SECURITIES AND EXCHANGE COMMISSION
                          Washington, D.C.   20549

                                 FORM 10-KSB


                Annual Report Pursuant to Section 13 or 15(d)
                   of the Securities Exchange Act of 1934

[x] Annual Report under Section 13 or 15(d) of the Securities Exchange Act of
    1934 for the fiscal year ended June 30, 2001
                                     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
            (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 3310, 555 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 Act:  None

Securities registered pursuant to Section 12(g) of the 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-B contained in this form, and no disclosure will be contained,
to the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-KSB or any
amendment to this Form 10-KSB.  [X]

The issuer's revenue for the fiscal year ended June 30, 2001 totaled $119,425.

The aggregate market value as of the Company's voting stock held by non-
affiliates of the Company as of October 1, 2001 could not be determined
because there is no established public trading market.

As of October 1, 2001, 4,666,185 shares of registrant's Common Stock $.0625
par value were issued and outstanding.

                The Index to Exhibits appears at Page 30



<PAGE>
                             TABLE OF CONTENTS

                                 PART I

                                                                         PAGE

ITEM 1.  DESCRIPTION OF BUSINESS                                           4
ITEM 2.  DESCRIPTION OF PROPERTIES                                         8
ITEM 3.  LEGAL PROCEEDINGS                                                18
ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS              18

                                PART II

ITEM 5.  MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS         18
ITEM 6.  MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATIONS       19
ITEM 7.  FINANCIAL STATEMENTS                                             25
ITEM 8.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
           AND FINANCIAL DISCLOSURE                                       25

                               PART III

ITEM 9.  DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL
           PERSONS; COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT     25
ITEM 10. EXECUTIVE COMPENSATION                                           27
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT   27
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS                   28

                               PART IV

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K                                 29







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















                                    1

<PAGE>
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, (3) oil and gas reserves and reserve replacement and (4)
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.

     -    All of our reserve information is based on estimates.  Reservoir
          engineering is a subjective process of estimating underground
          accumulations of oil and natural gas that cannot be measured in an
          exact way.  There are numerous uncertainties inherent in
          estimating quantities of proved natural gas and oil reserves.

     -    Changes in the legal, political and/or regulatory environment
          could have a material adverse effect on our future results of

                                    2

<PAGE>
          operations and financial condition.  Our ability to economically
          produce and sell our oil and gas production is 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.











































                                    3

<PAGE>
                                 PART I


ITEM 1.     DESCRIPTION OF BUSINESS

     (a)     Business Development

     Amber Resources Company ("Amber," "we" or "us") is engaged in the
exploration, development and production of oil and gas properties.  Our
business is conducted onshore in the continental United States and in the U.S.
coastal waters offshore California.  As of June 30, 2001, our principal assets
include interests in three undeveloped Federal units located in the Santa
Barbara Channel and the Santa Maria Basin offshore California and interests in
20  producing wells in western Oklahoma (the "Oklahoma Properties").  At June
30, 2001, proved producing reserves attributable to our onshore properties
were estimated to be approximately 130,070 Mcf of gas and 1,682 Bbls of oil.
There are uncertainties as to the timing of the development of our offshore
properties.  (See "Description of Properties"; Item 2 herein.)

     We were established as a Delaware corporation on January 17, 1978.  Our
offices are located at Suite 3310, 555 17th Street, Denver, Colorado 80202.
As of June 30, 2001, Delta Petroleum 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, 2001, we had an authorized capital of 5,000,000 shares of
$1.00 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, 2001, we were engaged in only one
industry, namely the acquisition, exploration, development, and production of
oil and gas properties and related business activities.  Our oil and gas
operations have been comprised primarily of production of oil and gas.  We
currently have producing oil and gas interests in the Anadarko Basin in
Oklahoma and interests in undeveloped offshore Federal leases and units near
Santa Barbara, California.

     (1)     Principal Products or Services and Their Markets.  The principal
products produced by us are crude oil and natural gas.  The products are
generally sold at the wellhead to purchasers in the immediate area where the
product is produced.  The principal markets for oil and gas are refineries and
transmission companies which have facilities near our producing properties.

     (2)     Distribution Methods of the Products or Services.  Oil and
natural gas produced from our wells are normally sold to purchasers as
referenced in (6) below.  Oil is picked up and transported by the purchaser
from the wellhead.  In some instances we are charged a fee for the cost of
transporting the oil, which fee is deducted from or accounted for in the price
paid for the oil.  Natural gas wells are connected to pipelines generally
owned by the natural gas purchasers.  A variety of pipeline transportation

                                    4

<PAGE>
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
acquisition of undeveloped properties is a highly competitive and speculative
business.  We compete with a number of other companies, including major oil
companies and other independent operators which are more experienced and which
have greater financial resources.  We do not hold a significant competitive
position in the oil and gas industry.

     (5)     Sources and Availability of Raw Materials and Names of Principal
Suppliers.  Oil and gas may be considered raw materials essential to our
business.  The acquisition, exploration, development, production, and sale of
oil and gas are subject to many factors which are outside of our control.
These factors include national and international economic conditions,
availability of drilling rigs, casing, pipe, and other equipment and supplies,
proximity to pipelines, the supply and price of other fuels, and the
regulation of prices, production, transportation, and marketing by the
Department of Energy and other federal and state governmental authorities.

     (6)     Dependence on One or a Few Major Customers.  We have two major
customers for the sale of oil and gas as of the date of this report.  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.

     (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.

     (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.

                                    5

<PAGE>
     We believe that our operations comply in all material respects with all
applicable laws and regulations and that the existence and enforcement of such
laws and regulations have no more restrictive effect on our method of
operations than on other similar companies in the energy industry.

     The following discussion contains summaries of certain laws and
regulations and is qualified in its entirety by the foregoing.

     Environmental Regulation.
     ------------------------

     Together with other companies in the industries in which we operate, our
operations are subject to numerous federal, state, and local environmental
laws and regulations concerning 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
operation of facilities.

     Environmental laws and regulations are expected to have an increasing
impact on our operations, although it is impossible to predict accurately the
effect of future developments in such laws and regulations on our future
earnings and operations.  Some risk of environmental costs and liabilities is
inherent in 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 currently own or lease interests in numerous properties that have been
used for many years for natural gas and crude oil production.  Although the
operator of such properties may have utilized operating and disposal practices
that were standard in the industry at the time, hydrocarbons or other wastes
may have been disposed of or released on or under the properties owned or

                                    6

<PAGE>
leased by us.  In addition, some of these properties have been operated by
third parties over whom we had no control.  The U.S. Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA") and
comparable state statutes impose strict, joint and several liability on owners
and operators of sites and on persons who disposed of or arranged for the
disposal of "hazardous substances" found at such sites.  The Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes govern
the management and disposal of wastes.  Although CERCLA currently excludes
petroleum from cleanup liability, many state laws affecting our operations
impose clean-up liability regarding petroleum and petroleum related products.
In addition, although RCRA currently classifies certain exploration and
production wastes as "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.

     Under our various agreements, we have primary liability for oil spills
that occur on properties for which we act as operator.  With respect to
properties for which we do not act as operator, we are generally liable for
oil spills as a non-operating working interest owner.  We do not act as
operator for any of our offshore California properties.  The operators of our
offshore California properties are primarily liable for oil spills and are
required by the MMS to carry certain types of insurance and to post bonds in
that regard.  In addition, we also carry insurance as a non-operator in the
amount of $5 million onshore and $10 million offshore.  There is no assurance
that our insurance coverage is adequate to protect us.


                                    7

<PAGE>
     Offshore Production.
     -------------------

     Offshore oil and gas operations in U.S. waters are subject to regulations
of the United States Department of the Interior which currently impose strict
liability upon the lessee under a Federal lease for the cost of clean-up of
pollution resulting from the lessee's operations, and such lessee could be
subject to possible liability for pollution damages.  In the event of a
serious incident of pollution, the Department of the Interior may require a
lessee under Federal leases to suspend or cease operations in the affected
areas.

     (10)     Research and Development.  We do not engage in any research and
development activities.  Since its inception, Amber has not had any customer
or government-sponsored material research activities relating to the
development of any new products, services or techniques, or the improvement of
existing products.

     (11)     Environmental Protection.  Because we are engaged in acquiring,
operating, exploring for and developing natural resources, we are subject to
various state and local provisions regarding environmental and ecological
matters.  Therefore, compliance with environmental laws may necessitate
significant capital outlays, may materially affect our earnings potential, and
could cause material changes in our proposed business.  At the present time,
however, these laws do not materially hinder nor adversely affect our
business.  Capital expenditures relating to environmental control facilities
have not been material to the operation of Amber since its inception.  In
addition, we do not anticipate that such expenditures will be material during
the fiscal year ending June 30, 2002.

     (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 oil and gas properties located offshore California
and in Oklahoma.  Wells from which we receive revenues are owned only
partially by us.  We did not file oil and gas reserve estimates with any
federal authority or agency other than the SEC during our years ended June 30,
2001 and 2000.

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

     We own interests in three undeveloped federal units located in federal
waters offshore California near Santa Barbara.

                                    8

<PAGE>
     The Santa Barbara Channel and the offshore Santa Maria Basin are the
seaward portions of geologically well-known onshore basins with over 90 years
of production history.  These offshore areas were first explored in the Santa
Barbara Channel along the near shore three mile strip controlled by the state.
New field discoveries in Pliocene and Miocene age reservoir sands led to
exploration into the federally controlled waters of the Pacific Outer
Continental Shelf ("POCS").  Eight POCS lease sales and subsequent drilling
conducted between 1966 and 1984 have resulted in the discovery of an estimated
two billion Bbls of oil and three trillion cubic feet of gas.  Of these
totals, some 869 million Bbls of oil and 819 billion cubic feet of gas have
been produced and sold.  During 2000, POCS production was approximately
150,000 Bbls of oil and 210 million cubic feet of gas per day according to the
Minerals Management Service of the Department of the Interior ("MMS").  We do
not, however, own any interest in any offshore California production and there
is no assurance that any of our undeveloped properties will ever achieve
production.

     Most of the early offshore production was from Pliocene age sandstone
reservoirs.  The more recent developments are from the highly fractured zones
of the Miocene age Monterey Formation.  The Monterey is productive in both the
Santa Barbara Channel and the offshore Santa Maria Basin.  It is the principal
producing horizon in the Point Arguello field, the Point Pedernales field, and
the Hondo and Pescado fields in the Santa Ynez Unit.  Because the Monterey is
capable of relatively high productive rates, the Hondo field, which has been
on production since late 1981, has already surpassed 190 million Bbls of
production.

     California's active tectonic history over the last few million years has
formed the large linear anticlinal features which trap the oil and gas.
Marine seismic surveys have been used to locate and define these structures
offshore.  Recent seismic surveying utilizing modern 3-D seismic technology,
coupled with exploratory well data, has greatly improved knowledge of the size
of reserves in fields under development and in fields for which development is
planned.  Currently, 11 fields are producing from 18 platforms in the Santa
Barbara Channel and offshore Santa Maria Basin.   Implementation of extended
high-angle to horizontal drilling methods is reducing the number of platforms
and wells needed to develop reserves in the area.  Use of these new drilling
methods and seismic technologies is expected to continue to improve
development economics.

     Leasing, lease administration, development and production within the
Federal POCS all fall under the Code of Federal Regulations administered by
the MMS.  The EPA controls disposal of effluents, such as drilling fluids and
produced waters.  Other Federal agencies, including the Coast Guard and the
Army Corps of Engineers, also have oversight on offshore construction and
operations.

     The first three miles seaward of the coastline are administered by each
state and are known as "State Tidelands" in California.  Within the State
Tidelands off Santa Barbara County, the State of California, through the State
Lands Commission, regulates oil and gas leases and the installation of
permanent and temporary producing facilities.  Because the three units in
which we own interests are located in the POCS seaward of the three mile
limit, leasing, drilling, and development of these units are not directly
regulated by the State of California.  However, to the extent that any

                                    9

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 production is transported to an on-shore facility through the state waters,
our pipelines (or other transportation facilities) would be subject to
California state regulations.  Construction and operation of any such
pipelines would require permits from the state.   Additionally, all
development plans must be consistent with the Federal Coastal Zone Management
Act ("CZMA").   In California the decision of CZMA consistency is made by the
California Coastal Commission.

     The Santa Barbara County Energy Division and the Board of Supervisors
will have a significant impact on the method and timing of any offshore field
development through its permitting and regulatory authority over the
construction and operation of on-shore facilities.  In addition, the Santa
Barbara County Air Pollution Control District has authority in the federal
waters off Santa Barbara County through the Federal Clean Air Act as amended
in 1990.

     Each working interest owner will be required to pay its proportionate
share of these costs based upon the amount of the interest that it owns.  The
size of our working interest in these units varies from .87% to 6.97%.  We may
be required to farm out all or a portion of our interests in these properties
to a third party if we cannot fund our share of the development costs.  There
can be no assurance that we can farm out our interests on acceptable terms.

     These units have been formally approved and are regulated by the MMS.
While the Federal Government has recently attempted to expedite the process of
obtaining permits and authorizations necessary to develop the properties,
there can be no assurance that it will be successful in doing so.  We do not
act as operator of any offshore California properties and consequently will
not generally control the timing of either the development of the properties
or the expenditures for development unless we choose to unilaterally propose
the drilling of wells under the relevant operating agreements.

     The MMS initiated the California Offshore Oil and Gas Energy Resources
(COOGER) Study at the request of the local regulatory agencies of the three
counties (Ventura, Santa Barbara and San Luis Obispo) affected by offshore oil
and gas development.  A private consulting firm completed the study under a
contract with the MMS.  The COOGER Study presents a long-term regional
perspective of potential onshore constraints that should be considered when
developing existing undeveloped offshore leases.  The COOGER Study projects
the economically recoverable oil and gas production from offshore leases which
have not yet been developed.  These projections are utilized to assist in
identifying a potential range of scenarios for developing these leases.  These
scenarios are compared to the projected infrastructural, environmental and
socioeconomic baselines between 1995 and 2015.

     No specific decisions regarding levels of offshore oil and gas
development or individual projects will occur in connection with the COOGER
Study.  Information presented in the study is intended to be utilized as a
reference document to provide the public, decision makers and industry with a
broad overview of cumulative industry activities and key issues associated
with a range of development scenarios.  We have attempted to evaluate the
scenarios that were studied with respect to properties located in the eastern
and central subregions (which include the Sword Unit and the Gato Canyon Unit)
and the results of such evaluation are set forth below:

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<PAGE>
          Scenario 1     No new development of existing offshore leases.  If
          this scenario were ultimately to be adopted by governmental
          decision makers as the proper course of action for development,
          our offshore California properties would in all likelihood have
          little or no value.  In this scenario we would seek to cause the
          Federal government to reimburse us for all money spent by us and
          our predecessors for leasing and other costs and for the value of
          the oil and gas reserves found on the leases through our
          exploration activities and those of our predecessors.

          Scenario 2     Development of existing leases, using existing
          onshore facilities as currently permitted, constructed and
          operated (whichever is less) without additional capacity.  This
          scenario includes modifications to allow processing and
          transportation of oil and natural gas with different qualities.
          It is likely that the adoption of this scenario by the industry as
          the proper course of action for development would result in lower
          than anticipated costs, but would cause the subject properties to
          be developed over a significantly extended period of time.

          Scenario 3     Development of existing leases, using existing
          onshore facilities by constructing additional capacity at existing
          sites to handle expanded production.  This scenario is currently
          anticipated by our management to be the most reasonable course of
          action although there is no assurance that this scenario will be
          adopted.

          Scenario 4     Development of existing leases after
          decommissioning and removal of some or all existing onshore
          facilities.  This scenario includes new facilities, and perhaps
          new sites, to handle anticipated future production. Under this
          scenario we would incur increased costs but that revenues would be
          received more quickly.

     We have also evaluated our position with regard to the scenarios with
respect to properties located in the northern sub-region (which includes the
Lion Rock Unit), the results of which are as follows:

          Scenario 1     No new development of existing offshore leases.  If
          this scenario were ultimately to be adopted by governmental
          decision-makers as the proper course of action for development,
          our offshore California properties would in all likelihood have
          little or no value.  In this scenario we would seek to cause the
          Federal government to reimburse us for all money spent by us and
          our predecessors for leasing and other costs and for the value of
          the oil and gas reserves found on the leases through our
          exploration activities and those of our predecessors.

          Scenario 2     Development of existing leases, using existing
          onshore facilities as currently permitted, constructed and
          operated (whichever is less) without additional capacity.  This
          scenario includes modifications to allow processing and
          transportation of oil and natural gas with different qualities.
          It is likely that the adoption of this scenario by the industry as
          the proper course of action for development would result in lower

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<PAGE>
          than anticipated costs, but would cause the subject properties to
          be developed over a significantly extended period of time.

          Scenario 3     Development of existing leases, using existing
          onshore facilities by constructing additional capacity at existing
          sites to handle expanded production.  This scenario that is
          currently anticipated by our management to be the most reasonable
          course of action although there is no assurance that this scenario
          will be adopted.

          Scenario 4     Development of existing offshore leases, using
          existing onshore facilities with additional capacity or adding new
          facilities to handle a relatively low rate of expanded
          development.  This scenario is similar to #3 above but would
          entail increased costs for any new facilities.

          Scenario 5     Development of existing offshore leases, using
          existing onshore facilities with additional capacity or adding new
          facilities to handle a relatively higher rate of expanded
          development.  Under this scenario we would incur increased costs
          but revenues would be received more quickly.

     The development plans for the various units (which have been submitted to
the MMS for review) currently provide for 22 wells from one platform set in a
water depth of approximately 328 feet for the Gato Canyon Unit; 63 wells from
one platform set in a water depth of approximately 1,100 feet for the Sword
Unit; and 183 wells from two platforms for the Lion Rock Unit (in which we own
only a 1% net profits interest and do not own any working interest).

     Current Status.  On October 15, 1992 the MMS directed a Suspension of
Operations (SOO), effective January 1, 1993, for the POCS undeveloped leases
and units.  The SOO was directed for the purpose of preparing what became
known as the COOGER Study.  Two-thirds of the cost of the Study was funded by
the participating companies in lieu of the payment of rentals on the leases.

     Additionally, all operations were suspended on the leases during this
period. On November 12, 1999, as the COOGER Study drew to a conclusion, the
MMS approved requests made by the operating companies for a Suspension of
Production (SOP) status for the POCS leases and units.  During the period of a
SOP, the lease rentals resume and each operator is generally required to
perform exploration and development activities in order to meet certain
milestones set out by the MMS.  The milestones that were established by the
MMS for the properties in which we own an interest were established through
negotiations by the MMS on behalf of the United States government and the
operators on behalf of the working interest owners.  We did not directly
participate in these negotiations.  Until recently, progress toward the
milestones was monitored by the operator in quarterly reports submitted to the
MMS.  In February 2000 all operators completed and timely submitted to the MMS
a preliminary "Description of the Proposed Project".  This was the first
milestone required under the SOP.  Quarterly reports were also prepared and
submitted for all the subsequent quarters.

     On June 22, 2001, however, a Federal Court in the case of California v.
Norton, et al (discussed below) ordered the MMS to set aside its approval of
the suspensions of our offshore leases and to direct suspensions, including

                                    12

<PAGE>
all milestone activities, for a time sufficient for the MMS to provide the
State of California with a consistency determination under federal law.  As a
result of this order, on July 2, 2001 the MMS directed suspensions of
operations for all of our offshore California leases for an indefinite period
of time and suspended all of the related milestones.  The ultimate outcome and
effects of this litigation are not certain at the present time.  In order to
continue to carry out the requirements of the MMS, all operators of the units
in which we own non-operating interests are prepared to meet the next
milestone leading to development of the leases, but the status of the
milestones is presently uncertain in light of the recent court ruling.  The
United States government has filed a notice of its intent to appeal the
court's order in the Norton case.

     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,

                                    13

<PAGE>
or that we might be subject to penalties which would result in the forfeiture
of substantial revenues from the properties.

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

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

     Gato Canyon Unit. We hold a 6.97% working interest, with capitalized
costs of $3,170,602, in the Gato Canyon Unit.  This 10,100 acre unit is
operated by Samedan Oil Corporation.  Seven test wells have been drilled on
the Gato Canyon structure.  Five of these were drilled within the boundaries
of the Unit and two were drilled outside the Unit boundaries in the adjacent
State Tidelands.  The test wells were drilled as follows: within the
boundaries of the Unit; three wells were drilled by Exxon, two in 1968 and one
in 1969; one well was drilled by Arco in 1985; and, one well was drilled by
Samedan in 1989.  Outside the boundaries of the Unit, in the State Tidelands
but still on the Gato Canyon Structure, one well was drilled by Mobil in 1966
and one well was drilled by Union Oil in 1967.  In April 1989, Samedan tested
the P-0460 #2 which yielded a combined test flow rate of 5,160 Bbls of oil per
day from six intervals in the Monterey Formation between 5,880 and 6,700 feet
of drilled depth. The Monterey Formation is a highly fractured shale
formation. The Monterey (which ranges from 500' to 2,900' in thickness) is the
main productive and target zone in many offshore California oil fields
(including our federal leases and/or units).

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

                                    14

<PAGE>
     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.  Amber does not currently claim any
proved reserves in this field under the SEC definition of that term.  The Lion
Rock Unit is operated by Aera Energy LLC.

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

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

     Sword Unit.  We hold a .87% working interest, with capitalized costs of
$280,776, in the Sword Unit.  Amber does not currently claim any proved
reserves in this field under the SEC definition of that term.  This 12,240
acre unit is operated by Conoco, Inc. In aggregate, three wells have been
drilled on this unit of which two wells were completed and tested in the
Monterey formation with calculated flow rates of from 4,000 to 5,000 Bbls per
day with an estimated average gravity of 10.6E API.  The two completed test
wells were drilled by Conoco, one in 1982 and the second in 1985.

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

         As a result of the Norton case, the Sword Unit leases are held under
directed suspensions of operations with no specified end date.  An updated

                                    15

<PAGE>
Exploration Plan is expected to include plans to drill an additional
delineation well when activities are resumed.


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

map insert

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


Oklahoma.

     We own non-operated working interests in 20 natural gas wells in the
Anadarko Basin of Oklahoma.  The wells range in depth from 14,000 to 20,000
feet and produce from the Red Fork, Atoka, Morrow and Springer formations.
Most of our reserves are in the Atoka formation.  The working interests range
from less than 1% to 23% and average about 2% per well.  Many of the wells
have remaining productive lives of 20 to 30 years.

     (c)     Production
             ----------

     We are not obligated to provide a fixed and determined quantity of oil
and gas in the future under existing contracts or agreements.  During the 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.  Our average oil and gas price per unit and average
production costs per unit are set forth below:

                            Year Ended     Year Ended      Year Ended
                           June 30, 2001  June 30, 2000   June 30, 1999
                           -------------  -------------   -------------
   Average sales price:
      Oil (per barrel)        $29.61         22.50            11.63
      Natural Gas (per Mcf)     4.85          2.32             1.88
      Production costs (per
         Mcf equivalent)        1.96          1.08              .82

     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 or Plan of Operation").

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

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

          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.

                                    16

<PAGE>
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.

     Developed Oil and Gas Properties
     --------------------------------

     We annually compare our historical cost basis of each developed oil and
gas property to its expected future undiscounted cash flow from each property
(on a field by field basis).  Estimates of expected future cash flows
represent management's best estimate based on reasonable and supportable
assumptions and projections.  If the expected future cash flows exceed the
carrying value of the property, no impairment is recognized.  If the carrying
value of the property exceeds the expected future cash flows, an impairment
exists and is measured by the excess of the carrying value over the estimated
fair value of the asset.

     Any impairment provisions recognized for developed and undeveloped
properties are permanent and may not be restored in the future.

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

     The table below shows, as of June 30, 2001, the approximate number of
gross and net producing oil and gas wells by state and their related developed
acres owned by us.  Productive wells are producing wells capable of
production, including shut-in wells.  Developed acreage consists of acres
spaced or assignable to productive wells.

                      Oil                    Gas           Developed Acres
               Gross(1)  Net (2)     Gross (1)  Net(2)     Gross(1)  Net(2)
               --------  -------     ---------  ------     --------  ------
     Oklahoma     0        0            20       0.41       3,200     211


     (1)     A "gross well" or "gross acre" is a well or acre in which a
             working interest is held.  The number of gross wells or acres is
             the total number of wells or acres in which a working interest is
             owned.

     (2)     A "net well" or "net acre" is deemed to exist when the sum of
             fractional ownership interests in gross wells or acres equals
             one.  The number of net wells or net acres is the sum of the
             fractional working interests owned in gross wells or gross acres
             expressed as whole numbers and fractions thereof.







                                    17

<PAGE>
     (e)     Undeveloped Acreage.
             -------------------
     At June 30, 2001, 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, 2001, we participated in the completion of
one well.


ITEM 3.     LEGAL PROCEEDINGS

     There is no litigation pending or threatened by or against us or any of
our properties as of June 30, 2001.


ITEM 4.     SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

     None.


                                     PART II

ITEM 5.     MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

     (a)     Market or Markets:
             -----------------

     We currently have, and have had for the past three years, only limited
trading in the over-the-counter market and there is no assurance that this
trading market will expand or even continue.  Recent regulations and rules by
the SEC and the National Association of Securities Dealers virtually assure
that there will be little or no trading in our stock unless and until we are
listed on NASDAQ or another exchange.  There is no assurance that we will be
able to meet the requirements for such listing in the foreseeable future.
Further, our capital stock may not be able to be traded in certain states
until and unless we are able to qualify, exempt or register our stock.
Quotations during 2001 and 2000 have not been available.





                                    18

<PAGE>
     (b)     Approximate Number of Holders of Common Stock:
             ---------------------------------------------

     The number of holders of record of our securities at June 30, 2001 was
approximately 1,000.

     (c)     Dividends:
             ---------

     We have not declared any cash dividends and have no plan for the payment
of dividends on our Common Stock in the foreseeable future.  Future payment of
such dividends, if any, will depend on the applicable legal and contractual
restrictions including those discussed above, as well as our financial
condition and financial requirements and general conditions.


ITEM 6.     MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATIONS.

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

     General
     -------

     At June 30, 2001, we had working capital of $6,315 compared to a working
capital deficit of $56,143 at June 30, 2000.  Our working capital deficit
during fiscal 2000 was primarily a result of deferred revenue.  Deferred
revenue primarily represents amounts received for gas produced and delivered
to a gas purchaser pursuant to the terms of recoupment agreements on
properties that we acquired.  We deferred an amount pending a determination of
our revenue interest based on the market price of the gas during the period
the gas that was produced and delivered to the purchaser.  Deferred revenue
also includes other amounts received where our interest was not confirmed.
The statute of limitations has expired for these deferred amounts and
accordingly, $51,667 and $62,656 for the years ended June 30, 2001 and 2000,
respectively, have been written off and recorded as a component of other
revenue.

     Offshore
     --------

     The undeveloped leases in which we own interests were issued during the
early 1980s (with the exception of the Sword Unit leases issued in 1979) and
carried a primary term of five years.  During those primary terms, oil and gas
in commercial quantities were discovered in all of the unit areas in which we
own interests.  Applicable statutes and regulations require that a lease
beyond its primary term must be maintained either by production or drilling
operations (conducted under an approved Exploration Plan or Development and
Production Plan, or under a suspension of production or suspension of
operations).

     Applicable federal regulations set forth a number of reasons for which
the MMS may either grant or direct a suspension of operations or suspension of
production.  It is common practice for lease suspensions of this nature to be
issued by the MMS either to aid the operator in accommodating necessary

                                    19

<PAGE>
activities or unavoidable delays or to accommodate environmental concerns or
national security issues.  These suspensions are issued when it is necessary
to allow the proper development of unitized leases on which discoveries of
commercial quantities of oil and gas have occurred.  Our leases are currently
held under suspensions issued on that basis.  Although the issuance of future
suspensions is subject to MMS discretion, the applicable statutes and
regulations, as well as past practice in the Pacific Outer Continental Shelf
region, support the issuance of future suspensions as necessary to facilitate
development so long as the operators continue diligent efforts to achieve
production.

     There are certain milestones that were previously established by the MMS
for two of our three undeveloped offshore California units.  The specific
milestones for each of the four units vary depending upon the operator of the
unit. On July 2, 2001, however, these milestones were suspended by the MMS in
compliance with an order entered by a Federal Court on June 22, 2001 in the
case of California v. Norton.  In that case, the California Coastal Commission
sued the United States government claiming, in essence, that the lease
suspensions that were granted by the MMS while the COOGER Study was being
completed violated the requirements of the Coastal Zone Management Act
because, in granting those suspensions, the MMS did not make a determination
that the suspensions were consistent with California's coastal management
program.  The Court agreed with California and ordered the MMS to set aside
its approval of the subject suspensions and to direct suspensions of all of
the subject leases, including all milestone activities, for a time sufficient
for the MMS to provide the State of California with a consistency
determination under the Coastal Zone Management Act.  The July 2, 2001 letters
from the MMS which direct suspension of the milestones indicate that the MMS
will review the previously submitted (and approved) suspension requests under
the provisions of the Coastal Zone Management Act as directed by the court.
The current suspensions of operations directed by the letters do not specify
an end date.

     The MMS has issued letters to all of the operators of the affected
leases offering the opportunity to modify the previously submitted suspension
of production requests.  Burdette A. Ogle, a consultant to us for our offshore
California properties, has informed us that he believes the end-date of the
suspensions of production will likely be the anticipated spud date for the
delineation wells set forth in the operators' respective requests for
suspension of production. During this period the leases will be held by the
suspensions.

     The suspensions themselves authorize only preliminary activities, not
operations, on the leases.  The operations (i.e., drilling the next
delineation wells) will be conducted under Exploration Plans ("EPs").  The
operators intend to submit proposed Exploration Plans to the MMS for approval
significantly before the expiration of the suspensions.

     Within 30 days of the date upon which the proposed EP is deemed
"submitted" (usually after further revisions at the request of the MMS), the
MMS is required to either: (1) approve the plan; (2) require the lessee to
modify the plan, in which case the lessee may resubmit the modified plan; or
(3) disapprove the plan if the MMS determines that the proposed activity would
probably cause serious environmental harm which cannot be mitigated.

                                    20

<PAGE>
     Disapproval of an Exploration Plan does not, in and of itself, effect a
cancellation of a lease.  Under Federal Regulations (30 CFR Sec.
250.203(k)(2)), a lessee may resubmit a disapproved plan if there is a change
in the circumstances which caused it to be disapproved.  Further, the Federal
Regulations contemplate that the lessee will work to modify the disapproved EP
to accommodate the environmental concerns for a period of up to five years,
during which time the lease would be held under a suspension.   If the leases
were ultimately cancelled on the basis of this Exploration Plan disapproval,
the regulations contemplate that compensation would be required.

     If an Exploration Plan is approved, a delineation well would be spudded
prior to the end of the applicable suspension.  Once drilling is underway, the
lease is held by operations.  At the end of drilling operations, the lessee
has a 180-day period to commence further operations (under an Exploration Plan
or a Development and Production Plan) or to obtain a further suspension.  In
practice, the lessee would seek a suspension to allow for time to evaluate the
results of delineation drilling and prepare a Development and Production Plan.
Again, the applicable sections of the regulations accommodate suspensions for
this purpose.

     During any such suspension, the operator would submit a proposed
Development and Production Plan to the MMS.  Within 60 days of the last day of
the applicable comment periods, the MMS must: (1) approve the Development and
Production Plan; (2) require modification of the Development and Production
Plan; or (3) disapprove the Development and Production Plan, due to (i) the
operator's failure to comply with applicable law, (ii) failure to obtain state
consistency concurrence, (iii) national security or defense issues, or (iv)
environmental concerns.  As with the Exploration Plan, disapproval does not
effect a lease cancellation.  Again, the regulations contemplate that the
lessee will work to modify the disapproved Development and Production Plan (or
resolve the Coastal Zone Management Act issues) for a period of up to five
years, during which the lease would most likely be held under a granted
suspension.

     As discussed above, all of the leases in which we hold an interest were
originally issued for a primary term of five years, and MMS suspensions have
the effect of extending the term of the lease for the period of the
suspension.  All of our leases must be maintained either through production,
drilling operations or suspensions.  Annual rentals under all leases equal
$3/acre.  Rentals were waived during the COOGER Study period (from January 1,
1993 through November 15, 1999).  The MMS has also waived rentals during the
current suspensions of operations beginning July 2, 2001.  As these
suspensions do not state a definite end date, the date through which rentals
will be waived is not known.

      The Sword and Gato Canyon units are operated by Samedan Oil Corporation.
In May 2000, Samedan acquired Conoco, Inc.'s interest in the Sword Unit.
Prior to such time, as operator Conoco timely submitted the Project
Description for the Sword Unit in February 2000. However, since becoming the
operator, Samedan has informed the MMS that it has plans to submit a revised
Project Description for the Sword Unit.  The new plan is to develop the field
from Platform Hermosa, an existing platform, rather than drilling a
delineation well on Sword and then abandoning it.  Prior to the suspension of
milestones in accordance with the Court's order in the Norton case, the next
scheduled milestone for the Sword Unit was the DPP for Platform Hermosa, which

                                    21

<PAGE>
was to be submitted to the MMS in September 2001.  When the DPP is filed, it
is estimated that the cost will be approximately $360,000, with Amber's share
being $3,600.

      In February 2000, Samedan timely submitted the Project Description for
the Gato Canyon Unit.  In August 2000, after responding to an MMS request for
additional information and clarification, Samedan filed the revised Project
Description.  Prior to the suspensions granted under the Norton decision, the
updated Exploration Plan for the Gato Canyon Unit was to be submitted to the
MMS in September 2001.  It is estimated that the cost of the updated
Exploration Plan will be approximately $300,000, with Amber's share being
$21,000.  If and when milestones are reinstated, it is anticipated that the
next milestone for Gato Canyon would still be to show proof that a Request for
Proposal has been prepared and distributed to the appropriate drilling
contractors as described in the revised Project Descriptions. At the time
milestones were suspended by the MMS, the milestone date for the RFP was
November 2001. It is estimated that it will cost $450,000 to complete the RFP,
with Amber's cost estimated at $36,000.  Prior to its suspension, the last
milestone was to begin drilling operations on the Gato Canyon Unit by May 1,
2003 using the committee's drilling unit.  The cost of the drilling operations
are estimated to be $11,000,000 with Amber's share being $776,700.

     Our working interest share of the future estimated development costs
based on estimates developed by the operating partners relating to our three
undeveloped offshore California units is approximately $27 million.  Because
the amounts required for development of these undeveloped properties are so
substantial relative to our present financial resources, we may ultimately
determine to farmout all or a portion of our interest.  If we were to farmout
our interests, our interest in the properties would be decreased
substantially.  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.  Alternatively, we may pursue other methods of
financing, including selling equity or debt securities.  There can be no
assurance that we can obtain any such financing.  If we were to sell
additional equity securities to finance the development of the properties, the
existing common stockholders' interest would be diluted significantly.

     At the present time we believe that all of the costs capitalized for our
offshore California properties will be fully recovered through future
development and production in spite of the factors discussed above, including,
without limitation, our inability to submit exploration plans for the Lion
Rock, Gato Canyon and Sword Units since their acquisition in 1992, the
extensive development necessary to access production from those Units, the
uncertainty created by the court ruling in June, 2001 in the Norton case, the
current suspension of operations prohibiting exploratory activities on the
properties and our inability to effect any development due to our status as an
investor as opposed to being the operator of the properties.

     Based on discussions with the MMS and operators of the properties, we
currently believe that the MMS, in cooperation with the property interest
owners, will provide the State of California with a consistency determination
under the Coastal Zone Management Act that will allow exploration and

                                    22

<PAGE>
development plans to be prepared.  Furthermore, we believe that the MMS will
seek to modify the previously submitted suspension of production requests to
focus solely on "preliminary activities," and will approve new suspension of
production requests that do not contain any "milestones" per se, as the stated
milestones in the previous suspensions of production appear to have been a
significant factor in the court's decisions.  We also believe that the end-
date of any such new suspensions of production will likely be the anticipated
spud date for the delineation wells set forth in the operators' respective
requests for suspensions of production.

     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 are committed to
expend 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 values of our property interests
are in excess of their carrying value at June 30, 2001, June 30, 2000 and June
30, 1999 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.

     Capital Resources
     -----------------

     We do not currently have a credit facility with any bank and we have not
determined the amount, if any, that we could borrow against our existing
properties.  Together with Delta, we will continue to seek additional sources
of both short-term and long-term liquidity to fund our working capital deficit
and our capital requirements for development of our properties, including
establishing a credit facility, sale of equity or debt securities and sale of
non-strategic properties 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, cash flow from our existing producing properties,
proceeds from the sale of oil and gas properties, 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
     ---------------------

     Net Income.  Our net losses for the years ended June 30, 2001 and 2000
were $42,628 and $67,494, respectively.

     Revenue.  Total revenue for the year ended June 30, 2001 was $119,425
compared to $100,245 for the year ended June 30, 2000.  Oil and gas sales for
the year ended June 30, 2001 was $67,738 compared to $37,579 for the year
ended June 30, 2000.   The increase in oil and gas sales for the year ended
June 30, 2001 compared to the year ended June 30, 2000 is attributable to the
increase in oil and gas price during fiscal 2001.

                                    23

<PAGE>
     Other Revenue.  Other revenue includes amounts recognized from the
production of gas previously deferred pending determination of our interest in
the properties.

     Production volumes and average prices received for the years ended June
30, 2001 and 2000 are as follows:

                                Year Ended             Year Ended
                               June 30, 2001          June 30, 2000
                               -------------          -------------
     Production:
        Oil (barrels)               381                    488
        Gas (Mcf)                11,630                 11,443

     Average Price:
          Oil (per barrel)       $29.61                  22.50
          Gas (per Mcf)          $ 4.85                   2.32

     Lease Operating Expenses.  Lease operating expenses for the year ended
June 30, 2001 was $22,827 compared to $15,528 for the year ended June 30,
2000.  On an MCF equivalent basis production expenses and taxes were $1.96 per
Mcf equivalent during the year ended June 30, 2001 compared to $1.08 for the
year ended June 30, 2000.

     Depletion Expense.  Depletion expense for the year ended June 30, 2001
was $10,608 compared to $14,417 for the year ended June 30, 2000.

     Exploration Expenses.  Exploration expenses consist of geological and
geophysical costs and lease rentals.  We incurred exploration costs of $17,482
and $7,189 for the years ended June 30, 2001 and 2000, respectively.

     General and Administrative Expenses.  General and administrative expense
for the year ended June 30, 2001 was $111,136 compared to $130,605 for the
year ended June 30, 2000.

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

     In July 2001, the Financial Accounting Standards Board issued SFAS No.
141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible
Assets" and approved for issuance SFAS No. 143, "Accounting for Asset
Retirement Allocations." SFAS No. 141 requires that the purchase method of
accounting be used for all business combinations initiated or completed after
June 30, 2001. SFAS No. 141 also specifies criteria that intangible assets
acquired in a purchase method business combination must meet to be recognized
and reported apart from goodwill. The adoption of SFAS No. 141 will have no
impact on our fiscal 2001 financial statements.

     SFAS No. 142 requires that goodwill no longer be amortized, but instead
tested for impairment at least annually in accordance with the provisions of
SFAS No. 142. Any goodwill and any intangible asset determined to have an
indefinite useful life that are acquired in a purchase business combination
completed after June 30, 2001 will not be amortized, but will be evaluated for

                                    24

<PAGE>
impairment in accordance with the appropriate existing accounting literature.
The adoption will have no impact on our fiscal 2001 financial statements.

     SFAS No. 143 requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset
and is effective for fiscal years beginning after June 15, 2002.  Management
is currently assessing the impact SFAS No. 143 will have on our financial
condition and results of operations.


ITEM 7.     FINANCIAL STATEMENTS

     Financial Statements are included beginning on Page F-1.


ITEM 8.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
            FINANCIAL DISCLOSURE.

            Not applicable.


                                  PART III

ITEM 9.     DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

            Executive Officers and Directors:

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

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

Aleron H. Larson, Jr.     56   Chairman of the Board,     May 1987 to Present
                               Secretary, and a Director

Roger A. Parker           39   President, Chief           May 1987 to Present
                               Executive Officer and
                               a Director

Terry D. Enright          52   Director                   November 1987 to
                                                          Present

Jerrie F. Eckelberger     57   Director                   September 1996
                                                          to Present

Kevin K. Nanke            36   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.

                                    25

<PAGE>
     Aleron H. Larson, Jr., age 56, has operated as an independent in the oil
and gas industry individually and through public and private ventures since
1978.  From July of 1990 through March 31, 1993, Mr. Larson served as the
Chairman, Secretary, CEO and a Director of Chippewa Resources Corporation (now
called "Underwriters Financial Group, Inc."), a public company then listed on
the American Stock Exchange which was previously our parent ("UFG").
Subsequent to a change of control, Mr. Larson resigned from all positions with
UFG effective March 31, 1993.  Mr. Larson serves as Chairman of the Board,
Secretary and Director of Delta Petroleum Corporation ("Delta"), a public oil
and gas company which is our parent corporation.  He has also served, since
1983, as the President and Board Chairman of Western Petroleum Corporation, a
public Colorado oil and gas company which is now inactive.  Mr. Larson
practiced law in Breckenridge, Colorado from 1971 until 1974.  During this
time he was a member of a law firm, Larson & Batchellor, engaged primarily in
real estate law, land use litigation, land planning and municipal law.  In
1974, he formed Larson & Larson, P.C., and was engaged primarily in areas of
law relating to securities, real estate, and oil and gas until 1978.  Mr.
Larson received a Bachelor of Arts degree in Business Administration from the
University of Texas at El Paso in 1967 and a Juris Doctor degree from the
University of Colorado in 1970.

     Roger A. Parker, age 39, served as the President, a Director and Chief
Operating Officer of Chippewa Resources Corporation (now called "Underwriters
Financial Group, Inc.") from July of 1990 through March 31, 1993.  Mr. Parker
resigned from all positions with UFG effective March 31, 1993.  Mr. Parker
also serves as President, Chief Executive Officer and Director of Delta.  He
also serves as a Director and Executive Vice President of P & G Exploration,
Inc., a private oil and gas company (formerly Texco Exploration, Inc.).  Mr.
Parker has also been the President, a Director and sole shareholder of Apex
Operating Company, Inc. since its inception in 1987.  He has operated as an
independent in the oil and gas industry individually and through public and
private ventures since 1982.  He was at various times, from 1982 to 1989, a
Director, Executive Vice President, President and shareholder of Ampet, Inc.
He received a Bachelor of Science in Mineral Land Management from the
University of Colorado in 1983.  He is a member of the Rocky Mountain Oil and
Gas Association and the Independent Producers Association of the Mountain
States (IPAMS).

     Terry D. Enright, age 52, has been in the oil and gas business since
1980.  Mr. Enright was a reservoir engineer until 1981 when he became
Operations Engineer and Manager for Tri-Ex Oil & Gas.  In 1983, Mr. Enright
founded and is President and a Director of Terrol Energy, a private,
independent oil company with wells and operations primarily in the Central
Kansas Uplift and D-J Basin. In 1989, he formed and became President and a
Director of a related company, Enright Gas & Oil, Inc.  Since then, he has
been involved in the drilling of prospects for Terrol Energy, Enright Gas &
Oil, Inc., and for others in Colorado, Montana and Kansas.  He has also
participated in brokering and buying of oil and gas leases and has been
retained by others for engineering, operations, and general oil and gas
consulting work.   Mr. Enright received a B.S. in Mechanical Engineering with
a minor in Business Administration from Kansas State University in Manhattan,
Kansas in 1972, and did graduate work toward an MBA at Wichita State
University in 1973.  He is a member of the Society of Petroleum Engineers and
a past member of the American Petroleum Institute and the American Society of
Mechanical Engineers, and also serves as a director for Delta.

                                    26

<PAGE>
     Jerrie F. Eckelberger, age 57, 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 1982 to
1992 Mr. Eckelberger was the senior partner of Eckelberger & Feldman, a law
firm with offices in Englewood, Colorado.   In 1992, Mr. Eckelberger founded
Eckelberger & Associates of which he is still the principal member.  Mr.
Eckelberger previously served as an officer, director and corporate counsel
for Roxborough Development Corporation.   Since March 1996, Mr. Eckelberger
has acted as President and Chief Executive Officer of 1998, Ltd., a Colorado
corporation actively engaged in the development of real estate in Colorado.
He is the Managing Member of The Francis Companies, L.L.C., a Colorado limited
liability company, which actively invests in real estate and has been since
June, 1996.  Additionally, since November, 1997, Mr. Eckelberger has served as
the Managing Member of the Woods at Pole Creek, a Colorado limited liability
company, specializing in real estate development.  Mr. Eckelberger also serves
as a director for Delta.

     Kevin K. Nanke, age 36, Treasurer and Chief Financial Officer, joined
Amber (and Delta) in April 1995.  He also serves as Treasurer and Chief
Financial Officer 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 Delta and Amber, he was employed by KPMG LLP.  He is a
member of the Colorado Society of CPA's and the Council of Petroleum
Accounting Society.  Mr. Nanke is not a nominee for election as a director.

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

     Messrs. Enright and Eckelberger serve as the audit committee and as the
compensation committee.


ITEM 10.    EXECUTIVE COMPENSATION.

     No officer or director received compensation directly from us during the
years ended June 30, 2001, 2000 and 1999.  Messrs. Larson, Parker and 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 11.    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.



                                    27

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

Delta Petroleum Corporation       4,277,977 (1)             91.68% (1)
555 17th Street, Suite 3310
Denver, Colorado 80202

Roger A. Parker                   4,277,977 (1)             91.68% (1)
555 17th St., Ste. 3310
Denver, CO  80202

Aleron H. Larson, Jr.             4,277,977 (1)             91.68% (1)
555 17th St., Ste. 3310
Denver, CO  80202

Terry D. Enright                  4,277,977 (1)             91.68% (1)
P.O. Box 227
Hygiene, Colorado 80533

Jerrie F. Eckelberger             4,277,977(1)              91.68% (1)
5575 DTC Parkway, #118
Englewood, CO 80111

Kevin K. Nanke                    4,277,977 (1)             91.68%(1)
555 17th St., Ste 3310
Denver, Colorado 80202

Management as a Group (5 people)  4,277,977(1)              91.68% (1)

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

(1)     All shares are owned by Delta; Messrs. Larson, Parker and Nanke are
        officers, directors and controlling shareholders of Delta. Messrs.
        Enright and Eckelberger are also directors of Delta.


ITEM 12.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

     Effective October 1, 1998, we entered into an agreement with Delta which
provides for the sharing of management between the two companies.  Under this
agreement we pay Delta $25,000 per quarter for our share of rent,
administrative, accounting and management services of Delta officers and
employees.  This agreement is cancellable by either party at any time.  It is
our opinion that fees paid to Delta for services rendered are comparable to
fees that would be charged by similarly qualified non-affiliated persons.
This agreement replaces a previous agreement which allocated similar expenses
based on our proportionate share of oil and gas production. The charges to us
for the provision of services by Delta were $100,000 for the years ended June
30, 2001 and 2000.  We had a receivable from Delta of $404,000 and $505,000
recorded as a reduction in equity at June 30, 2001 and 2000, respectively.




                                    28

<PAGE>
                                    PART IV

ITEM 13.    EXHIBITS AND REPORTS ON FORM 8-K

     (a)     Exhibits:
             --------

      The Exhibits listed in the Index to Exhibits appearing at page 30 are
filed as part of this report.

     (b)     Reports on Form 8-K:  None










































                                    29

<PAGE>
                              INDEX TO EXHIBITS

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

(3)     Articles of Incorporation and Bylaws.  The Articles of Incorporation
        (Certificate of Incorporation) and Bylaws of the Registrant filed as
        Exhibits 4 and 5 to Registrant's Form S-1 Registration Statement filed
        August 28, 1978 with the Securities and Exchange Commission are
        incorporated herein by reference. The Restated Articles of
        Incorporation (Restated Certificate of Incorporation) dated January
        26, 1988 and Amendment to Restated Certificate of Incorporation dated
        September 18, 1989 are attached hereto as Exhibits 3.1 and 3.2,
        respectively.

(4)     Instruments Defining the Rights of Security Holders.

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

(9)     Voting Trust Agreement.  Not applicable.

(10)    Material Contracts.

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

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

        10.3     Agreement between Amber Resources Company and Delta Petroleum
                 Corporation dated effective October 1, 1998.

(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.

                                    30

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

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

(24)    Power of Attorney.  Not applicable.

(27)    Financial Data Schedule. Not applicable.

(99)    Additional Exhibits. Not applicable.












































                                    31

<PAGE>
                          Independent Auditors' Report


The Board of Directors and Stockholders
Amber Resources Company:


We have audited the accompanying balance sheets of Amber Resources Company
(the "Company"), a subsidiary  of  Delta Petroleum Corporation, as of June 30,
2001 and 2000 and the related statements of operations and accumulated
deficit, and cash flows for the years then ended. These financial statements
are  the responsibility of the Company's management.  Our responsibility is to
express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Amber Resources Company as of
June 30, 2001 and 2000, and the results of its operations and its cash flows
for each of the years in the two-year period ended June 30, 2001, in
conformity with accounting principles generally accepted in the United States
of America.




                                     s/KPMG
                                     KPMG LLP


Denver, Colorado
October 5, 2001


















                                    F-1


<PAGE>
AMBER RESOURCES COMPANY
BALANCE SHEETS
June 30, 2001 and 2000


                                                       2001         2000
                                                    ----------   ----------
ASSETS

Current Assets:
     Cash                                           $   14,992   $    5,422
     Accounts receivable                                 7,855        3,000
                                                    ----------   ----------
          Total current assets                          22,847        8,422
                                                    ----------   ----------
Property and Equipment:
     Oil and gas properties, at cost (using
       the successful efforts method
       of accounting):
     Undeveloped offshore California properties      5,006,276    5,006,276
     Developed onshore domestic properties             203,053      195,531
                                                    ----------   ----------
                                                     5,209,329    5,201,807
     Less accumulated depreciation and depletion      (169,968)    (159,360)
                                                    ----------   ----------
          Net property and equipment                 5,039,361    5,042,447
                                                    ----------   ----------
                                                    $5,062,208   $5,050,869
                                                    ==========   ==========
LIABILITIES AND STOCKHOLDERS' EQUITY


Current  Liabilities:
     Accounts payable                               $   16,532   $   12,898
     Deferred revenue                                        -       51,667
                                                    ----------   ----------
          Total current liabilities                     16,532       64,565
                                                    ----------   ----------
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, 2001 and 2000      291,637      291,637
     Additional paid-in capital                      5,755,232    5,755,232
     Accumulated deficit                              (597,564)    (554,936)
     Advance to parent                                (403,629)    (505,629)
                                                    ----------   ----------
     Total stockholders' equity                      5,045,676    4,986,304
                                                    ----------   ----------
Commitments
                                                    $5,062,208   $5,050,869
                                                    ==========   ==========

         See accompanying notes to consolidated financial statements.


                                    F-2


<PAGE>
AMBER RESOURCES COMPANY
STATEMENTS OF OPERATIONS AND ACCUMULATED DEFICIT
Years Ended June 30, 2001 and 2000



                                                  2001           2000
                                               ----------     ----------
Revenue:
     Oil and gas sales                         $   67,738     $   37,579
     Other revenue                                 51,667         62,656
     Other income                                      20             10
                                               ----------     ----------
          Total revenue                           119,425        100,245


Operating expenses:
     Lease operating expenses                      22,827         15,528
     Depreciation and depletion                    10,608         14,417
     Exploration expenses                          17,482          7,189
     General and administrative, including
       $100,000 in 2001 and 2000 to parent        111,136        130,605
                                               ----------     ----------
          Total operating expenses                162,053        167,739
                                               ----------     ----------

          Net loss                                (42,628)       (67,494)

     Accumulated deficit at
          beginning of the year                  (554,936)      (487,442)
                                               ----------     ----------
     Accumulated deficit at
          end of the year                      $ (597,564)    $ (554,936)
                                               ==========     ==========

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






          See accompanying notes to consolidated financial statements.





                                  F-3


<PAGE>
AMBER RESOURCES COMPANY
STATEMENTS OF CASH FLOWS
Years Ended June 30, 2001 and 2000


                                                       2001         2000
                                                    ---------    ----------

Cash flows operating activities:
   Net loss                                         $ (42,628)   $ (67,494)
   Adjustments to reconcile net loss to cash
       used in operating activities:
     Depletion                                         10,608        14,417
   Net changes in operating assets and operating
       liabilities:
   Increase in trade accounts receivable               (4,855)       (1,000)
   Increase (decrease) in accounts payable trade        3,634        (6,799)
   Deferred revenue                                   (51,667)      (62,656)
                                                    ---------    ----------

Net cash used in operating activities                 (84,908)     (123,532)
                                                    ---------    ----------
Cash flows from investing activities-
   Additions to property and equipment                 (7,522)            -
                                                    ---------    ----------
Cash flows from financing activities-
   Changes in accounts receivable from and
     accounts payable to parent                       102,000       127,993
                                                    ---------    ----------

Net increase in cash                                    9,570         4,461
                                                    ---------    ----------

Cash at beginning of period                             5,422           961
                                                    ---------    ----------

Cash at end of period                               $  14,992    $    5,422
                                                    ---------    ----------










         See accompanying notes to consolidated financial statements.






                                    F-4


<PAGE>
AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------

(1)  Summary of Significant Accounting Policies

     Organization

     Amber Resources Company ("the Company") was incorporated in January,
1978, and is principally engaged  in  acquiring, exploring, developing, and
producing oil and gas properties. The Company owns interests in undeveloped
oil and gas properties in federal units offshore California, near Santa
Barbara, and developed oil and gas properties in the continental United
States.  As of June 30, 2001, Delta Petroleum Corporation 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.  These factors among others may indicate that without
increased cash flow from operations, sale of oil and gas properties  or
additional financing the Company may not be able to meet its obligation in a
timely manner or be able to fund exploration and development of its oil and
gas properties.

    One aspect of the Company's business activities has been the buying and
selling of oil and gas properties. In the past the Company has sold properties
to fund its working capital deficits and/or its funding needs.  Should the
Company be unable to achieve its projected cash flow from operations
additional financing or sale of oil and gas properties could be necessary. The
Company believes that it could sell oil and gas properties or obtain
additional financing, however, there can be no assurance that such financing
would be available on a timely or acceptable terms.

     Oil and Gas Properties

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

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

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

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

                                    F-5


AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------

     Certain of the Company's oil and gas activities  are conducted through
partnerships and joint ventures, the Company  includes its proportionate share
of  assets, liabilities, revenues and expenses in its consolidated financial
statements. Partnership net assets represents the Company's share of net
working capital in such entities.

     Impairment of Long-Lived Assets

     Statement of Financial Accounting Standards 121 "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of"
(SFAS 121) requires that long-lived assets be reviewed for impairment when
events or changes in circumstances indicate that the carrying value of such
assets may not be recoverable.  For developed properties, the review consists
of a comparison of the carrying value of the asset with the asset's expected
future undiscounted cash flows without interest costs.

     Estimates of expected future cash flows represent management's best
estimate based on reasonable and supportable assumptions and projections.  If
the expected future cash flows exceed the carrying value of the asset, no
impairment is recognized.  If the carrying value of the asset exceeds the
expected future cash flows, an impairment exists and is measured by the excess
of the carrying value over the estimated fair value of the asset.  Any
impairment provisions recognized in accordance with SFAS 121 are permanent and
may not be restored in the future.

   The Company assesses developed properties on an individual field basis for
impairment on at least an annual basis.

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

     Gas Balancing

     The Company uses the sales method of accounting for gas balancing of gas
production.  Under this method, all proceeds from production credited to the
Company are recorded as revenue until such time as the Company has produced
its share of the total estimated reserves of the property.  Thereafter,
additional amounts received are recorded as a liability.







                                   F-6


<PAGE>
AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------

As of June 30, 2001, the Company had produced and recognized as revenue
approximately 67,000 Mcf more than its share of production.  The undiscounted
value of this imbalance is approximately $201,000 using the lower of the price
received for the natural gas, the current market price or the contract price,
as applicable.

    Deferred Revenue

     Deferred revenue primarily represents amounts received for gas produced
and delivered where the Company was uncertain as to the distribution of
amounts attributable to its interest, including amounts from a gas purchaser
under the terms of a recoupment agreement on properties that the Company
acquired during the Amber acquisition.  The Company deferred amounts pending a
determination of the Company's revenue interest.

     The statute of limitation has expired for these deferred amounts and
accordingly $51,667 and $62,656 for the years ended June 30, 2001 and 2000,
respectively, have been written off and recorded as a component of other
income.

     Income Taxes

     The Company uses the asset and liability method  of accounting for income
taxes as set forth in Statement of Financial Accounting Standards 109 (SFAS
109), Accounting for Income Taxes. Under the asset and liability method,
deferred tax assets and liabilities are recognized for the future  tax
consequences attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases and net operating loss and tax credit carryforwards. Deferred tax assets
and liabilities are measured using enacted income tax rates expected to apply
to taxable income in the years in which those differences are expected to be
recovered or settled. Under SFAS 109, the effect on deferred tax assets and
liabilities of a change in income tax rates is recognized in the results of
operations in the period that includes the enactment date.  The company is
consolidated in the Delta Petroleum Corporation's ("Delta"), the Company's
parent, income tax return.






                                    F-7


<PAGE>
AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------

Earnings (Loss) per Share

     Basic earnings (loss) per share is computed by dividing net earnings
(loss) attributes to common stock by the weighted average number of common
shares outstanding during each period, excluding treasury shares.  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. Actual results could differ from these estimates.

     Recently Issued Accounting Standards and Pronouncements

     In July 2001, the Financial Accounting Standards Board issued SFAS No.
141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible
Assets" and approved for issuance SFAS No. 143, "Accounting for Asset
Retirement Allocations." SFAS No. 141 requires that the purchase method of
accounting be used for all business combinations initiated or completed after
June 30, 2001. SFAS No. 141 also specifies criteria that intangible assets
acquired in a purchase method business combination must meet to be recognized
and reported apart from goodwill.  The adoption of SFAS No. 141 will have no
impact on Amber's fiscal 2001 financial statements.

     SFAS No. 142 requires that goodwill no longer be amortized, but instead
tested for impairment at least annually in accordance with the provisions of
SFAS No. 142. Any goodwill and any intangible asset determined to have an
indefinite useful life that are acquired in a purchase business combination
completed after June 30, 2001 will not be amortized, but will be evaluated for
impairment in accordance with the appropriate existing accounting literature.
The adoption of SFAS No. 142 will have no impact on Amber's fiscal 2001
financial statements.

     SFAS No. 143 requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset
and is effective for fiscal years beginning after June 15, 2002.  The Company
is currently assessing the impact SFAS No. 143 will have on its financial
condition and results of operations.






                                  F-8

<PAGE>
AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------

(2)  Preferred Stock

     The Board of Directors is authorized to issue 5,000,000 shares of 9%
Class A convertible preferred stock having a par value of $1 per share. At the
option of the Company, this preferred stock is convertible at a rate of .625
shares of common stock for each share of Class A convertible preferred stock.
As of the year ended June 30, 2001 and 2000, no preferred stock were issued
and outstanding.

(3)  Income Taxes

     At June 30, 2001 and 2000, the Company's significant deferred tax assets
and liabilities are summarized as follows:
































                                   F-9



<PAGE>
AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------

                                             2001            2000
                                             ----            ----
 Deferred tax assets:
    Net operating loss
    carryforwards                         $ 726,000        1,091,000

                                          ----------      ----------
    Gross deferred tax assets               726,000        1,091,000

     Less valuation allowance              (635,000)       (768,000)
                                          ----------      ----------
                                                   -         323,000
  Deferred tax liability:
    Oil and gas properties,
    principally due to differences
    in basis and depreciation and
    depletion                               (91,000)       (323,000)
                                          ----------      ----------
   Net deferred tax asset                 $        -      $        -
                                          ==========      ==========

     No income tax expense or benefit has been recorded for the years ended
June 30, 2001 and 2000 since the deferred income taxes that would have
otherwise been provided were offset by a decrease in the valuation allowance
for the net deferred tax assets.  The Company is consolidated in Delta's
income tax return and accounts for its income tax as if it filed a separate
return.  As Delta has a net operating loss carryforward and a valuation
allowance for deferred tax assets, the consolidation for income tax purposes
has no financial statement impact to the Company.

    At June 30, 2001, the Company had net operating loss carryforwards for
regular and alternative minimum tax purposes of approximately $2,413,000 and
$2,693,000 , respectively.  If not utilized, the tax net operating loss
carryforwards will expire during the period from 2002 through 2021.  If not
utilized, approximately $1.7 million of net operating losses will expire
over the next five years.

(4)  Related Party Transactions

     Effective October 1, 1998, the Company and Delta entered into an
agreement which provides for the sharing of management between the two
companies. Under this agreement the Company pays Delta $25,000 per quarter for
our share of rent, administrative, accounting  and management services of
Delta officers  and employees.  This agreement replaces a previous agreement
which allocated similar expenses based on the Company's proportionate share of
oil and gas production. The charges to us for the provision of services by
Delta were $100,000 for the year ended June 30, 2001 and 2000. We had a non-
interest bearing receivable from Delta of $403,629 and 505,629 recorded as a
reduction in equity at June 30, 2001 and 2000, respectively.


                                 F-10

<PAGE>
AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------


(5)  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,
                                       2001          2000
                                   -----------     ---------
  Undeveloped offshore
     California properties         $ 5,006,276     5,006,276
  Developed onshore
     domestic properties               203,053       195,531
                                   -----------     ---------
  Undeveloped offshore
                                     5,209,329     5,201,807
  Accumulated depreciation
     and depletion                    (169,968)     (159,360)
                                   -----------     ---------
                                   $ 5,039,361     5,050,869
                                   ===========     =========

     The Company has ownership interests in three unproved undeveloped
offshore California oil and gas properties with aggregate carrying values of
$5,006,276 at June 30, 2001 and June 30, 2000, respectively.  These property
interests are located in proximity to existing producing federal offshore
units near Santa Barbara, California and represent the right to explore for,
develop and produce oil and gas from offshore federal lease units. Preliminary
exploration efforts on these properties have
occurred and the existence of substantial quantities of hydrocarbons has been
indicated.  The recovery of the Company's investment in these properties will
require extensive exploration and development activities (and costs) that
cannot proceed without certain regulatory approvals that have been delayed and
is subject to other substantial risks and uncertainties as discussed herein.

     The Company is not the designated operator of any of these properties but
is an active participant in the ongoing activities of each property along with
the designated operator and other interest owners.  If the designated operator
elected not to or was unable to continue as the operator, the other property
interest owners would have the right to designate a new operator as well as
share in additional property returns prior to the replaced operator being able
to receive returns.  Based on the Company's size, it would be difficult for
the Company to proceed with exploration and development plans should other
substantial interest owners elect not to proceed.  However, to the best of its
knowledge, the Company believes the designated operators and other major
property interest owners intend to proceed with exploration and development
plans under the terms and conditions of the operating agreement.  The
ownership rights in each of these properties have been retained under various
suspension notices issued by the Mineral Management Service of the U.S.
Federal Government (MMS) whereby as long as the owners of each property were
progressing toward defined milestone objectives, the owners' rights with

                                    F-11

<PAGE>
AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------

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. 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.

     In the summer of 2001, several events occurred that continue to impact
the ability of the property owners to proceed to prepare exploration and
development plans for the properties.

     In June, 2001, in the case of The State of California ex. rel. The
California Coastal Commission: Gray Davis, Governor of California and Bill
Lockyer, Attorney General in the State of California et. al., v. Gale A.
Norton, Secretary of the Interior, United States Department of the Interior,
Minerals Management Service, Regional Supervisor of the Minerals Management
Service, et. al., the United States District Court for the Northern District
of California found that the previous grants of lease suspensions by the MMS
was an activity that required a determination by the MMS under the Coastal
Zone Management Act that the lease suspensions were consistent with
California's coastal management program, and ordered the MMS to set aside its
approval of the subject suspensions and to direct suspensions of the offshore
California leases, including all milestone activities, for a time sufficient
for the MMS to provide the State of California with a consistency
determination under the Coastal Zone Management Act.

     By correspondence dated on July 2, 2001, the MMS set aside its approval
of the previously existing lease suspensions and directed new suspensions of
all of the offshore California leases, including all milestone activities, for
a time sufficient for the MMS to provide the State of California with a
consistency determination under the Coastal Zone Management Act.  The new
suspensions of operations directed by the correspondence do not specify an end
date.  The United States government has filed a notice of its intent to appeal
the court's order in the Norton case.

     Based on discussions with the MMS and operators of the properties, the
Company currently believes that the MMS, in cooperation with the property
interest owners, will provide the State of California with a consistency
determination under the Coastal Zone Management Act that will allow
exploration and development plans to be prepared.  Furthermore the Company
believes that the MMS will seek to modify the previously submitted suspension
of production requests to focus solely on "preliminary activities," and will
approve new suspensions of production requests that do not contain any
"milestones" per se, as the stated milestones in the previous suspensions of
production appear to have been a significant factor in the court's decisions.
The Company also believes that the end-date of any such new suspensions of
production will likely be the anticipated spud date for the delineation wells
set forth in the operator's respective requests for suspensions of production.

                                   F-12

<PAGE>
AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------

     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,
2001 and June 30, 2000 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.

     Costs incurred in oil and gas producing activities for the years ended
June 30, 2001 and 2000 are as follows:

                                   2001       2000
                                   ----       ----

     Intangible drilling costs    $ 7,522         -
     Exploration costs            $17,582     7,189

     A summary of the results of operations for oil and gas producing
activities, excluding general and administrative cost, for the years ended
June 30, 2001 and 2000 is as follows:

                                          2001        2000
                                        -------      -------
  Revenue:
    Oil and gas sales                   $67,738      $37,579
  Expenses:
   Lease operating                      22,827       15,528
   Depletion                             10,608       14,417
   Exploration                           17,482        7,189
                                        -------      -------
  Results of operations of oil
  Gas producing activities              $16,821      $   445
                                        =======      =======







                                    F-13




<PAGE>
AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------


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

     Sales of three major customers accounted for approximately 44%, 12% and
12% of 2001 oil and gas sales.  Sales to two major customers accounted for
approximately 44%, and 12% of 2000 oil and gas sales.

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

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

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

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

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

     Proved 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

                                    F-14


AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------

application of fluid injection or other improved recovery techniques for
supplementing the natural forces and mechanisms of primary recovery should be
included as "proved developed reserves" only after testing by a pilot project
or after the operation of an installed program has confirmed through
production response that increased recovery will be achieved.

      Proved undeveloped oil and gas reserves are reserves that are expected
to be recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion. Reserves on
undrilled acreage shall be limited to those drilling units offsetting
productive units that are reasonably certain of production when drilled.
Proved reserves for other undrilled units can be claimed only where it can be
demonstrated with certainty that there is continuity of production from the
existing productive formation.  Under no circumstances should estimates for
proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual
tests in the area and in the same reservoir.

     A summary of changes in estimated quantities of proved reserves for the
years ended June 30, 2001 and 2000 are as follows:

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

Balance at July 1, 1999                  186,590        835

 Revisions of quantity estimates          (8,148)     1,854
 Production                              (11,443)      (488)
                                       ---------    -------
Balance at June 30, 2000                 166,999      2,201

  Revisions of quantity estimates        (25,299)      (138)
  Production                             (11,630)      (381)

Balance at June 30, 2001                 130,070      1,682
                                      ==========    =======

Proved developed reserves:
  June 30, 1999                          186,590        835
  June 30, 2000                          166,999      2,201
  June 30, 2001                          130,070      1,682


     Future net cash flows presented below are computed using year-end prices
and costs.

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

                                   F-15

<PAGE>
AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------

 June 30, 2000

 Future cash inflows                         $  643,918
 Future costs:
  Production                                    292,258
  Development                                         -
  Income taxes                                        -
                                             ----------

 Future net cash flows                          351,660

 10% discount factor                            119,724
                                             ----------
 Standardized measure of discounted future
    net cash flows                           $  231,936
                                             ==========

 June 30, 2001

 Future cash inflows                         $  343,937
 Future costs:
  Production                                    172,264
  Development                                         -
  Income taxes                                        -
                                             ----------

 Future net cash flows                          171,673

 10% discount factor                             64,629
                                             ----------

 Standardized measure of discounted future
    net cash flows                           $  107,044
                                             ==========















                                   F-16

<PAGE>
AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2001 and 2000
----------------------------------------------------------------------------

     The principal sources of changes in the standardized measure of
discounted net cash flows during the year ended June 30, 2001 and 2000 are as
follows:

                                                    2001         2000
                                                  --------     ---------

 Beginning of year                                $231,936       203,958

 Sales of oil and gas produced during the
   period , net of production costs                (44,911)      (20,321)
 Net change in prices and production costs         (51,512)       78,265
 Changes in estimated future development costs           -             -
 Revisions of previous quantity estimates,
   estimated timing of development and other       (51,663)      (50,362)
 Sale of reserves in place                               -             -
 Accretion of discount                              23,194        20,396
                                                  --------     ---------
 End of year                                      $107,044       231,936
                                                  ========     =========


























                                     F-17

<PAGE>
                                   SIGNATURE

     Pursuant to the requirements of Section 13 or 15(d) 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.

                                 AMBER RESOURCES COMPANY



Date:  September 12, 2001        By: /s/ Roger A. Parker
                                     ----------------------------------------
                                     Roger A. Parker, Chief Executive Officer



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


     Pursuant to the requirements of Section 13 or 15(d) 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 12, 2001
-------------------------------
Aleron H. Larson, Jr., Director


/s/ Roger A. Parker                             October 12, 2001
-------------------------------
Roger A. Parker, Director


/s/ Terry D. Enright                            October 12, 2001
-------------------------------
Terry D. Enright, Director


/s/ Jerrie F. Eckelberger                       October 12, 2001
-------------------------------
Jerrie F. Eckelberger, Director