found reserves in commercial quantities.
The sale of a partial interest in a proved property is accounted for as a cost
recovery and no gain or loss is recognized as long as this treatment does not
significantly affect the unit-of-production amortization rate. A gain or loss
is recognized for all other sales of producing properties.

The application of the successful efforts method of accounting requires
managerial judgment to determine that proper classification of wells
designated as developmental or exploratory which will ultimately determine the
proper accounting treatment of the costs incurred. The results from a

drilling operation can take considerable time to analyze and the determination
that commercial reserves have been discovered requires both judgment and
industry experience. Wells may be completed that are assumed to be productive
and actually deliver gas and oil in quantities insufficient to be economic,
which may result in the abandonment of the wells at a later date. Wells are
drilled that have targeted geologic structures that are both developmental and
exploratory in nature and an allocation of costs is required to properly
account for the results. Delineation seismic incurred to select development
locations within an oil and gas field is typically considered a development
cost and capitalized, but often these seismic programs extend beyond the
reserve area considered proved and management must estimate the portion of the
seismic costs to expense. The evaluation of gas and oil leasehold acquisition
costs requires managerial judgment to estimate the fair value of these costs
with reference to drilling activity in a given area. Drilling activities in
an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact
on the operational results reported when we are entering a new exploratory
area in hopes of finding a gas and oil field that will be the focus of future
development drilling activity. The initial exploratory wells may be
unsuccessful and will be expensed. Seismic costs can be substantial which
will result in additional exploration expenses when incurred.

Reserve Estimates
-----------------

We do not currently own any reserves and we do not currently have any
estimates of any gas or oil reserves.

Impairment of Gas and Oil Properties
------------------------------------

We review our gas and oil properties for impairment whenever events and
circumstances indicate a decline in the recoverability of their carrying
value. We estimate the expected future cash flows of our gas and oil
properties and compare such future cash flows to the carrying amount of the
gas and oil properties to determine if the carrying amount is recoverable. If
the carrying amount exceeds the estimated undiscounted future cash flows, we
will adjust the carrying amount of the gas and oil properties to their fair
value. The factors used to determine fair value include, but are not limited
to, estimates of hydrocarbons that we believe are recoverable even though they
are not proved reserves, future commodity pricing, future production
estimates, anticipated capital expenditures, and a discount rate commensurate
with the risk associated with realizing the expected cash flows projected.

Given the complexities associated with such estimates and the history of
price volatility in the gas and oil markets, events may arise that would
require us to record an impairment of the book values associated with our gas
and oil properties. As a result of our review, we did not record an
impairment during the years ended June 30, 2005, 2004 or 2003.

Recently Issued Accounting Standards and Pronouncements
- -------------------------------------------------------

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error
Corrections-a replacement of APB Opinion No. 20 and FASB Statement No. 3
("Statement 154"). SFAS 154 requires retrospective application to prior
periods' financial statements for changes in accounting principle, unless it
is impracticable to determine either the period-specific effects or the
cumulative effect of the change. SFAS 154 also requires that a change in
depreciation, amortization, or depletion method for long-lived, non-financial
assets be accounted for as a change in accounting estimate affected by a
change in accounting principle. SFAS 154 is effective for accounting changes
and corrections of errors made in fiscal years beginning after December 15,
2005. The implementation of FAS 154 is not expected to have a material impact
on our consolidated results of operations, financial position or cash flows.

In December 2004, the FASB issued its final standard on accounting for
employee stock options, FAS No. 123 (Revised 2004), "Share-Based Payment"
("FAS123(R)"). FAS 123(R) replaces FAS No. 123, "Accounting for Stock-Based
Compensation" ("FAS 123"), and supersedes Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees." FAS 123(R) requires
companies to measure compensation costs for all share-based payments,
including grants of employee stock options, based on the fair value of the
awards on the grant date and to recognize such expense over the period during
which an employee is required to provide services in exchange for the award.
The pro forma disclosures previously permitted under FAS 123 will no longer be
an alternative to financial statement recognition. FAS 123(R) is effective for
all awards granted, modified, repurchased or cancelled after, and to unvested
portions of previously issued and outstanding awards vesting after, interim or
annual periods, beginning after June 15, 2005, which for us will be the first
quarter of fiscal 2006. We are currently evaluating the effect of adopting FAS
123(R) on our financial position and results of operations, and we have not
yet determined whether the adoption of FAS 123(R) will result in expenses in
amounts that are similar to the current pro forma disclosures under FAS 123.

ITEM 7A. 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, 2005. Based upon this evaluation, the chief executive
officer and chief financial officer concluded that our disclosure controls and
procedures were effective in ensuring that material information required to be
disclosed is included in the reports that it files with the Securities and
Exchange Commission.

Changes in Internal Controls
----------------------------

There were no significant changes in our internal controls or, to the
knowledge of our management, in other factors that could significantly affect
internal controls subsequent to the date of the most recent evaluation of our
disclosure controls and procedures utilized to compile information included in
this filing.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Information with respect to our executive officers and directors is set
forth below:

Name Age Positions Period of Service
- ---------------------- --- ----------------------- -------------------

Aleron H. Larson, Jr. 60 Chairman of the Board, May 1987 to Present
Secretary, and a Director

Roger A. Parker 43 President, Chief May 1987 to Present
Executive Officer and
a Director

Jerrie F. Eckelberger 61 Director September 1996
to Present

Kevin K. Nanke 40 Treasurer and Chief December 1999
Financial Officer to Present

The following is biographical information as to the business experience
of each of our current officers and directors.

Roger A. Parker has served as the President, Chief Executive Officer and
a Director of both Amber and Delta since May of 1987, and as the Chief
Executive Officer of both corporations since April of 2002. Since April 1,
2005 he has also served as a Director of DHS Drilling Company, which is an
affiliate of Delta. He received a Bachelor of Science in Mineral Land
Management from the University of Colorado in 1983. He is a member of the
Rocky Mountain Oil and Gas Association and is a board member of the
Independent Producers Association of the Mountain States (IPAMS). He also
serves on other boards, including Community Banks of Colorado.

Jerrie F. Eckelberger is an investor, real estate developer and attorney
who has practiced law in the State of Colorado since 1971. He graduated from
Northwestern University with a Bachelor of Arts degree in 1966 and received
his Juris Doctor degree in 1971 from the University of Colorado School of Law.
From 1972 to 1975, Mr. Eckelberger was a staff attorney with the Eighteenth
Judicial District Attorney's Office in Colorado. From 1975 to present, Mr.
Eckelberger has been engaged in the private practice of law and is presently a
member of the law firm of Eckelberger & Jackson, LLC. Mr. Eckelberger
previously served as an officer, director and corporate counsel for Roxborough
Development Corporation. Since March, 1996, Mr. Eckelberger has engaged in
the investment and development of Colorado real estate through several private
companies in which he is a principal.

Aleron H. Larson, Jr. has operated as an independent in the oil and gas
industry individually and through public and private ventures since 1978. Mr.
Larson serves as our Chairman of the Board, Secretary and a Director, and as a
Director and Secretary of Delta. Mr. Larson practiced law in Breckenridge,
Colorado from 1971 until 1974. During this time he was a member of a law
firm, Larson & Batchellor, engaged primarily in real estate law, land use
litigation, land planning and municipal law. In 1974, he formed Larson &
Larson, P.C., and was engaged primarily in areas of law relating to
securities, real estate, and oil and gas until 1978. Mr. Larson

received a Bachelor of Arts degree in Business Administration from the
University of Texas at El Paso in 1967 and a Juris Doctor degree from the
University of Colorado in 1970.

Kevin K. Nanke has served as the Treasurer and Chief Financial Officer
of both Amber and Delta since April, 1995. Since April 1, 2005 he has also
served as Chief Financial Officer, Treasurer and Director of DHS Drilling
Company, which is an affiliate of Delta. Since 1989, he has been involved in
public and private accounting with the oil and gas industry. Mr. Nanke
received a Bachelor of Arts in Accounting from the University of Northern Iowa
in 1989. Prior to working with us, he was employed by KPMG LLP. He is a
member of the Colorado Society of CPA's and the Council of Petroleum
Accounting Society.

There is no family relationship among or between any of our Officers
and/or Directors.

Section 16(a) Beneficial Ownership Reporting Compliance
-------------------------------------------------------

Based solely on a review of Forms 3 and 4 and amendments thereto
furnished to us during our most recent fiscal year, and Forms 5 and amendments
thereto furnished with respect to our most recent fiscal year and certain
representations, no persons who were either a director, officer, or beneficial
owner of more than 10% of the Company's common stock failed to file on a
timely basis reports required by Section 16(a) of the Exchange Act during the
most recent fiscal year.

ITEM 11. EXECUTIVE COMPENSATION

No officer or director received compensation directly from us during the
years ended June 30, 2005, 2004 and 2003. Messrs. Larson, Parker, Nanke,
Chairman, President and Chief Financial Officer, respectively, are compensated
by Delta, which compensation is paid under a management agreement with us. No
officer or director received stock appreciation rights, restricted stock
awards, options, warrants or other similar compensation reportable under this
section during any of the above referenced periods.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

(a) & (b) Security Holdings of Management and Persons Controlling more
than 5% of Shares of Common Stock Outstanding on a Fully-Diluted Basis.

Name and Address of Amount & Nature of
Beneficial Owners Beneficial Ownership Percent of Class
- ------------------- -------------------- ----------------

Delta Petroleum Corporation 4,277,977 (1) 91.68% (1)
370 17th Street, Suite 4300

Denver, Colorado 80202

Roger A. Parker 4,277,977 (1) 91.68% (1)
370 17th Street, Suite 4300
Denver, CO 80202

Aleron H. Larson, Jr. 4,277,977 (1) 91.68% (1)
25598 Foothills Drive North
Golden, CO 80401

Jerrie F. Eckelberger 4,277,977 (1) 91.68% (1)
7120 East Orchard Road
Englewood, CO 80111

Kevin K. Nanke 4,277,977 (1) 91.68% (1)
370 17th Street, Suite 4300
Denver, Colorado 80202

Management as a Group (4 people) 4,277,977 (1) 91.68% (1)

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

(1) All shares are owned by Delta; Messrs. Larson, Parker, Nanke and
Eckleberger are either officers, directors or shareholders of Delta.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Effective October 1, 1998, we entered into an agreement with Delta which
provides for the sharing of management between the two companies. Under this
agreement we pay Delta $25,000 per quarter for our share of rent,
administrative, accounting and management services of Delta officers and
employees. This agreement may be cancelled by either party at any time. It
is our opinion that fees paid to Delta for services rendered are comparable to
fees that would be charged by similarly qualified non-affiliated persons. This
agreement replaces a previous agreement which allocated similar expenses based
on our proportionate share of oil and gas production. The charges to us for
the provision of services by Delta were $100,000 for the years ended June 30,
2005, 2004 and 2003. We had receivables from Delta of $47,498 and $157,159
recorded as reductions in equity at June 30, 2005 and 2004, respectively.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

AUDIT FEES: The aggregate fees billed for professional services rendered
by KPMG LLP for the audit of the annual financial statements of the Company
for the fiscal year ended June 30, 2005 and the review of the financial
statements included in the Company's Forms 10-Q for such fiscal year were paid
by Delta, our parent, pursuant to our agreement under which we pay Delta
$25,000 per quarter. (See Item 13. Certain Relationships and Related
Transactions.)

AUDIT RELATED FEES: None

TAX FEES: None.

ALL OTHER FEES: None.

PART IV

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

(a) (1) Financial Statements
--------------------

Independent auditors' reports F-1

Balance Sheets as of June 30, 2005 and 2004 F-3

Statements of Operations and Accumulated Deficit
Years Ended June 30, 2005, 2004 and 2003 F-4

Statements of Cash Flows F-5
Years Ended June 30, 2005, 2004 and 2003

Notes to Financial Statements F-6

(a) (2) Financial Statement Schedules
-----------------------------

None

(a) (3) Exhibits
--------

The Exhibits listed in the Index to Exhibits appearing at page 26 are
filed as part of this report. Management contracts and compensatory plans
required to be filed as exhibits are marked with an "*."

INDEX TO EXHIBITS

(2) Plan of Acquisitions, Reorganization, Arrangement, Liquidation, or
Succession. Not applicable.

(3) Articles of Incorporation and Bylaws.

3.1 The Articles of Incorporation(Certificate of Incorporation)
and Bylaws of the Registrant filed as Exhibits 4 and 5 to
Registrant's Form S-1 Registration Statement filed August 28,
1978 with the Securities and Exchange Commission
are incorporated herein by reference. The Restated Articles
of Incorporation (Restated Certificate of Incorporation)
dated January 26, 1988 and Amendment to Restated Certificate
of Incorporation dated September 18, 1989 are incorporated by
reference to Exhibits 3.1 and 3.2 to the Company's Form
10-KSB for the fiscal year ended June 30, 1997.

3.2 Certificate for Renewal and Revival of Charter. Incorporated
by reference from Exhibit 3.2 of the Company's Form 10-K for
the fiscal year ended June 30, 2003.

(4) Instruments Defining the Rights of Security Holders.

4.1 Certificate of Designation of the Relative Rights of the
Class A Preferred Stock of Amber Resources Company dated
July 25, 1989. Incorporated by reference to Exhibit 4.1 of
The Company's Form 10-KSB for the fiscal year ended
June 30, 1997.

(9) Voting Trust Agreement. Not applicable.

(10) Material Contracts.

10.1 Agreement dated March 31, 1993 between Delta Petroleum
Corporation and Amber Resources Company. Incorporated by
reference from Exhibit 10.1 of the Company's Form 10-KSB for
the fiscal year ended June 30, 1997.

10.2 Amber Resources Company 1996 Incentive Plan. Incorporated by
reference from Exhibit 99.1 of the Company's December 4, 1996
Form 8-K.*

10.3 Agreement between Amber Resources Company and Delta Petroleum
Corporation dated effective October 1, 1998. Incorporated by
reference from Exhibit 10.2 of the Company's Form 10-KSB for
the fiscal year ended June 30, 1999.

10.4 Purchase and Sale Agreement between Amber Resources Company
and Delta Petroleum Corporation dated July 1, 2001.
Incorporated by reference to Exhibit 10.4 to the Company's
Form 10-K for the fiscal year ended June 30, 2002.

(11) Statement Regarding Computation of Per Share Earnings. Not applicable.

(12) Statement Regarding Computation of Ratios. Not applicable.

(13) Annual Report to Security Holders, Form 10-Q or Quarterly
Report to Security Holders. Not applicable.

(16) Letter re: Change in Certifying Accountants. Not applicable.

(17) Letter re: Director Resignation. Not applicable.

(18) Letter Regarding Change in Accounting Principals. Not applicable.

(19) Previously Unfiled Documents. Not applicable.

(21) Subsidiaries of the Registrant. Not applicable.

(22) Published Report Regarding Matters Submitted to Vote of Security
Holders. Not applicable.

(23) Consent of Experts and Counsel. Not applicable.

(24) Power of Attorney. Not applicable.

(31) Rule 13a-14(a)/15d-14(a) Certifications.

31.1 Certification of Chief Executive Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002. Filed herewith
electronically.

31.2 Certification of Chief Financial Officer Pursuant to Section
302 of the Sarbanes-Oxley Act of 2002. Filed herewith
electronically.

(32) Section 1350 Certifications.

32.1 Certification of Chief Executive Officer Pursuant to 18 U.S.C.
Section 1350. Filed herewith electronically.

32.2 Certification of Chief Financial Officer Pursuant to 18 U.S.C.
Section 1350. Filed herewith electronically.

(99) Additional Exhibits. Not applicable.

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

* Management contracts and compensatory plans.

Report of Independent Registered Public Accounting Firm

The Board of Directors
Amber Resources Company of Colorado:

We have audited the accompanying balance sheets of Amber Resources Company of
Colorado, formerly named Amber Resources Company (the "Company"), a subsidiary
of Delta Petroleum Corporation, as of June 30, 2005 and 2004 and the related
statements of operations and accumulated deficit, and cash flows for each of
the years in the three-year period ended June 30, 2005. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Amber Resources Company of
Colorado as of June 30, 2005 and 2004, and the results of its operations and
its cash flows for each of the years in the three-year period ended June 30,
2005, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP
KPMG LLP

Denver, Colorado
September 26, 2005

F-1

AMBER RESOURCES COMPANY OF COLORADO
BALANCE SHEETS
June 30, 2005 and 2004
- -----------------------------------------------------------------------------

2005 2004
--------- ----------
ASSETS

Current Assets:
Cash $ - $ 579
--------- ---------
Total current assets - 579
--------- ---------
Property and Equipment:
Oil and gas properties, at cost (using
the successful efforts method
of accounting):
Undeveloped offshore California properties 5,006,560 5,006,560
---------- ----------
$5,006,560 $5,007,139
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY

Liabilities: $ - $ -
---------- ----------
Stockholders' Equity:
Preferred stock, $.10 par value;
authorized 5,000,000 shares of Class A
convertible preferred stock, none issued -
Common stock, $.0625 par value;
authorized 25,000,000 shares, issued
4,666,185 shares at June 30, 2005 and 2004 291,637 291,637
Additional paid in capital 5,755,232 5,755,232
Accumulated deficit (992,811) (882,571)

Advance to parent (47,498) (157,159)
---------- ----------
Total stockholders' equity 5,006,560 5,007,139
---------- ----------
Commitments
$5,006,560 $5,007,139
========== ==========

See accompanying notes to consolidated financial statements.

F-2

AMBER RESOURCES COMPANY OF COLORADO
STATEMENTS OF OPERATIONS AND ACCUMULATED DEFICIT
Years Ended June 30, 2005, 2004 and 2003
- -----------------------------------------------------------------------------

Years Ended June 30,
2005 2004 2003
--------- --------- ---------

Revenue:
Oil and gas sales $ - $ - $ -
--------- --------- ---------

Total revenue - - -

Operating expenses:
Exploration expenses 235 1,441 -
General and administrative, including
$100,000 in 2005, 2004 and 2003 to
parent 110,005 107,867 128,936
--------- --------- ---------
Total operating expenses 110,240 109,308 128,936
--------- --------- ---------

Loss from Operations (110,240) (109,308) (128,936)

Other income - - 2
--------- --------- ---------

Net Loss (110,240) (109,308) (128,934)

Accumulated deficit at beginning
of the year (882,571) (773,263) (644,329)
--------- --------- ---------
Accumulated deficit at end of the
year $(992,811) $(882,571) $(773,263)
========= ========= =========

Basic loss per share $ (0.02) $ (0.02) $ (0.03)
========= ========= =========

Weighted average number of common
shares outstanding 4,666,185 4,666,185 4,666,185
========= ========= =========

See accompanying notes to consolidated financial statements.

F-3

AMBER RESOURCES COMPANY OF COLORADO
STATEMENTS OF CASH FLOWS
Years Ended June 30, 2005, 2004 and 2003
- -----------------------------------------------------------------------------

Years Ended June 30,
2005 2004 2003
--------- --------- ---------

Cash flows from operating activities:
Net loss $(110,240) $(109,308) $(128,934)

Net changes in operating assets and
operating liabilities:
Decrease in accounts payable trade - - (2,912)
--------- --------- ---------
Net cash used in operating activities (110,240) (109,308) (131,846)
--------- --------- ---------

Cash flows from investing activities -
Additions to property and equipment, net - - (284)
--------- --------- ---------
Net Cash used in investing activities - - (284)

Cash flows from financing activities -
Changes in accounts receivable from and
accounts payable to parent 109,661 109 020 132,216
--------- --------- ---------
Net increase (decrease) in cash (579) (288) 186
--------- --------- ---------

Cash at beginning of period 579 867 681
--------- --------- ---------

Cash at end of period $ - $ 579 $ 867
========= ========= =========

See accompanying notes to consolidated financial statements.

F-4

AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Years Ended June 30, 2005 and 2004
- -----------------------------------------------------------------------------

(1) Summary of Significant Accounting Policies

Organization

Amber Resources Company of Colorado, formerly Amber Resources Company
("the Company"), was incorporated in January, 1978, and is principally engaged
in acquiring, exploring, developing, and producing offshore oil and gas
properties. The Company owns interests in three undeveloped oil and gas
properties in federal units offshore California, near Santa Barbara. As of
June 30, 2005 Delta Petroleum Corporation ("Delta") owned 4,277,977 shares
(91.68%) of the Company's common stock.

Liquidity

The Company has incurred losses from operations over the past several
years coupled with significant deficiencies in cash flow from operations for
the same period. Additionally, during the year ended June 30, 2002 the
Company sold its remaining producing reserves to Delta. The Company's
remaining properties are all undeveloped offshore California properties, the
development of which is currently being delayed by litigation with the US
Government. These factors among others may indicate that without increased
cash flow from sale of oil and gas properties or additional financing, the
Company may not be able to meet its obligations in a timely manner or be able
to fund exploration and development of its remaining oil and gas properties.
The Company believes that it could sell oil and gas properties or obtain
additional financing, if necessary. However, there can be no assurance that
such financing would be available in a timely fashion or on acceptable terms.

Revenue Recognition

The Company uses the sales method of accounting for oil and gas revenues.
Under this method, revenues are recognized based on actual volumes of oil and
gas sold to purchasers.

Oil and Gas Properties

The Company follows the successful efforts method of accounting for its
oil and gas activities. Accordingly, costs associated with the acquisition,
drilling, and equipping of successful exploratory wells are capitalized.

Geological and geophysical costs, delay and surface rentals and drilling
costs of unsuccessful exploratory wells are charged to expense as incurred.
Costs of drilling development wells, both successful and unsuccessful, are
capitalized.

F-5

(1) Summary of Significant Accounting Policies, Continued

Upon the sale or retirement of oil and gas properties, the cost thereof
and the accumulated depreciation and depletion are removed from the accounts
and any gain or loss is credited or charged to operations.

Depreciation and depletion of capitalized acquisition, exploration and
development costs is computed on the units-of-production method by individual
fields as the related proved reserves are produced. Capitalized costs of
undeveloped properties are assessed periodically on an individual field basis
and a provision for impairment is recorded, if necessary, through a charge to
operations.

Impairment of Long Lived Assets

In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS 144 establishes a single
accounting model for long-lived assets to be disposed of by sale and requires
that those long-lived assets be measured at the lower of carrying amount or
fair value less cost to sell, whether reported in continuing operations or in
discontinued operations.

For undeveloped properties, the need for an impairment reserve is based
on the Company's plans for future development and other activities impacting
the life of the property and the ability of the Company to recover its
investment. When the Company believes the cost of the undeveloped property is
no longer recoverable, an impairment charge is recorded based on the estimated
fair value of the property.

Earnings (Loss) per Share

Basic earnings (loss) per share is computed by dividing net earnings
(loss) attributable to common stock by the weighted average number of common
shares outstanding during each period, excluding treasury shares. The Company
does not have any dilutive instruments and as such, no diluted earnings per
share have been presented.

Use of Estimates

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenue and expenses during the
reported period. Significant estimates include oil and gas reserves, bad
debts, oil and gas properties, income taxes, contingencies and litigation.
Actual results could differ from these estimates.

F-6

(1) Summary of Significant Accounting Policies, Continued

Recently Issued Accounting Standards and Pronouncements

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error
CorrectionsCa replacement of APB Opinion No. 20 and FASB Statement No. 3
("Statement 154"). SFAS 154 requires retrospective application to prior
periods= financial statements for changes in accounting principle, unless it
is impracticable to determine either the period-specific effects or the
cumulative effect of the change. SFAS 154 also requires that a change in
depreciation, amortization, or depletion method for long-lived, non-financial
assets be accounted for as a change in accounting estimate affected by a
change in accounting principle. SFAS 154 is effective for accounting changes
and corrections of errors made in fiscal years beginning after December 15,
2005. The implementation of FAS 154 is not expected to have a material impact
on the Company's consolidated results of operations, financial position or
cash flows.

In December 2004, the FASB issued its final standard on accounting for
employee stock options, FAS No. 123 (Revised 2004), "Share-Based Payment"
("FAS123(R)"). FAS 123(R) replaces FAS No. 123, "Accounting for Stock-Based
Compensation" ("FAS 123"), and supersedes Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees." FAS 123(R) requires
companies to measure compensation costs for all share-based payments,
including grants of employee stock options, based on the fair value of the
awards on the grant date and to recognize such expense over the period during
which an employee is required to provide services in exchange for the award.
The pro forma disclosures previously permitted under FAS 123 will no longer be
an alternative to financial statement recognition. FAS 123(R) is effective for
all awards granted, modified, repurchased or cancelled after, and to unvested
portions of previously issued and outstanding awards vesting after, interim or
annual periods, beginning after June 15, 2005, which for us will be the first
quarter of fiscal 2006. The Company is currently evaluating the effect of
adopting FAS 123(R) on its financial position and results of operations, and
have not yet determined whether the adoption of FAS 123(R) will result in
expenses in amounts that are similar to the current pro forma disclosures
under FAS 123.

F-7

(2) Oil and Gas Properties

Unproved Undeveloped Offshore California Properties

The Company has ownership interests ranging from .87% to 6.97% in three
unproved undeveloped offshore California oil and gas properties with aggregate
carrying values of $5,006,560 on June 30, 2005 and 2004. These property
interests are located in proximity to existing producing federal offshore
units near Santa Barbara, California and represent the right to explore for,
develop and produce oil and gas from offshore federal lease units. Preliminary
exploration efforts on these properties have occurred and the existence of
substantial quantities of hydrocarbons has been indicated. The recovery of
the Company's investment in these properties will require extensive
exploration and development activities (and costs) that cannot proceed without
certain regulatory approvals that have been delayed and is subject to other
substantial risks and uncertainties as discussed herein.

The Company is not the designated operator of any of these properties but
is an active participant in the ongoing activities of each property along with
the designated operator and other interest owners. If the designated operator
elected not to or was unable to continue as the operator, the other property
interest owners would have the right to designate a new operator as well as
share in additional property returns prior to the replaced operator being able
to receive returns. Based on the Company's size, it would be difficult for
the Company to proceed with exploration and development plans should other
substantial interest owners elect not to proceed. However, to the best of its
knowledge, the Company believes the designated operators and other major
property interest owners intend to proceed with exploration and development
plans under the terms and conditions of the operating agreement.

On June 22, 2001, however, a Federal Court in the case of California v.
Norton, et al. ruled that the Minerals Management Services (MMS) does not have
the power to grant suspensions on the subject leases without first making a
consistency determination under the Coastal Zone Management Act ("CZMA"), and
ordered the MMS to set aside its approval of the suspensions of the Company's
offshore leases and to direct suspensions for a time sufficient for the MMS to
provide the State of California with the required consistency determination.
No such consistency determination has as yet been made.

The ownership rights in each of these properties have been retained under
various suspension notices issued by the MMS of the U.S. Federal Government
whereby as long as the owners of each property were progressing toward defined
milestone objectives, the owners' rights with respect to the properties
continue to be maintained. The issuance of the suspension notices has been
necessitated by the numerous delays in the exploration and development process
resulting from regulatory requirements imposed on the property owners by
federal, state and local agencies.

F-8

(2) Oil and Gas Properties, Continued

The delays have prevented the property owners from submitting for
approval an exploration plan on four of the properties. If and when plans are
submitted for approval, they are subject to review for consistency with the
California Coastal Zone Management Planning (CZMP) and by the MMS for other
technical requirements.

Even though the Company is not the designated operator of the properties
and regulatory approvals have not been obtained, the Company believes
exploration and development activities on these properties will occur and is
committed to expend funds attributable to its interests in order to proceed
with obtaining the approvals for the exploration and development activities.

Based on the preliminary indicated levels of hydrocarbons present from
drilling operations conducted in the past, the Company believes the fair value
of its property interests are in excess of their carrying value at June 30,
2005 and June 30, 2004 and that no impairment in the carrying value has
occurred. Should the required regulatory approvals not be obtained or plans
for exploration and development of the properties not continue, the carrying
value of the properties would likely be impaired and written off.

The forty undeveloped leases are located in the Offshore Santa Maria
Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the
Santa Barbara Channel off Santa Barbara and Ventura counties. None of these
leases are adverse ruling by the California Coastal Commission under the
Coastal Zone Management Act and we decide not to appeal such ruling to the
Secretary of Commerce, or the Secretary of Commerce either refuses to hear our
appeal of any such ruling or ultimately makes a determination adverse to us,
it is likely that some or all of these leases would become impaired and
written off at that time.

As the ruling in the Norton case currently stands, the United States has
been ordered to make a consistency determination under the CZMA, but the
leases are still valid. If the leases are found not to be valid for some
reason, or if the United States either does not comply with the order
requiring it to make a consistency determination or finds that development is
inconsistent with the CZMA, it would appear that the leases would become
impaired even though we would undoubtedly proceed with our litigation. It is
also possible that other events could occur that would cause the leases to
become impaired, and we will continuously evaluate those factors as they
occur.

F-9

AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Consolidated Financial Statements
June 30, 2005, 2004 and 2003
- -----------------------------------------------------------------------------

(2) Oil and Gas Properties, Continued

On January 9, 2002, we and several other plaintiffs filed a lawsuit in
the United States Court of Federal Claims in Washington, D.C. alleging that
the U.S. Government has materially breached the terms of forty undeveloped
federal leases, some of which are part of our Offshore California properties.
The Complaint is based on allegations by the collective plaintiffs that the
United States has materially breached the terms of certain of their Offshore
California leases by attempting to deviate significantly from the procedures
and standards that were in effect when the leases were entered into, and by
failing to carry out its own obligations relating to those leases in a timely
and fair manner. More specifically, the plaintiffs have alleged that the
judicial determination in the California v. Norton case that a 1990 amendment
to the CZMA required the Government to make a consistency determination prior
to granting lease suspension requests in 1999 constitutes a material change in
the procedures and standards that were in effect when the leases were issued.
The plaintiffs have also alleged that the United States has failed to afford
them the timely and fair review of their lease suspension requests which has
resulted in significant, continuing and material delays to their exploratory
and development operations.

(3) Preferred Stock

The Board of Directors is authorized to issue 5,000,000 shares of
preferred stock having a par value of $0.10 per share. As of the years ended
June 30, 2005 and 2004, no preferred stock was issued and outstanding.

F-10

(4) Income Taxes

At June 30, 2005, 2004 and 2003, the Company's significant deferred tax
assets and liabilities are summarized as follows:

2005 2004 2003
---- ---- ----
Deferred tax assets:
Net operating loss
Carryforwards $ 402,521 $ 503,000 $ 765,000
--------- --------- ---------
Gross deferred tax assets 402,521 503,000 765,000

Less valuation allowance (402,521) (503,000) (765,000)
--------- --------- ---------
Net deferred tax asset $ - $ - $ -
========= ========= =========

Delta accounts for income tax in accordance with the provisions of
Statement of Financial Standards No. 109, "Accounting for Income Taxes"
("SFAS" 109) and includes Amber's attributes in calculating its tax
calculations. The Company is consolidated in Delta's income tax return and
accounts for its income tax as if it filed a separate return.

In assessing the realizability of deferred tax assets, management
considers whether it is more likely than not that some portion or all of the
deferred tax assets will not be realized. The ultimate realization of
deferred tax assets is dependent upon the generation of future taxable income
during the periods in which those temporary differences become deductible.
Management considers the scheduled reversal of deferred tax liabilities,
projected future taxable income, and tax planning strategies in making this
assessment. Based upon the level of historical taxable income and projections
for future taxable income over the periods in which the deferred tax assets
are deductible, management believes it is more likely than not that the
Company will realize the benefits of these deductible differences, net of the
existing valuation allowances at June 30, 2005.

At June 30, 2005, the Company had net operating loss carryforwards for
regular and alternative minimum tax purposes of approximately $1,048,000. If
not utilized, the tax net operating loss carryforwards will expire as follows:

Amount Year of Expiration
-------- ------------------

$ 73,000 2006
- 2007
15,000 2008
- 2009
960,000 2010

F-11

(5) Related Party Transactions

Effective October 1, 1998, the Company and Delta entered into an
agreement which provides for the sharing of management between the two
companies. Under this agreement the Company pays Delta $25,000 per quarter for
its share of rent, administrative, accounting and management services of Delta
officers and employees. This agreement replaces a previous agreement which
allocated similar expenses based on the Company's proportionate share of oil
and gas production. The charges to the Company for the provision of services
by Delta were $100,000 for the year ended June 30, 2005, 2004 and 2003. The
Company had a non-interest bearing receivable from Delta of $47,498 and
$157,159 recorded as a reduction in equity at June 30, 2005 and 2004,
respectively.

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

Capitalized costs related to oil and gas producing activities are as
follows:

June 30, June 30,
2005 2004
----------- -----------
Undeveloped offshore
California properties $ 5,006,560 $ 5,006,560
=========== ===========

Costs incurred in oil and gas producing activities for the years ended
June 30, 2005, 2004 and 2003 are as follows:

2005 2004 2003
---- ---- ----
Unproved property acquisition
costs $ - $ - $ 284
Exploration costs $ 235 $1,441 $ -

A summary of the results of operations for oil and gas producing
activities, excluding general and administrative cost, for the years ended
June 30, 2005, 2004 and 2003 is as follows:

2005 2004 2003
---- ---- ----
Revenue:
Oil and gas sales $ - $ - $ -
Expenses:
Lease operating - - -
Depletion - - -
Exploration 235 1,441 -
------ ------ ------
Results of operations of oil
Gas producing activities $ (235) $(1,441) $ -
======= ======== =======

F-12

AMBER RESOURCES COMPANY OF COLORADO
(A subsidiary of Delta Petroleum Corporation)
Notes to Financial Statements
Years ended June 30, 2005, 2004 and 2003
- -----------------------------------------------------------------------------

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

Statement of Financial Accounting Standards 131 "Disclosures about
Segments of an Enterprise and Related Information" (SFAS 131) establishes
standards for reporting information about operating segments in annual and
interim financial statements. SFAS 131 also establishes standards for related
disclosures about products and services, geographic areas and major customers.
The Company manages its business through one operating segment.

The Company had sold its producing properties at the beginning of fiscal
year 2002. There were no customers in 2005 and 2004.

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

Proved Oil and Gas Reserves. Proved oil and gas reserves are the
estimated quantities of crude oil, natural gas, and natural gas liquids which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions, i.e., prices and costs as of the date the estimate is
made. Prices include consideration of changes in existing prices provided only
by contractual arrangements, but not on escalations based upon future
conditions.

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

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

F-13

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

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

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

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

Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation. Under no circumstances should estimates
for proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual
tests in the area and in the same reservoir.

The Company sold all its producing properties to Delta on July 1, 2001.
As such, no reserve estimates were prepared for the past three years.

F-14

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, we have caused this Form 10-K to be signed on our behalf
by the undersigned, thereunto duly authorized, in the City of Denver and State
of Colorado on the 13th day of October, 2005

AMBER RESOURCES COMPANY OF COLORADO

By:/s/ Roger A. Parker
----------------------------------------
Roger A. Parker, Chief Executive Officer

By:/s/ Kevin K. Nanke
----------------------------------------
Kevin K. Nanke, Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, we
have duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.

Signature and Title Date
------------------- ----

/s/ Aleron H. Larson, Jr. October 13, 2005
- ---------------------------------------
Aleron H. Larson, Jr., Director

/s/ Roger A. Parker October 13, 2005
- ---------------------------------------
Roger A. Parker, Director

/s/ Jerrie F. Eckelberger October 13, 2005
- ---------------------------------------
Jerrie F. Eckelberger, Director