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, 1999
                                    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, 1999 totaled
$989,390.

The aggregate market value as of the Company's voting stock held by non-
affiliates of the Company as of September 10, 1999 could not be determined
because there is no established public trading market.

As of September 10, 1999, 4,666,185 shares of registrant's Common Stock
$.0625 par value were issued and outstanding.

                 The Index to Exhibits appears at Page 28.

                             TABLE OF CONTENTS

                                  PART I

                                                            PAGE

ITEM 1.   DESCRIPTION OF BUSINESS                           1
ITEM 2.   DESCRIPTION OF PROPERTY                           5
ITEM 3.   LEGAL PROCEEDINGS                                 17
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE
               OF SECURITY HOLDERS                          17

                                  PART II

ITEM 5.   MARKET FOR COMMON EQUITY
               AND RELATED STOCKHOLDER MATTERS              17
ITEM 6.   MANAGEMENT'S DISCUSSION AND ANALYSIS
               OR PLAN OF OPERATION                         18
ITEM 7.   FINANCIAL STATEMENTS                              21
ITEM 8.   CHANGES IN AND DISAGREEMENTS WITH
               ACCOUNTANTS ON ACCOUNTING
               AND FINANCIAL DISCLOSURE                     21

                                 PART III

ITEM 9.   DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
               AND CONTROL PERSONS; COMPLIANCE
               WITH SECTION 16(a) OF THE
               EXCHANGE ACT                                 21
ITEM 10.  EXECUTIVE COMPENSATION                            23
ITEM 11.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
               OWNERS AND MANAGEMENT                        24
ITEM 12.  CERTAIN RELATIONSHIPS AND RELATED
                TRANSACTIONS                                25
ITEM 13.  EXHIBITS AND REPORTS ON FORM 8-K                  25


FORWARD-LOOKING STATEMENTS                                  25



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

                                  PART I


ITEM 1.   DESCRIPTION OF BUSINESS

          (a)  Business Development

          Amber Resources Company ("Amber","the Company") 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, 1999, 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, 1999, proved producing reserves
attributable to our onshore properties were estimated to be
approximately .19 Bcf of gas and 835 Bbls of oil.  There are
uncertainties as to the timing of the development of our offshore
properties.  (See "Description of Properties"; Item 2 herein.)

          The Company, a Delaware corporation, was established
January 17, 1978.  Our offices are located at Suite 3310, 555 17th
Street, Denver, Colorado 80202.  As of June 30, 1999, Delta
Petroleum Corporation ("Delta") owned 4,277,977 shares (91.68%) of
our outstanding common stock.  The Company is 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, 1999, Amber 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, 1999, 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
the purchasers 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 calculated into the price paid for the oil.
Natural gas wells are connected to pipelines owned by the natural
gas purchasers.  A variety of pipeline transportation charges are
usually included in the calculation of the price paid for the
natural gas.

          (3)  Status of Any Publicly Announced New Product or
Service.  We have not made a public announcement of, and no
information has otherwise become public about, a new product or
industry segment requiring the investment of a material amount of
our total assets.

          (4)  Competitive Business Conditions.  Oil and gas
exploration and 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.

          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 its 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 many 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
particular operations and products of ours, 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 of the Company, 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
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 "nonhazardous," 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
wilful 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.

          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, the
Company 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 change in our business.  At the present time,
however, the existence of environmental law does not materially
hinder nor adversely affect our business.  Capital expenditures
relating to environmental control facilities have not been material
to the Company since its inception.  In addition, we do not
anticipate that such expenditures will be material during the
fiscal year ending June 30, 2000.

          (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, 1999 and 1998.

          Offshore Federal Waters: Santa Barbara, California Area

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

          The Santa Barbara Channel and the offshore Santa Maria
Basin are the seaward portions of geologically well-known onshore
basins with over 90 years of production history.  These offshore
areas were first explored in the Santa Barbara Channel along the
near shore three mile strip controlled by the state.  New field
discoveries in Pliocene and Miocene age reservoir sands led to
exploration into the federally controlled waters of the Pacific
Outer Continental Shelf ("POCS").  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.  Currently, POCS production is 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").

          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 in 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, 10 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
the Company owns interests are located in the POCS seaward of the
three mile limit, leasing, drilling, and development of these units
are not directly regulated by the State of California.  However, to
the extent that any production is transported to an on-shore
facility through the state waters, the Company's pipelines (or
other transportation facilities) would be subject to California
state regulations.  Construction and operation of the 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 this 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 have a controlling
interest in and do not act as the operator of any of the offshore
California properties and consequently we will not 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 is currently conducting the study under
a contract with the MMS.  The COOGER Study seeks to present a long-
term regional perspective of potential onshore constraints that
should be considered when developing existing undeveloped offshore
leases.  COOGER will project the economically recoverable oil and
gas production from offshore leases which have not yet been
developed.  These projections will be utilized to assist in
identifying a potential range of scenarios for developing these
leases.  These scenarios will then be 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.  The exact effects upon offshore
development of the adoption of any one of the scenarios are not yet
capable of analysis because the study has not yet been completed
and reviewed.  However, we have evaluated our position with regard
to the scenarios currently being studied with respect to properties
located in the eastern and central subregions (which include the
Sword Unit and the Gato Canyon Unit) and the results of such
evaluation are set forth below:

               Scenario 1     No new development of existing
               offshore leases.  If this scenario were ultimately
               to be adopted by governmental decisionmakers 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.  Although the exact effects
               upon offshore development are not yet capable of
               analysis because the study has not yet been
               completed, it is likely that the adoption of this
               scenario by governmental decision makers and 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.  Although the details of this
               scenario are not yet available because the study
               has not been completed, it would appear that this
               is approximately the same scenario that is
               anticipated by our management.

               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 potential future production.  There is
               currently insufficient information available to
               assess the impact of this scenario on us, but it
               would appear likely that we would incur increased
               costs and that revenues would be received more
               quickly.

               We have also evaluated our position with regard to
     the scenarios currently being studied with respect to
     properties located in the northern subregion (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 decisionmakers 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.  Although the exact effects
               upon offshore development are not yet capable of
               analysis because the study has not yet been
               completed, it is likely that the adoption of this
               scenario by governmental decision makers and the
               industry as the proper course of action for
               development would result in lower than anticipated
               costs, but would cause our 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.  Although the details of this
               scenario are not yet available because the study
               has not been completed, it would appear that this
               is approximately the same scenario that is
               anticipated by our management.

               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 allows for a new
               site(s).  There is currently insufficient
               information available to assess the impact of this
               scenario on us.

               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.  This scenario allows for a new
               site(s).  There is currently insufficient
               information available to assess the impact of this
               scenario on Amber, but it would appear likely that
               we would incur increased costs and that revenues
               would be received more quickly.

          Our development plan currently provides 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 1,300 feet for the Sword Unit;  and 183 wells from
two platforms for the Lion Rock Unit.  On the Lion Rock Unit,
platform A will be set in a water depth of approximately 507 feet,
and Platform B will be set in a water depth of approximately 484
feet.  The reach of the deviated wells from each platform required
to drain in each unit was found to fall within the reach limits now
considered to be "state-of-the-art."

          Current Status.  On October 15, 1992 the MMS directed a
Suspension of Operations ("SOO") effective January 1, 1993, for the
POCS non-producing leases and units, pursuant to CFR 250.10, to
enable the lease owners to participate in what became known as the
COOGER Study.  This allowed the leases to be held under an SOO
during the term of the study thereby permitting the owners to cease
paying lease payments to the Federal government and suspending the
requirements relating to development of these leases during this
period.

          The MMS has extended the SOO from time to time to allow
completion of the COOGER Study.  Most recently the MMS directed an
additional SOO through November 15, 1999 when unit operators are
required to have submitted descriptions of their exploration plans
for the leases to support their requests for Suspension of
Production ("SOP") status for the leases.   Each operator has or
will submit what the MMS has termed a Schedule of Events for a
specific lease or unit that it operates and also a request for a
SOP time period to execute the Schedule of Events.

          In order to carry out the requirements of the MMS, all
operators of the units in which we own non-operating interests
(described below) are currently engaged in studies to develop a
conceptual framework and general timetable for continued
delineation and development of the leases.  For delineation, the
operators will outline the mobile drilling unit well activities,
including number and location.  For development, the operators'
reports will cover the total number of facilities involved,
including platforms, pipelines, onshore processing facilities,
transportation systems and marketing plans.  We are participating
with the operators in meeting the MMS schedules through meetings,
and consultations and in sharing in the costs as invoiced by the
operators.

          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 $26,938,000.

          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.  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 its offshore California properties),
reduce our ownership interest in the properties through sales of
interests in the property or as the result of farm-outs, 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 its ownership interest
in the properties under some circumstances, or that we might be
subject to penalties which would result in the forfeiture of
substantial revenues from the properties.

          While the cost to develop the offshore California
properties in which we own an interest are anticipated to be
substantial in relation to our small size, we believe 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 near historic lows, it is likely that
development efforts will proceed at a slower pace to the end that
costs will be incurred over a more extended period of time.  If
petroleum prices increase, 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 properties.

          Gato Canyon Unit. We hold a 6.97% working interest 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 distance to access the Las Flores site is
approximately six miles.  Our share of the estimated capital costs
to develop the Gato Canyon field are approximately $20,174,000.

          The Gato Canyon Unit leases are currently held under a
Suspension of Operations until November 15, 1999.  Thereafter, the
Unit operator intends to carry out a Schedule of Events under a
Suspension of Production.  The Schedule of Events will include the
preparation of an updated Exploration Plan, which is expected to
include plans to drill an additional delineation well.  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 in the
Lion Rock Unit.  The Lion Rock Unit is operated by Aera Energy LLC.
An aggregate of seven test wells have been drilled on the Lion Rock
Unit.  Four of these wells were completed and tested and indicated
the presence of oil and gas in the Monterey Formation.   One test
well was drilled by Socal (now Chevron) in 1965 and six wells were
drilled by Phillips Petroleum, one in 1982, two in 1983, two in
1984 and one in 1985.

          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.
The oil and gas produced at Lion Rock will be processed at a new
facility in the onshore Santa Maria Basin or at the existing Lompoc
facility (see Map).  The oil will 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 landfall.

          The Lion Rock Unit is currently held under a Suspension
of Operations until November 15, 1999.  Thereafter, the Unit
operator intends to carry out a Schedule of Events under a
Suspension of Production.  The Schedule of Events will include
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 in the Sword
Unit.  This 12,240 acre unit is operated by Conoco, Inc. In
aggregate, three wells have been drilled on this unit of which two
wells were completed and tested in the Monterey formation with
calculated flow rates of from 4,000 to 5,000 Bbls per day with an
estimated average gravity of 10.6 degrees 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.  The
oil and gas produced from the Sword Field will likely be processed
at the existing Gaviota consolidated facility and the oil
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 will be
approximately five miles in length.  Our share of the estimated
capital costs to develop the Sword field is approximately
$6,764,000.

          The Sword Unit leases are currently held under a
Suspension of Operations until November 15, 1999.  Thereafter, the
Unit operator intends to carry out a Schedule of Events under a
Suspension of Production.  Included in the Schedule of Events will
be preparation of an updated Exploration Plan leading to the
drilling of an additional delineation well.

                                 MAP

   Map depicting Santa Barbara County, California oil and gas
   facilities in relation to offshore federal units in which the
   Company owns interests.

     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.
The following table sets forth our net production of oil and gas,
average sales prices and average production costs during the
periods indicated.

          The average oil and gas price per unit and average
production costs per unit for the Company are set forth below:

                               Year Ended      Year Ended      Year Ended
                             June 30, 1999   June 30, 1998    June 30, 1997

Average sales price:

 Oil (per barrel)                 $11.63           17.31            21.19

 Natural Gas (per Mcf)             $1.88            2.34             2.28

 Production costs (per
     Mcf equivalent)                $.82             .57              .50

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

          (d)  Productive Wells and Acreage.

          The table below shows, as of June 30, 1999, 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.

          (e)  Undeveloped Acreage.

          At June 30, 1999, we held undeveloped acreage by state as
set forth below:

                                              Undeveloped Acres (1)
          Location                             Gross           Net

          California (2)                      22,340           811

     (1)  Undeveloped acreage is considered to be those lease acres
          on which wells have not been drilled or completed to a
          point that would permit the production of commercial
          quantities of oil and gas, regardless of whether such
          acreage contains proved reserves.

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

          (f)  Drilling Activities

          During the years ended June 30, 1999 and 1998, we
participated in the recompletion of one well each year, but did not
participate in the drilling of any new wells.

ITEM 3.   LEGAL PROCEEDINGS

          There is no litigation pending or threatened by or
against us or any of our properties as of June 30, 1999.

          The operators of the offshore Federal units in which we
own interests have each filed Notices of Appeal on behalf of
themselves and the co-owners of the various units, including Amber,
with the United States Department of Interior of a June 25,1999
order issued by the Regional Director, Pacific OCS Region,
terminating existing Suspensions of Production in effect prior to
the present Suspension of Operations.  We do not expect that the
outcome of any later appeal that might be filed pursuant to the
Notice of Appeal will have any material affect upon our property
interests because the operators are in the process of requesting
new Suspension of Production status for each of the units which, if
granted, will replace the existing Suspension of Operations.

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

          Not applicable.

                                  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 1998 and
1999 have not been available.

          (b)  Approximate Number of Holders of Common Stock:

          The number of holders of record of our securities at June
30, 1999 was approximately 1,000.

          (c)  Dividends:

          We have not declared any cash dividends and has 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.

          At June 30, 1999, we had a working capital deficit of
$131,060 compared to a working capital deficit of $522,028 at June
30, 1998.  Our working capital deficit is primarily a result of
royalties payable.

          Our current liabilities include royalties payable of
$114,323 at June 30, 1999 which represent our estimate of royalties
payable on production attributable to our interest in certain wells
in Oklahoma.   We believe that the operators of the affected wells
have paid some of the royalties on behalf of us and have withheld
such amounts from revenues attributable to our interest in the
wells.  We have contacted the operators of the wells in an attempt
to determine what amounts the operators have paid on behalf of us
over the past five years, which amounts would reduce the amounts we
owed.  We have been informed by our legal counsel that the
applicable statue of limitations period for actions on written
contracts arising in the state of Oklahoma is five years.  The
statute of limitation has expired for royalty owners to make a
claim for a portion of the estimated royalties that had previously
been accrued.  Accordingly, these amounts have been written off and
recorded as other income in 1999 and 1998.

          We believe that it is unlikely that all claims that might
be made for payment of royalties payable would be made at one time.
We also believe, although there can be no assurance, that we may
ultimately be able to settle with potential claimants for less than
the amounts recorded for royalties payable.

          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.  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, 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 income for the years ended June 30,
1998 and 1998 was $659,149 and $288,172, respectively.  The
increase in net earnings can primarily be attributed to a gain on
the sale of properties of $731,752 during the year ended June 30,
1999 compared to a gain on sale of oil and gas properties of
$283,993 during the year ended June 30, 1998.

          Revenue.    Total revenue for the year ended June 30,
1999 was $989,390 compared to $1,173,329 for the year ended June
30, 1998.  Oil and gas sales for the year ended June 30, 1999 was
$139,105 compared to $702,161 for the year ended June 30, 1998.
The decrease in oil and gas sales for the year ended June 30, 1999
compared to the year ended June 30, 1998 is attributable to the
sale of the majority of our productive oil and gas wells during the
year coupled with a decrease in the average price received for oil
and gas sales.

          Production volumes and average prices received for the
years ended June 30, 1999 and 1998 are as follows:

                                Year Ended                   Year Ended
                              June 30, 1999                June 30, 1998


Production:

     Oil (barrels)                 604                            565
     Gas (Mcf)                  70,235                        296,329

Average Price:

     Oil (per barrel)           $11.63                          17.31
     Gas (per Mcf)              $ 1.88                           2.34


          Lease Operating Expenses.  Lease operating expenses for
the year ended June 30, 1999 was $60,411 compared to $171,354 for
the year ended June 30, 1998.  On a MCF equivalent basis production
expenses and taxes were $.82 per Mcf equivalent during the year
ended June 30, 1999 compared to $.57 for the year ended June 30,
1998.

          Depletion Expense.  Depletion expense for the year ended
June 30, 1999 was $31,682 compared to $90,108 for the year ended
June 30, 1998.

          Exploration Expenses.  Exploration expenses consist of
geological and geophysical costs and lease rentals.  We incurred
exploration costs of $1,494 and $20,464 for the years ended June
30, 1999 and 1998, respectively.

          General and Administrative Expenses.  General and
administrative expense for the year ended June 30, 1999 was
$236,654 compared to $603,231 for the year ended June 30, 1998.
General and administrative expenses decreased from 1998 to 1999
primarily as a result of the change in management fee charged by us
after the sale of our most productive wells leaving less of a need
for administrative support.

          Year 2000

          We have completed a review of our computer system and
applications (which began in fiscal 1997) to identify the systems
that could be affected by the "Year 2000" issue.  The Year 2000
problem is the result of computer  programs being written using two
digits rather than four to define the applicable year.  Any of our
programs that have time-sensitive software may recognize a date
using "00" as the year 1900 rather than the year 2000.  This could
result in a major system failure or miscalculations.

          On the basis of our review, we currently believe that the
Year 2000 issue will not pose material operational problems for us.
To our knowledge after investigation, no "embedded technology"
(such as microchips in an electronic control system) of the Company
poses a material Year 2000 concern.

          Because we believe that we have no material internal Year
2000 problems, we have not and do not expect to expend a
significant amount of funds to address Year 2000 issues.  It is our
policy to continue to review our suppliers' Year 2000 compliance
and require assurance of Year 2000 compliance from new suppliers;
however, such monitoring does not involve a significant cost to us.

          In addition to the foregoing, we have contacted our major
vendors and have received either oral or written assurances from
our major vendors or has reviewed assurances contained on vendors'
web sites that they have no material Year 2000 problems.  We
believe that our vendors are largely fungible; therefore, in the
event a vendor's representations regarding its Year 2000 compliance
were untrue for any reason, we believe that we could find adequate
Year 2000-compliant vendors as substitutes.

          We have also received either oral or written assurances
from our customers or have reviewed assurances contained on our
customers' web sites that they have no Year 2000 problems which
would materially adversely affect the business or operations of the
Company.

          The information contained in this Year 2000 discussion is
forward-looking and involves risks and uncertainties that may cause
actual results to vary materially from those projected.  Some
factors that could significantly impact our expected Year 2000
compliance and the estimated cost thereof include internal computer
hardware or software problems which have not as yet been identified
by us, and currently undisclosed and unanticipated problems which
may be encountered by third parties with whom Amber has business
relationships.

          Recent Accounting Standards and Pronouncements

          Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities"
(SFAS 133), was issued in June 1998, by the Financial Accounting
Standards Board.  SFAS 133 establishes new accounting and reporting
standards for derivative instruments and for hedging activities.
This statement required an entity to establish at the inception of
a hedge the method it will use for assessing the effectiveness of
the hedging derivative and the measurement approach for determining
the ineffective aspect of the hedge.  Those methods must be
consistent with the entity's approach to managing risk.  SFAS 133
is effective for all fiscal quarters of fiscal years beginning
after June 15, 2000.  The Company has not assessed the impact, if
any, that SFAS 133 will have on its financial statements.

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.

          (a)  Executive Officers and Directors:

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

Aleron H. Larson, Jr.    54  Chairman of the Board,   May 1987 to Present
                                                      Chief Executive Officer
                                                      Secretary, Treasurer,
                                                      and a Director

Roger A. Parker          37  President and            May 1987 to Present
                               a Director

Terry D. Enright         50  Director                 November 1987 to
                                                          Present

Jerrie F. Eckelberger    55  Director                 September 1996
                                                         to Present


              All of our directors hold office until the next annual
meeting of our stockholders and until their successors have been
elected and have qualified.  There is no family relationship
between or among any of our executive officers and directors.

              Aleron H. Larson, Jr., age 54, 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,
C.E.O. and a Director of Underwriters Financial Group, Inc. ("UFG")
(formerly Chippewa Resources Corporation), a public company then
listed on the American Stock Exchange which presently owns
approximately 13.8% of the outstanding equity securities of Delta.
Subsequent to a change of control, Mr. Larson resigned from all
positions with UFG effective March 31, 1993.  Mr. Larson serves as
Chairman, CEO, Secretary, Treasurer and Director of Delta Petroleum
Corporation, a public oil and gas company which is the parent and
majority owner of Amber.  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 37, served as the President, a
Director and Chief Operating Officer of Underwriters Financial
Group 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 Operating Officer and
Director of Delta Petroleum Corporation, which is the parent and
majority owner of Amber.  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 and a Director of Apex Operating Company,
Inc. since its inception in 1987.   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 50, has been in the oil and gas
business since 1980.  He serves as a Director of both the Company
and Delta Petroleum Corporation, which is the parent and majority
owner of Amber.  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.

              Jerrie F. Eckelberger, age 55, is an investor, real
estate developer and attorney who has practiced law in the State of
Colorado for 28 years.   He serves as a Director of both the
Company and Delta Petroleum Corporation, which is the parent and
majority owner of Amber.   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
 .  After spending two years in the litigation department of a
Denver law firm, he founded Eckelberger & Associates of which he is
still the principal member.  From 1982 to 1992 Mr. Eckelberger was
the senior partner of Eckelberger & Feldman, a law firm with
offices in Englewood, Colorado.  Mr. Eckelberger previously served
as an officer, director and corporate counsel for Roxborough
Development Corporation.  He is presently the 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.
Additionally, Mr. Eckelberger is the Managing Member of the Woods
at Pole Creek, LLC, a Colorado limited liability company,
specializing in real estate development.

              There is no family relationship among any of the
Directors.

              Messrs. Enright and Eckelberger serve as the Audit,
Compensation and Incentive Plan Committee.


ITEM 10.     EXECUTIVE COMPENSATION.

              No officer or director received compensation directly
from the Company during the years ended June 30, 1999, 1998 and
1997.  Messers. Larson and Parker, Chairman and President,
respectively, are compensated by Delta which is paid under a
management agreement with the Company.  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.


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

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

(1)  All shares are owned by Delta; Messrs. Larson and Parker 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, the Company and Delta entered
into an agreement 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 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 $206,745 for the year ended June 30, 1999,
and $570,000 for the year ended June 30, 1998.  We had a receivable
to Delta of $633,622 recorded as a reduction in equity at June 30,
1999 and a payable to Delta of $333,976 at June 30, 1998.

                                  PART IV

ITEM 13.  EXHIBITS AND REPORTS ON FORM 8-K

          (a)  Exhibits:

          The Exhibits listed in the Index to Exhibits appearing at
page 28 are filed as part of this report.

          (b)  Reports on Form 8-K:  None

                        FORWARD-LOOKING STATEMENTS

     This Form 10-KSB contains forward-looking statements within
meaning of section 27A of the Securities Act of 1933 and section
21E of the Securities Exchange Act of 1934, including statements
regarding, among other items, our growth strategies, anticipated
trends in our business and our future results of operations, market
conditions in the oil and gas industry, the status of and/or future
expectations for our offshore properties, our ability to make and
integrate acquisitions and the outcome of litigation and the impact
of governmental regulation.  These forward-looking statements are
based largely on our expectations and are subject to a number of
risks and uncertainties, many of which are beyond our control.
Actual results could differ materially from these forward-looking
statements as a result of, among other things:

     *    a decline in oil and/or gas production or prices,

     *    incorrect estimates of required capital expenditures,

     *    increases in the cost of drilling, completion and gas
          collection or other costs of production and operations,

     *    an inability to meet growth projections, and

     *    other risk factors discussed or not discussed herein.

     In addition, the words "believe", "may", "will", "estimate",
"continue", "anticipate", "intend", "expect" and similar
expressions, as they relate to Amber, our business or our
management, are intended to identify forward-looking statements.

     We undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information,
future events or otherwise after the date of this Form 10-KSB.  In
light of these risks and uncertainties, the forward-looking events
and circumstances discussed in this document may not occur and
actual results could differ materially from those anticipated or
implied in the forward-looking statements.


                                 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.

     (Registrant)                  AMBER RESOURCES COMPANY



By (Signature and Title)            s/Aleron H. Larson, Jr.
                                     Aleron H. Larson, Jr.,
                                   Secretary, Chairman of the
                                  Board, Treasurer and Principal
                                       Financial Officer


                                       s/Kevin K. Nanke
                                    Kevin K. Nanke, Controller and
                                    Principal Accounting 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.


     By (Signature and Title)            s/Aleron H. Larson, Jr
                                         Aleron H. Larson,Jr., Director

     Date                                         9/27/99



     By (Signature and Title)
                                         s/Roger A. Parker
                                         Roger A. Parker, Director

     Date                                         9/27/99



     By (Signature and Title)
                                         s/Terry D. Enright
                                         Terry D. Enright, Director

     Date                                         9/27/99



     By (Signature and Title)
                                         s/Jerrie F. Eckelberger
                                         Jerrie F. Eckelberger, Director

     Date                                         9/27/99


                             INDEX TO EXHIBITS

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

(3)  Articles of Incorporation and By-Laws'  The Articles of
     Incorporation (Certificate of Incorporation) and By-Laws 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.

(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. Filed herewith electronically.

(99) Additional Exhibits. Not applicable.


                       Independent Auditors' Report


The Board of Directors and Stockholders
Amber Resources Company:


We have audited the accompanying consolidated balance sheets of
Amber Resources Company (the Company), (a subsidiary of Delta
Petroleum Corporation), and subsidiary as of June 30, 1999 and
1998 and the related consolidated statements of operations,
stockholders' equity, 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 generally accepted
auditing  standards.  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 consolidated financial statements referred to
above present fairly, in all material respects, the financial
position of Amber Resources Company and subsidiary as of June 30,
1999 and 1998 and the results of their operations and their cash
flows for the years then ended, in conformity with generally
accepted accounting principles.

                                  s/KPMG LLP
                                   KPMG LLP





Denver, Colorado
September 21, 1999


AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)

BALANCE SHEETS
June 30, 1999 and 1998






                                                   1999              1998

ASSETS

Current assets:
  Cash                                        $        961           14,661
  Accounts receivable                                2,000           71,178

    Total current assets                             2,961           85,839


Oil and gas properties, successful efforts
  method of accounting (Note 1 and 5):
  Undeveloped offshore California properties      5,006,276        5,006,276
  Developed onshore domestic properties             195,531        1,264,134
                                                  5,201,807        6,270,410

  Accumulated depletion                            (144,943)        (848,104)

    Net oil and gas properties                    5,056,864        5,422,306

                                                 $5,059,825        5,508,145


LIABILITIES AND STOCKHOLDERS' EQUITY

Current  liabilities:
  Accounts payable:
    Trade                                        $   19,697           41,059
    Parent                                              -            333,976
  Royalties payable                                 114,323          232,832

    Total current liabilities                       134,020          607,867

Stockholders' equity:
  Preferred stock, $1.00 par value; Authorized
    5,000,000 shares of Class A convertible
    preferred stock, none issued (Note 2)               -                 -
  Common stock, $.0625 par value;
    authorized 25,000,000 shares, 4,666,185
    shares issued and outstanding                   291,637          291,637
  Additional paid-in capital                      5,755,232        5,755,232
  Accumulated deficit                              (487,442)      (1,146,591)
  Advances to parent                               (633,622)            -

    Total stockholders' equity                    4,925,805        4,900,278

                                                 $5,059,825        5,508,145



STATEMENT OF OPERATIONS AND ACCUMULATED DEFICIT
Years Ended June 30, 1999 and 1998



                                                       1999            1998

Revenue:
  Oil and gas sales                                $  139,105        702,161
  Gain on sale of oil and gas properties              731,752        283,993
  Other income                                        118,533        187,175

    Total revenue                                     989,390      1,173,329


Expenses:
  Lease operating expenses                             60,411        171,354
  Depletion                                            31,682         90,108
  Exploration expenses                                  1,494         20,464
  General and administrative,
     including $206,745 in 1999
     and $570,000 in 1998 to parent (Note 4)          236,654        603,231

    Total expenses                                    330,241        885,157

    Net income                                        659,149        288,172

Accumulated deficit at beginning of the year       (1,146,591)    (1,434,763)

Accumulated deficit at end of the year             $ (487,442)    (1,146,591)

Basic earnings per share                            $     0.14         0.06

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



Statements of Cash Flows
Years Ended June 30, 1999 and 1998



                                                       1999           1998

Cash flows from operating activities:
  Net income                                       $  659,149        288,172
  Adjustments to reconcile net income to cash
      provided by (used in) operating activities:
    Gain on sale of oil and gas properties           (731,752)      (283,993)
    Write-off of royalties payable                   (118,509)      (186,976)
    Depletion                                          31,682         90,108
  Net changes in current assets and
      current liabilities
    Decrease in accounts receivable                    69,178         40,550
    (Decrease) increase in accounts payable           (21,362)        24,778

Net cash used in operating activities                (111,614)       (27,361)

Cash flows from investing activities:
  Additions to oil and gas properties                  (9,105)        (1,318)
  Proceeds from the sale of oil and gas properties  1,074,617        338,063

    Net cash provided by investing activities       1,065,512        336,745

Cash flows from financing activities-
  Changes in acccounts receivable from and
    accounts payable to parent                       (967,598)       (301,163)

    Net increase (decrease) in cash                   (13,700)          8,221

    Cash at beginning of the year                      14,661           6,440

    Cash at end of the year                        $      961          14,661



                      See accompanying notes to financial statements.

AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 1999 and 1998



(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.

     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.  As of June 30, 1999, the
Company had a working capital deficit of $131,059.  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.

     The Company is taking steps to reduce losses and generate cash
flow from operations which management believes will generate
sufficient cash flow to meet its obligations in a timely manner.
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 basis 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 depletion is removed from the
accounts and any gain or loss is credited or charged to operations.

     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 unproved properties are assessed periodically
and a provision for impairment is recorded, if necessary, through
a charge to operations.

     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) was issued in March 1995.  This
statement 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.  This
review consists of a comparison of the carrying value of the asset
with the asset's expected future undiscounted cash flows without
interest costs.

     Impairment of Long-Lived Assets

     Estimates of expected future cash flows are to 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.

     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 related
reserves.  Thereafter, additional amounts received are recorded as
a liability.

     As of June 30, 1999, the Company had produced approximately
18,000  Mcf less than its entitled share of production.  The
undiscounted value of this imbalance is approximately $40,000 using
the lower of the price received for the natural gas, the current
market price or the contract price as applicable.

     Royalties Payable

     Recoupment gas royalties, included in royalties payable,
represent estimated royalties due on recoupment gas produced and
delivered to the gas purchaser.  The Company has estimated an
amount that may be due to the royalty owners based on the market
price of the gas during the period the gas was produced and
delivered to the gas purchaser.

     Royalties payable also include estimated royalties payable on
other properties held in suspense.  A significant portion of the
estimated royalties have not been paid pending a determination of
what amounts may have previously been paid by the operator of the
properties on behalf of the Company.

     The statute of limitation has expired for royalty owners to
make a claim for a portion of the estimated royalties that had
previously been accrued.  Accordingly, these amount have been
written off and recorded as other income in 1999 and 1998.

     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.

     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 has 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.

(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, 1999 and 1998, no preferred stock were issued and outstanding.

(3)  Income Taxes

     At June 30, 1999 and 1998, the Company s significant deferred
tax assets and liabilities are summarized as follows:

                                                1999         1998
      Deferred tax assets:
         Net operating loss
           carryforwards                 $    1,017,000     1,199,000
         Oil and gas properties,
             principally due to
             differences in basis and
             depreciation and depletion            -               -
         Gross deferred tax assets            1,017,000     1,199,000

         Less valuation allowance              (976,000)   (1,158,000)
                                                 41,000        41,000

      Deferred tax liability:
        Oil and gas properties,
           principally due to
           differences in basis and
           depreciation and depletion           (41,000)      (41,000)

      Net deferred tax asset            $           -             -


   No income tax expense has been recorded for the years ended
June 30, 1999 and 1998 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.

   At June 30, 1999, the Company had net operating loss
carryforwards for regular and alternative minimum tax purposes of
approximately $3,151,000 and $3,813,000, respectively.  If not
utilized, the tax net operating loss carryforwards will expire
during the period from 2000 through 2019.  If not utilized,
approximately $2.4 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 for
its proportionate share of rent, administrative, accounting and
management services of Delta's officers and employees.  This
agreement replaces a previous agreement which allocated similar
expenses based on the Company's proportionate share of oil and gas
production.  The charges to the Company for the sharing of
management services by Delta were $206,745 for the year ended June
30, 1999, and $570,000 for the year ended June 30, 1998.  The
Company had a receivable to Delta of $633,622 recorded as a
reduction in equity at June 30, 1999 and a payable to Delta of
$333,976 at June 30, 1998.

(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,
                                           1999                   1998

    Undeveloped offshore
         California properties         $ 5,006,276             5,006,276
    Developed onshore
         domestic properties               195,531             1,264,134
                                         5,201,807             6,270,410
    Accumulated depreciation
         and depletion                    (144,943)             (848,104)

                                       $ 5,056,864             5,422,306

    Costs incurred in oil and gas producing activities for the
years ended June 30, 1999 and 1998 are as follows:

                                                1999              1998

         Exploration costs                     $1,494            20,464

         Development costs                     $9,105             1,318

    Sales of major customers accounted for approximately 65%, and
18% of 1999 oil and gas sales.  Sales to major customers accounted
for approximately 62%, 14% and 11% of 1998 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 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.

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

A summary of changes in estimated quantities of proved reserves for the years
ended June 30, 1999 and 1998 are as follows:



                                            Onshore
                                              GAS             OIL
                                             (MCF)          (BBLS)

Balance at July 1, 1997                   1,871,794           5,816

  Revisions of quantity estimates           333,171          (2,136)
  Sale of oil and gas properties           (441,765)           (708)
  Production                               (296,329)           (565)
Balance at June 30, 1998                  1,466,871           2,407

  Revisions of quantity estimates            26,290            (968)
  Sale of oil and gas properties         (1,236,336)             -
  Production                                (70,235)           (604)
Balance at June 30, 1999                    186,590             835

Proved developed reserves:
   June 30, 1997                          1,871,794           5,816
   June 30, 1998                          1,466,871           2,407
   June 30, 1999                            186,590             835


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

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.

 June 30, 1998

 Future cash inflows                             $ 3,492,318
 Future costs:
    Production                                     1,337,464
    Development                                            -
    Income taxes                                           -

 Future net cash flows                             2,154,854

  10% discount factor                                613,372

 Standardized  measure of discounted future
       net cash flows                            $ 1,541,482


 June 30, 1999

 Future cash inflows                             $   454,032
 Future costs:
    Production                                       189,318
    Development                                            -
    Income taxes                                           -

 Future net cash flows                               264,714

  10% discount factor                                 60,756

 Standardized  measure of discounted future
       net cash flows                            $   203,958



The principal sources of changes in the standardized measure of discounted
net cash flows during the year ended June 30, 1999 and 1998 are as follows:


                                                    1999          1998

 Beginning of year                               $ 1,541,482     1,790,353

 Sales of oil and gas produced during the
     period , net of production costs                (78,694)     (530,807)
 Net change in prices and production costs            33,745       239,320
 Changes in estimated future development costs        (7,015)         (943)
 Revisions of previous quantity estimates,
      estimated timing of development and other     (167,092)      329,902
 Sale of reserves in place                        (1,272,616)     (465,378)
 Accretion of discount                               154,148       179,035

 End of year                                     $   203,958     1,541,482