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, 2000
                               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,                   80202
 Denver,  Colorado
(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, 2000
totaled $100,245.

The  aggregate market value as of the Company's voting stock held
by  non-affiliates of the Company as of August 15, 2000 could not
be  determined  because  there is no established  public  trading
market.

As  of  August 21, 2000, 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                           2
ITEM 2.   DESCRIPTION OF PROPERTY                           6
ITEM 3.   LEGAL PROCEEDINGS                                 18
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE
               OF SECURITY HOLDERS                          18

                            PART II

ITEM 5.   MARKET FOR COMMON EQUITY
               AND RELATED STOCKHOLDER MATTERS              18
ITEM 6.   MANAGEMENT'S DISCUSSION AND ANALYSIS
          OR PLAN OF OPERATION                              19
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                                 22
ITEM 10.  EXECUTIVE COMPENSATION                            24
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                  26


FORWARD-LOOKING STATEMENTS                                  26



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, 2000, 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,  2000,  proved  producing
reserves attributable to our onshore properties were estimated to
be approximately .17 Bcf of gas and 2,201 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, 2000, 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, 2000, 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, 2000, 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 industry 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, 2001.

          (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, 2000 and 1999.

          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.  This scenario is  currently
               anticipated  by  our management  to  be  the  most
               reasonable course of action although there  is  no
               assurance that this scenario will be adopted.

               Scenario  4      Development  of  existing  leases
               after  decommissioning and removal of some or  all
               existing   onshore  facilities.    This   scenario
               includes new facilities, and perhaps new sites, to
               handle  anticipated  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.   This  scenario   that   is
               currently anticipated by our management to be  the
               most reasonable course of action although there is
               no assurance that this scenario will be adopted.

               Scenario  4      Development of existing  offshore
               leases,  using  existing onshore  facilities  with
               additional  capacity or adding new  facilities  to
               handle   a   relatively  low  rate   of   expanded
               development.   This  scenario  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.

          The  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  undeveloped  leases and  units,  pursuant  to  30  CFR
250.110.  The SOO was directed for the purpose of preparing  what
became  known as the COOGER Study. Two-thirds of the cost of  the
Study  was funded by the participating companies in lieu  of  the
payment  of  rentals on the leases. Additionally, all  operations
were suspended on the leases during this period. On November  12,
1999,  as the COOGER Study drew to a conclusion, the MMS approved
requests  made  by the operating companies for  a  Suspension  of
Production (SOP) status for the POCS leases and units. During the
period  of  a  SOP the lease rentals resume and each operator  is
required  to  perform exploration and development  activities  in
order  to  meet  certain milestones set out by the MMS.  Progress
toward  the milestones is monitored by the operator in  quarterly
reports  submitted  to the MMS.  In February 2000  all  operators
completed   and  timely  submitted  to  the  MMS  a   preliminary
"Description  of  the  Proposed  Project".  This  was  the  first
milestone  required under the SOP.  Quarterly reports  were  also
prepared  and  submitted for the last quarter of  1999,  and  the
first and second quarters of 2000.

           In order to continue to carry out the requirements  of
the MMS, all operators of the units in which we own non-operating
interests  are currently engaged in studies and project  planning
to  meet the next milestone leading to development of the leases.
Where  additional drilling is needed the operators will  bring  a
mobile  drilling  unit  to  the POCS  to  further  delineate  the
undeveloped oil and gas fields.

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

          To  the  extent  that  we do not have  sufficient  cash
available  to pay our share of expenses when they become  payable
under  the  respective operating agreements, it will be necessary
for  us  to seek funding from outside sources.  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 million.

          The Gato Canyon Unit leases are currently held under  a
Suspension  of  Production until May 1, 2003.   An updated Exploration
Plan 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  Production until November 1, 2002.  During this SOP there will
will be 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?  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 $7 million.

          The  Sword  Unit  leases  are currently  held  under  a
Suspension  of  Production until April 1, 2003. An updated Exploration
Plan is expected to include plans to drillan additional delineation well.

                               map insert

       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, 2000   June 30, 1999  June 30, 1998

     Average sales price:
       Oil (per barrel)         $22.50           11.63           17.31
       Natural Gas (per Mcf)     $2.32            1.88            2.34
       Production costs (per
         Mcf equivalent)         $1.08             .82             .57

          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,  2000,  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, 2000, we held undeveloped acreage by state
as set forth below:

                                            Undeveloped Acres(1)
          Location             Gross                 Net

          California(1)        22,340                 811

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

          (f)  Drilling Activities

          During the year ended June 30, 2000, we had no drilling
activity   while  during  the  year  ended  June  30,   1999   we
participated  in  the  recompletion of  one  well,  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, 2000.


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

          None.

                            PART II


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

          (a)  Market or Markets:

          We  currently  have, and have had for  the  past  three
years,  only limited trading in the over-the-counter  market  and
there  is  no assurance that this trading market will  expand  or
even  continue.  Recent regulations and rules by the SEC and  the
National Association of Securities Dealers virtually assure  that
there  will be little or no trading in our stock unless and until
we  are  listed  on  NASDAQ or another  exchange.   There  is  no
assurance that we will be able to meet the requirements for  such
listing  in  the foreseeable future.  Further, our capital  stock
may  not be able to be traded in certain states until and  unless
we are able to qualify, exempt or register our stock.  Quotations
during 2000 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, 2000 was approximately 1,000.

          (c)  Dividends:

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

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

          Liquidity and Capital Resources.

          At  June 30, 2000, we had a working capital deficit  of
$56,143 compared to a working capital deficit of $131,060 at June
30,  1999.  Our working capital deficit is primarily a result  of
royalties payable.

          Our  current liabilities include royalties  payable  of
$51,667  at June 30, 2000 which represents a liability previously
recorded  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  2000  and
1999.

          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.  Together with Delta, we
will continue to seek additional sources of both short-term and
long-term liquidity  to fund our working capital deficit and our
capital requirements for development of our properties, including
establishing  a  credit facility,  sale  of equity or debt securities
and  sale  of  non-strategic properties although there can be no
assurance  that  we will be successful in our efforts.  Many of
the factors which may affect our future operating performance and
liquidity are beyond our  control,  including  oil  and natural
gas  prices  and  the availability of financing.

          After evaluation of the considerations described above,
we  believe that our existing cash balances, cash flow  from  our
existing producing properties, proceeds from the sale of oil  and
gas  properties, 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 loss for the year ended June 30,
2000  was $67,494 compared to our net income of $659,149 for  the
year  ended  June  30, 1999.  The decrease 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.

          Revenue.     Total revenue for the year ended June  30,
2000  was  $100,245 compared to $989,390 for the year ended  June
30, 1999.  Oil and gas sales for the year ended June 30, 2000 was
$37,579  compared to $139,105 for the year ended June  30,  1999.
The  decrease  in oil and gas sales for the year ended  June  30,
2000 compared to the year ended June 30, 1999 is attributable  to
the  sale  of  the majority of our productive oil and  gas  wells
during fiscal 1999.

          Production volumes and average prices received for  the
years ended June 30, 2000 and 1999 are as follows:

                          Year Ended              Year Ended
                         June 30, 2000           June 30, 1999
Production:
     Oil (barrels)            488                        604
     Gas (Mcf)             11,443                     70,235

Average Price:
     Oil (per barrel)      $22.50                      11.63
     Gas (per Mcf)         $ 2.32                       1.88

          Lease Operating Expenses.  Lease operating expenses for
the  year ended June 30, 2000 was $15,528 compared to $60,411 for
the  year  ended  June  30,  1999.  On  a  MCF  equivalent  basis
production  expenses  and  taxes were $1.08  per  Mcf  equivalent
during the year ended June 30, 2000 compared to $.82 for the year
ended June 30, 1999.

          Depletion  Expense.   Depletion expense  for  the  year
ended June 30, 2000 was $14,417 compared to $31,682 for the  year
ended June 30, 1999.

          Exploration Expenses.  Exploration expenses consist  of
geological and geophysical costs and lease rentals.  We  incurred
exploration costs of $7,189 and $1,494 for the years  ended  June
30, 2000 and 1999, respectively.

          General  and  Administrative  Expenses.   General   and
administrative  expense  for the year ended  June  30,  2000  was
$130,605  compared to $236,654 for the year ended June 30,  1999.
General  and administrative expenses decreased from 1999 to 2000
primarily as a result of the change in management fee charged to us
after the sale of our most productive wells leaving less of  a
need for administrative support.

           Recently Issued or Proposed  Accounting Standards  and
Pronouncements.

          In March 2000, the Financial Accounting Standards Board
("FASB")  issued  FASB  Interpretation  No.  44  "Accounting  for
Certain   Transactions   involving   Stock   Compensation-    and
interpretation  of APB Opinion No. 25 ("FIN 44").   This  opinion
provides  guidance  on  the accounting for certain  stock  option
transactions   and   subsequent  amendments   to   stock   option
transactions.   FIN  44 is effective July 1,  2000,  but  certain
conclusions  cover  specific  events  that  occur  after   either
December  15, 1998 or January 12, 2000.  To the extent that   FIN
44  covers  events occurring during the period from December  15,
1998  and January 12, 2000, but before July 1, 2000, the  effects
of  applying  this  interpretation are  to  be  recognized  on  a
prospective basis.  Repriced options mentioned above  may  impact
future periods.   The Company has not yet assessed the impact, if
any,  that FIN 44 might have on its financial position or results
of operations.

           In  December  1999, the SEC released Staff  Accounting
Bulletin  ("SAB")  No.  101, "Revenue  Recognition  in  Financial
Statements",   which  provides  guidance  on   the   recognition,
presentation  and  disclosure of revenue in financial  statements
filed  with  the SEC.  Subsequently, the SEC released  SAB  101B,
which delayed the implementations date of SAB 101 for registrants
with  fiscal years beginning between December 16, 1999 and  March
15,  2000.  The Company has not yet assessed the impact, if  any,
that  SAB 101 might have on its financial position or results  of
operations.

           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 was amended by SFAS 137 and 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.  55     Chairman of the Board,     May 1987 to Present
                              Chief Executive Officer
                              Secretary, Treasurer,
                                 and Director

Roger  A.  Parker      38     President  and             May 1987 to Present
                                   Director

Terry D. Enright       51     Director                    November 1987 to
                                                              Present

Jerrie   F.
     Eckelberger       56     Director                    September 1996 to
                                                              Present

Kevin K. Nanke         35     Chief Financial Officer     December 1999 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 55,  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 4.97% 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 38, 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 51, 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 56, 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.

         Kevin K. Nanke, age 35, appointed Chief Financial Officer
in December 1999, joined Delta in April 1995 as Controller.  Since
1989, he has been involved in public and private accounting with
the oil and gas industry.  Mr. Nanke received a Bachelor of Arts
in Accounting from the University of Northern Iowa in 1989.  Prior
to working with Delta, he was employed by KPMG LLP.  He is a member
of the Colorado Society of CPA's and the Council of Petroleum
Accounting Society.

         There  is  no  family  relationship  among  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, 2000, 1999  and
1998.    Messrs.  Larson, Parker and Nanke,  Chairman, President and
Chief Financial Officer, respectively,  are compensated by Delta which
is  paid  under a management  agreement with the Company.  No officeror
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

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

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

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

ITEM 12.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

          Effective  October  1,  1998,  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 $100,000 for the year
ended  June  30, 2000, and $206,745 for the year ended  June  30,
1999.   We  had a receivable from Delta of $505,629 and  $633,622
recorded  as  a  reduction in equity at June 30, 2000  and  1999,
respectively.

                            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,
     *    government regulations, 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  Delta,  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, Chief Financial Officer


     Pursuant to the requirements of Section 13 or 15(d)  of  the
Securities Exchange Act of 1934, we have duly caused this  report
to  be  signed  on its behalf by the undersigned, thereunto  duly
authorized.


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

     Date                                         9/26/00


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

     Date                                         9/26/00


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

     Date                                         9/26/00


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

     Date                                         9/26/00


                       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  balance  sheets  of  Amber
Resources  Company  (the  "Company"),  a  subsidiary   of   Delta
Petroleum  Corporation, as of June 30,  2000  and  1999  and  the
related  statements  of operations and accumulated  deficit,  and
cash  flows for the years then ended.  These financial statements
are   the  responsibility  of  the  Company's  management.    Our
responsibility  is  to  express an  opinion  on  these  financial
statements based on our audits.

We  conducted  our  audits in accordance with 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  financial statements  referred  to  above
present  fairly, in all material respects, the financial position
of  Amber Resources Company as of June 30, 1998 and 1997, and the
results  of its operations and its cash flows for the years  then
ended   in   conformity   with  generally   accepted   accounting
principles.




                              s/KPMG
                              KPMG LLP


Denver, Colorado
September 14, 2000




AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)

BALANCE SHEETS
June 30, 2000 and 1999






                                                2000               1999

ASSETS

Current assets:
  Cash                                    $     5,422                961
  Accounts receivable                           3,000              2,000

    Total current assets                        8,422              2,961

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            195,531
                                            5,201,807          5,201,807

  Accumulated depletion                      (159,360)          (144,943)

    Net oil and gas properties              5,042,447          5,056,864

                                          $ 5,050,869          5,059,825


LIABILITIES AND STOCKHOLDERS' EQUITY

Current  liabilities:
  Accounts payable:                       $    12,898             19,697
  Royalties payable                            51,667            114,323

    Total current liabilities                  64,565            134,020


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                        (554,936)          (487,442)
  Advances to parent                         (505,629)          (633,622)

    Total stockholders' equity              4,986,304          4,925,805

                                          $ 5,050,869          5,059,825



AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)

STATEMENT OF OPERATIONS AND ACCUMULATED DEFICIT
Years Ended June 30, 2000 and 1999






                                                2000               1999

Revenue:
  Oil and gas sales                       $    37,579            139,105
  Gain on sale of oil
    and gas properties                              -            731,752
  Other income                                 62,666            118,533

    Total revenue                             100,245            989,390


Expenses:
  Lease operating expenses                     15,528             60,411
  Depletion                                    14,417             31,682
  Exploration expenses                          7,189              1,494
  General and administrative,
    including $100,000 in 2000
    and $206,745 in 1999 to
    parent (Note 4)                           130,605            236,654

    Total expenses                            167,739            330,241

    Net income (loss)                         (67,494)           659,149

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

Accumulated deficit at end of the year    $  (554,936)          (487,442)

Basic earnings per share                  $     (0.01)              0.14

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



AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)

Statements of Cash Flows
Years Ended June 30, 2000 and 1999





                                                   2000            1999

Cash flows from operating activities:
  Net income (loss)                        $   (67,494)            659,149
  Adjustments to reconcile
      net income to cash
      provided by (used in)
      operating activities:
    Gain on sale of oil and gas
      properties                                     -           (731,752)
    Write-off of royalties payable             (62,656)          (118,509)
    Depletion                                   14,417             31,682
  Net changes in current assets and
      current liabilities
    (Increase) decrease in
       accounts receivable                      (1,000)            69,178
    Decrease in accounts payable                (6,799)           (21,362)

Net cash used in operating activities         (123,532)          (111,614)

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

    Net cash provided by investing activities        -          1,065,512

Cash flows from financing activities-
  Changes in acccounts receivable from and
    accounts payable to parent                 127,993           (967,598)

    Net increase (decrease) in cash              4,461            (13,700)

    Cash at beginning of the year                  961             14,661

    Cash at end of the year                $     5,422                961


                 See accompanying notes to financial statements.


AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 2000 and 1999

(1)  Summary of Significant Accounting Policies

     Organization

     Amber Resources Company ("the Company") was incorporated  in
January,   1978,  and  is  principally  engaged   in   acquiring,
exploring, developing, and producing oil and gas properties.  The
Company  owns interests in undeveloped oil and gas properties  in
federal  units  offshore  California,  near  Santa  Barbara,  and
developed  oil  and  gas  properties in  the  continental  United
States.   As of June 30, 2000, Delta Petroleum Corporation  owned
4,277,977 shares (91.68%) of the Company's common stock.

     Liquidity

     The  Company  has incurred losses from operations  over  the
past  several years coupled with significant deficiencies in cash
flow  from operations for the same period.  As of June 30,  2000,
the  Company  had  a working capital deficit of  $56,143.   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.

     Impairment of Long-Lived Assets

     Long-lived assets are 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.

     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 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, 2000, 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  royalties due on recoupment gas produced and delivered
to  the  gas  purchaser.  The Company made its estimates  of  the
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.  These estimates are reduced  by
amounts that 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 2000 and 1999.

     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
have been presented.

     Use of Estimates

     The  preparation of financial statements in conformity  with
generally  accepted accounting principles requires management  to
make  estimates and assumptions that affect the reported  amounts
of assets and liabilities and disclosure of contingent assets and
liabilities  at  the  date of the financial  statements  and  the
reported  amounts  of  revenue and expenses during  the  reported
period.  Actual results could differ from these estimates.

(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,  2000  and  1999,  the  Company=s  significant
deferred tax assets and liabilities are summarized as follows:

                                               2000          1999
  Deferred tax assets:
       Net operating loss
        carryforwards                      $1,091,000     1,017,000
       Oil and gas properties,
         principally due to
         differences in basis and
         depreciation and depletion             -             -
       Gross deferred tax assets           1,091,000    1,017,000

          Less valuation allowance          (768,000)    (976,000)
                                             323,000       41,000
   Deferred tax liability:
       Oil and gas properties,
        principally due to differences
        in basis and depreciation and
        depletion                            (323,000)    (41,000)
     Net deferred tax asset                 $   -         $   -

     No  income tax expense or benefit has been recorded for  the
years  ended  June  30, 2000 and 1999 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,  2000,  the  Company  had  net  operating  loss
carryforwards for regular and alternative minimum tax purposes of
approximately  $2,871,000 and $3,151,000, respectively.   If  not
utilized,  the tax net operating loss carryforwards  will  expire
during  the  period  from 2001 through 2020.   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  $25,000 per quarter for our share of rent, administrative,
accounting   and  management  services  of  Delta  officers   and
employees.   This  agreement replaces a previous agreement  which
allocated  similar expenses based on the Company's  proportionate
share  of  oil  and gas production.  The charges to  us  for  the
provision  of services by Delta were $100,000 for the year  ended
June 30, 2000, and $206,745 for the year ended June 30, 1999.  We
had  a non interest bearing receivable from Delta of $505,629 and
$633,622  recorded as a reduction in equity at June 30, 2000  and
1999, respectively.

(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,
                                          2000              1999
    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                    (159,360)       (144,943)
                                       $ 5,042,447       5,056,864

    A  summary  of  the results of operations  for  oil  and  gas
producing activities, excluding general and administrative  cost,
for the years ended June 30, 2000 and 1999 is as follows:

                                        2000              1999
    Revenue:
       Oil and gas sales               $37,579          $139,105
    Expenses:
       Lease operating                  15,528            60,411
      Depletion                         14,417            31,682
      Exploration                        7,189             1,494
      Results of operations of oil
      Gas producing activities         $   445          $ 45,518

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

    Costs  incurred in oil and gas producing activities  for  the
years ended June 30, 2000 and 1999 are as follows:

                                        2000           1999
         Exploration costs             $7,189          1,494
         Development costs             $9,105          9,105

     Sales  of  major customers accounted for approximately  44%,
12% and 12% of  2000 oil and gas sales.  Sales to major customers
accounted  for  approximately 65% and 18% of  1999  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.


A summary of changes in estimated quantities of proved reserves for the years
ended June 30, 2000 and 1999 are as follows:



                                                      Onshore
                                               GAS              OIL
                                              (MCF)           (BBLS)

Balance at July 1, 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

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

Proved developed reserves:
   June 30, 1998                            1,466,871           2,407
   June 30, 1999                              186,590             835
   June 30, 2000                              166,999           2,201



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, 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


 June 30, 2000

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

 Future net cash flows                               351,660

  10% discount factor                                119,724

 Standardized  measure of discounted future
       net cash flows                            $   231,936




The principal sources of changes in the standardized measure of discounted
net cash flows during the year ended June 30, 2000 and 1999 are as follows:


                                                    2000          1999

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

 Sales of oil and gas produced during the
     period , net of production costs                (20,321)      (78,694)
 Net change in prices and production costs            78,265        33,745
 Changes in estimated future development costs             -        (7,015)
 Revisions of previous quantity estimates,
      estimated timing of development and other      (50,362)     (167,092)
 Sale of reserves in place                                 -    (1,272,616)
 Accretion of discount                                20,396       154,148

 End of  year                                    $   231,936       203,958