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, 1997
                                    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        
incorporation or organization           Identification No.)
   

          Suite 3310, 555 Seventeenth Street
          Denver, Colorado                              80202
     (Address of principal executive offices)         (Zip Code)

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

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

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

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

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

The issuer's revenue for the fiscal year ended June 30, 1997
totaled $1,113,274.

The aggregate market value as of the Company's voting stock held
by non-affiliates of the Company as of September 19, 1997 could
not be determined because there is no established public trading
market.

As of September 25, 1997, 4,666,185 shares of registrant's Common
Stock $.0625 par value were issued and outstanding.

                The Index to Exhibits appears at Page 20.


                             TABLE OF CONTENTS


                                  PART I

                                                            PAGE


ITEM 1.   DESCRIPTION OF BUSINESS                           1
ITEM 2.   DESCRIPTION OF PROPERTY                           3
ITEM 3.   LEGAL PROCEEDINGS                                 9
ITEM 4.   SUBMISSION OF MATTERS TO A VOTE    
               OF SECURITY HOLDERS                          9
     
                                  PART II

ITEM 5.   MARKET FOR COMMON EQUITY                
               AND RELATED STOCKHOLDER MATTERS              10
ITEM 6.   MANAGEMENT'S DISCUSSION AND ANALYSIS   
               OR PLAN OF OPERATION                         11
ITEM 7.   FINANCIAL STATEMENTS                              14
ITEM 8.   CHANGES IN AND DISAGREEMENTS WITH 
               ACCOUNTANTS ON ACCOUNTING
               AND FINANCIAL DISCLOSURE                     14
     
                                 PART III

ITEM 9.   DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
               AND CONTROL PERSONS; COMPLIANCE
               WITH SECTION 16(a) OF THE 
               EXCHANGE ACT                                 14
ITEM 10.  EXECUTIVE COMPENSATION                            16
ITEM 11.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
               OWNERS AND MANAGEMENT                        17
ITEM 12.  CERTAIN RELATIONSHIPS AND RELATED
                TRANSACTIONS                                18
ITEM 13.  EXHIBITS AND REPORTS ON FORM 8-K                  18
     

                                  PART I

ITEM 1.   DESCRIPTION OF BUSINESS

          (a)  Business Development

          Amber Resources Company ("Amber" or "the Company") is
engaged in the exploration, development and production of oil and
gas properties.  The Company's business is conducted onshore in
the continental United States and in the coastal waters of
California.  As of June 30, 1997, the Company's 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 42 producing wells in western
Oklahoma (the "Oklahoma Properties").  At June 30, 1997, the
Company estimated its proved undeveloped reserves attributable to
its offshore California properties to be approximately 13.76 Bcf
of gas and 10,885,000 Bbls of oil and proved producing reserves
attributable to its onshore properties to be approximately 1.87
Bcf of gas and 5,800 Bbls of oil.  There are uncertainties as to
the timing of the development of the offshore properties.  (See
"Description of Properties"; Item 2 herein.)

          The Company, a Delaware corporation, was established
January 17, 1978.  The Company's offices are located at Suite
3310, 555 17th Street, Denver, Colorado 80202.  As of June 30,
1997, Delta Petroleum Corporation ("Delta") owned 4,277,977
shares (91.68%) of the Company's outstanding common stock.  The
Company is managed by Delta under a management agreement
effective March 31, 1993 which provides for the sharing of the
management between the two companies and allocation of expenses
related thereto.  
          
          At June 30, 1997, 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, 1997, Amber was engaged
in only one industry, namely the acquisition, exploration,
development, and production of oil and gas properties and related
business activities.  The Company's oil and gas operations have
been comprised primarily of production of oil and gas.  The
Company currently has producing oil and gas interests in the
Anadarko Basin in Oklahoma and interests in proven but
undeveloped offshore Federal leases and units near Santa Barbara,
California.

          (1)  Principal Products or Services and Their Markets. 
The principal products produced by the Company 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 the Company's
producing properties.

          (2)  Distribution Methods of the Products or Services. 
Oil and natural gas produced from the Company's 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 the Company is 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.  The Company has 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 the Company's total assets.

          (4)  Competitive Business Conditions.  Oil and gas
exploration and acquisition of undeveloped properties is a highly
competitive and speculative business.  The Company competes with
a number of other companies, including major oil companies and
other independent operators which are more experienced and which
have greater financial resources.  The Company does 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 the Company's business.  The acquisition,
exploration, development, production, and sale of oil and gas are
subject to many factors which are outside of the Company's
control.  These factors include national and international
economic conditions, availability of drilling rigs, casing, pipe,
and other equipment and supplies, proximity to pipelines, the
supply and price of other fuels, and the regulation of prices,
production, transportation, and marketing by the Department of
Energy and other federal and state governmental authorities.

          (6)  Dependence on One or a Few Major Customers.  The
Company has three major customers for the sale of oil and gas as
of the date of this report, namely, Tristar Gas Marketing,
Chesapeake Gas Marketing and HS Resources.  The loss of any one
or all of these customers would not have a material adverse
effect on the Company's business.

          (7)  Patents, Trademarks, Licenses, Franchises,
Concessions, Royalty Agreements and Labor Contracts.  The Company
does 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.  The Company is not a party to any labor
contracts.

          (8)  Need for Any Governmental Approval of Principal
Products or Services.  Except that the Company must obtain
certain permits and other approvals from various governmental
agencies prior to drilling wells and producing oil and/or natural
gas, the Company does not need to obtain governmental approval of
its principal products or services.

          (9)  Effect of Existing or Probable Governmental
Regulations on the Business.  The oil and gas industry is
extensively regulated by federal, state and local authorities. 
Legislation affecting the oil and gas industry is under constant
review for amendment or expansion.  Numerous departments and
agencies, both federal and state, have issued rules or
regulations binding on the oil and gas industry and its
individual members, some of which carry substantial penalties for
the failure to comply.  The regulatory burden on the oil and gas
industry increases its cost of doing business and consequently
affects its profitability.  Inasmuch as such laws and regulations
are frequently amended or reinterpreted, the Company is unable to
predict the future cost or impact of complying with such
regulations.

          (10) Research and Development.  The Company does 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 the Company is
engaged in acquiring, operating, exploring for and developing
natural resources, it is 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 the Company's
earnings potential, and could cause material change in the
Company's proposed business.  At the present time, however, the
existence of environmental law does not materially hinder nor
adversely affect the Company's business.  Capital expenditures
relating to environmental control facilities have not been
material to the Company since its inception.  In addition, the
Company does not anticipate that such expenditures will be
material during the fiscal year ending June 30, 1998.

          (12) Employees.  The Company has no full time
employees.

ITEM 2.   DESCRIPTION OF PROPERTIES

          (a)  Office Facilities:

               The Company shares offices with Delta under its
management agreement with Delta.  Under this agreement, the
Company pays Delta for its proportionate share of rent,
secretarial and administrative, accounting and management
services of Delta's officers and employees.

          (b)  Oil and Gas Properties

               The Company owns interests in oil and gas
properties located in Oklahoma and offshore California.  Wells
from which the Company receives revenues are owned only partially
by the Company.  The Company did not file oil and gas reserve
estimates with any federal authority or agency other than the SEC
during its years ended June 30, 1997 and 1996.

          Offshore Federal Waters: Santa Barbara, California Area 

          Amber Resources Company, owns interests in three proved
undeveloped federal units located in federal waters offshore
California near Santa Barbara.

          At June 30, 1997, Amber's offshore California reserves
from these Units totaled approximately 13.76 Bcf of gas and
10,885,000 Bbls of oil for an aggregate oil and gas equivalent of
approximately 13,178,000 BOE.

          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 750
million Bbls of oil and 700 billion cubic feet of gas have been
produced and sold.  POCS production is approximately 160,000 Bbls
of oil and 186 million cubic feet of gas per day according to the
Minerals Management Services 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 on production since late 1981, has
already surpassed 150 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 19 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 wells needed to develop reserves in the area.  Use of these
new drilling methods and seismic technologies is expected to
improve development economics. 

          The first three miles off the shore of the coastline
are administered by each state and are known as "state waters". 
Within the state waters offshore Santa Barbara County, the State
of California regulates oil and gas leases, drilling, and the
installation of permanent and temporary producing facilities. 
Because the three units in which the Company owns interests are
located outside and beyond the state waters in the POCS, the
offshore area beyond the three-mile limit, leasing and drilling
of these units are not regulated by the State of California. 
However, to the extent that the production will be transported to
an on-shore facility through the state waters, the Company's
pipelines (or other transportation facilities) will be subject to
California state regulations.  Construction and operation of the
pipelines will require permits from the state.  State regulations
also govern the construction and operations of on-shore
facilities such as terminals, pumping stations, and water
separation facilities, all of which require a comprehensive
permitting process.   Ocean disposal of effluents, such as
drilling muds and produced waters, is administered by the EPA. 
Additionally, all development plans must be consistent with the
Federal Coastal Zone Management Act ("CZM").   In California the
CZM consistency determination is taken by the California Coastal
Commission.

          Santa Barbara County, through its Board of Supervisors,
also has a significant impact on the method and timing of any
offshore field development through its concurrent regulation of
the construction and operation of on-shore facilities.

          Leasing, lease administration, development, and
production with the OCS all fall under Federal regulations
administered by the MMS.

          The Company's Offshore California proved undeveloped
reserves are attributable to its interests in these three federal
units located offshore California near Santa Barbara. While these
interests represent ownership of substantial oil and gas reserves
classified as proved undeveloped, the cost to develop the
reserves will be very substantial.  The Company may be required
to farm out all or a portion of its interests in these properties
if it cannot fund its share of the development costs.  There can
be no assurance that the Company can farm out its interests on
acceptable terms.  If the Company were to farm out its interests
in these properties, its share of the proved reserves
attributable to the properties would be decreased substantially. 
The Company may also incur substantial dilution of its interests
in the properties if it elects to use other methods of financing
the development costs.

          These units have been formally approved and are
regulated by the MMS. However, due to a history of opposition to
offshore drilling and production in California by some
individuals and groups, the process of obtaining all of the
necessary permits and authorizations to develop the properties
will be lengthy.  While the Federal Government has recently
attempted to expedite this process, there can be no assurance
that it will be successful in doing so.  The Company does not
have a controlling interest in and does not act as the operator
of any of the offshore California properties and consequently
will not control the timing of either the development of the
properties or the expenditures for development.  Management and
its independent engineering consultant have considered these
factors relating to timing of the development of the reserves in
the preparation of the reserve information relating to these
properties.  As additional information becomes available in the
future, the Company's estimates of the proved undeveloped
reserves attributable to these properties could materially
change.

          Current Status.  On November 5, 1996, the MMS issued a
Directed Suspension of Operations for the POCS Non-Producing
Leases and Units, pursuant to CFR 250.10(b)(4), extending the
existing Suspension of Operations ("SOO") from January 1, 1997
until December 31, 1998.  This action permitted Unit owners to
cease paying lease payments to the Federal government and
suspended the requirements relating to development of the leases
during this period.  The Directive cited the fact that the MMS
had requested in 1992 that the lease owners participate in what
became known as the COOGER (California Offshore Oil and Gas
Energy Resources) Study and during the term of the Study that the
leases would be held under a SOO.

          The MMS issued a second letter on December 24, 1996
with the intent to expand and clarify the November 5th Directive
and to notify all lease owners of the course of action to be
followed by the Lease and Unit Operators during 1997 and 1998
prior to the expiration of the SOO.  This letter requests that
each Operator submit a Unit (or Lease) Plan of Operations to the
MMS by December 31, 1997.  This will not be a binding document
but the MMS intends to use it in determining a strategy for
development.  In early 1998 each Operator is to meet with the MMS
for a review of the Plan.  Based on this meeting the Operator
will submit, by September 1, 1998, a final Plan of Operations for
approval.  The approved Plans for the Units will go into effect
on January 1, 1999.

          In order to carry out the requirements of this December
24, 1996 letter, all Operators of the units in which the Company
owns non-operating interests (described below) are currently
engaged in studies to develop a conceptual framework and general
timetable for continued delineation and development of the
leases.  For delineation, the Operators will outline the mobile
drilling unit well activities, including number and location. 
For development, the Operators' reports will cover the total
number of facilities involved, including platform(s), pipelines,
onshore processing facilities, transportation systems and
marketing plans.  The Company is participating with the Operators
in meeting the MMS schedules through meetings and consultations
and is sharing in the costs as invoiced by the Operators.  

          Gato Canyon Unit.  The Company holds a 6.97% working
interest in the Gato Canyon Unit.  This 10,100 acre unit is
operated by Samedan Oil Corporation.  Four of the five wells
drilled on the unit to date have indicated the presence of oil
and gas reserves.  In April 1989, Samedan announced the
completion and test of the Samedan  P-0460 #2 yielded a test flow
rate of 5,500 barrels of oil per day from the Monterey Formation
between 5,000 and 6,800 feet of drill 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 the Company's federal lease units).  As of July 1,
1997, Forrest A. Garb & Associates, Inc. ("Garb"), an independent
petroleum engineering firm based in Dallas, Texas, issued a
report indicating that Gato Canyon contains recoverable reserves
estimated to be 123.8 million Bbls of oil and 22.17 Bcf of
natural gas representing approximately 7.08 million Bbls of oil
and 9.9 Bcf of natural gas net to the Company's 6.97%
working interest.  The oil has an estimated average gravity of 16
degrees API. Based on prices of $12.50 per Bbl and $1.41 per Mcf
and applicable regulatory parameters, the Company's 6.97% working
interest in the Gato Canyon Unit has a pretax discounted (10%)
present value of approximately $8,203,000.  (See "--Oil and Gas
Reserves".)  

          Lion Rock Unit.  The Company holds a 1% net profits
interest in  28,800 acres of the Lion Rock Unit.  Lion Rock is
operated by Aera Energy, LLC, a subsidiary of Shell Oil Company. 
An aggregate of seven wells have been drilled on this unit of
which four have been completed and tested which indicate
producible oil and gas reserves in the Monterey Formation. 
Additionally, the unit is immediately contiguous with the San
Miguel Field which is in the same reservoir as defined by
drilling and testing of six wells, seismic data and geological
analysis to date.  Based on a report prepared by Garb, on July 1,
1997 the Lion Rock Unit contains proved undeveloped recoverable
reserves of 527.1 million Bbls of oil and 474.4 Bcf of natural
gas, equivalent to approximately 2,398,000 barrels of oil and 2.2
Bcf of natural gas net to the Company's interest.  The oil has an
average estimated gravity of 10.7 degrees API.  Based on prices
of $12.50 per Bbl and $1.41 per Mcf and applicable regulatory
parameters, the Company's aggregate interest in the Lion Rock
Unit has a pre-tax present value (discounted at 10%) of
approximately $3,702,000 as of July 1, 1997.  (See "--Oil
and Gas Reserves".)  

          Sword Unit.  The Company holds 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 have been completed and tested to date with
calculated flow rates of from 4,000 to 5,000 Bbls per day, which
indicate producible oil and gas reserves in the Monterey
Formation.  Based on a July 1, 1997 report prepared by Garb, the
Sword Unit contains proved undeveloped recoverable reserves of
193.9 million Bbls of oil and 232.7 Bcf of natural gas
representing reserves of approximately 1.41 million Bbls of oil
(having an estimated average gravity of 10.6 API) and 1.69 Bcf of
natural gas to the Company's interest.  Based on prices of $12.50
per Bbl and $1.41 per Mcf and applicable regulatory parameters,
the Company's interest in the Sword Unit has a pre-tax present
value (discounted at 10%) of approximately $1,388,000.  (See
"--Oil and Gas Reserves".)  

     Oklahoma.

          The Company owns non-operated working interests in 42
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 the
Company's reserves are in the Atoka formation.  Apache
Corporation operates 20 of the wells in which the Company owns an
interest.  Other major operators include Samson Resources
Corporation, Meridian Oil Company and Ricks Exploration.  The
working interests range from less than 1% to 40% and average
about 7.5% per well.  Many of the wells have remaining productive
lives of 20 to 30 years.  

          (c)  Production

          The Company is 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 the
Company has not had, nor does it now have, any long-term supply
or similar agreements with governments or authorities pursuant to
which the Company acted as producer.  The following table sets
forth the Company's 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, 1997    June 30, 1996     June 30, 1995 
     
Average sales price:                                        
          
Oil (per barrel)            $21.19             20.85           15.27   
Natural Gas (per Mcf)        $2.28              1.73            1.55   
     
Production costs (per        
Mcf equivalent)               $.50               .65             .57   
     
          The profitability of the Company's oil and gas
production activities is affected by the fluctuations in the sale
prices of its oil and gas production.  (See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations.")

          (d)  Productive Wells and Acreage. 

          The table below shows, as of June 30, 1997, the
approximate number of gross and net producing oil and gas wells
by state and their related developed acres owned by the Company. 
Productive wells are producing wells capable of production,
including shut-in wells.  Developed acreage consists of acres
spaced or assignable to productive wells.

              Oil (3)           Gas (3)         Developed Acres
       Gross(1)   Net(1)    Gross(1)  Net(1)     Gross(1)  Net(2)

Oklahoma    0       0         42       2.52       6,720     444 

     (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.

     (3)  See "Oil and Gas Reserves" below for reserve data.

          (e)  Undeveloped Acreage.

          At June 30, 1997, the Company held undeveloped acreage
by state as set forth below:

                                 Undeveloped Acres (1)    
          Location               Gross           Net  

          California (2)        22,340           811

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

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

          (f)  Drilling Activities

               During the years ended June 30, 1997 and 1996, the
Company participated in the recompletion of one well each year,
but did not participate in the drilling of any new wells.  

ITEM 3.   LEGAL PROCEEDINGS

          There is no litigation pending or threatened by or
against the Registrant or any of its properties as of June 30,
1997.

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

          Not applicable.

                                  PART II

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

          (a)  Market or Markets:

          The Company currently has, and has 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 the Company's stock unless
and until the Company is listed on NASDAQ or another exchange. 
There is no assurance that the Company will be able to meet the
requirements for such listing in the foreseeable future. 
Further, the Company's capital stock may not be able to be traded
in certain states until and unless the Company is able to
qualify, exempt or register its stock.   Quotations during 1996
and 1997 have not been available.

          (b)  Approximate Number of Holders of Common Stock:

          The number of holders of record of the Company's
securities at June 30, 1997 was approximately 1,000.

          (c)  Dividends:

          The Company has not declared any cash dividends and has
no plan for the payment of dividends on its 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 the financial
condition and financial requirements of the Company and general
conditions.

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

     Liquidity and Capital Resources. 

               At June 30, 1997, the Company had a working
capital deficit of $953,060 compared to a working capital deficit
of $1,161,713 at June 30, 1996.  The Company's working capital
deficit is primarily a result of amounts payable to Delta and
royalties payable.  The Company's account payable to affiliate
has decreased from June 30, 1996 as the Company's available cash
flow during the period exceeded the Company's proportionate share
of rent, secretarial and administrative, accounting and
management services paid by Delta.

               The Company's current liabilities include
royalties payable of $419,808 at June 30, 1997 which represent
the Company's estimate of royalties payable on production
attributable to it's interest in certain wells in Oklahoma.   The
Company believes that the operators of the affected wells have
paid some of the royalties on behalf of the Company and have
withheld such amounts from revenues attributable to the Company's
interest in the wells.  The Company has contacted the operators
of the wells in an attempt to determine what amounts the
operators have paid on behalf of the Company over the past five
years, which amounts would reduce the amounts owed by the
Company.  To date the Company has not received
information adequate to allow it to determine the amounts paid by
the operators.  The Company has been informed by its 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 1997 and
1996.

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

               The Company does not currently have a credit
facility with any bank and it has not determined the amount, if
any, that it could borrow against its existing properties.  The
Company will continue to seek additional sources of both
short-term and long-term liquidity to fund its working capital
deficit and its capital requirements for development of its
properties including establishing a credit facility, sale of
equity or debt securities and sale of non-strategic properties. 
Many of the factors which may affect the Company's future
operating performance and liquidity are beyond the Company's
control, including oil and natural gas prices and the
availability of financing.

               The financial statements have been prepared on a
going concern basis which contemplates the realization of assets
and the satisfaction of liabilities and commitments in the normal
course of business.  Several factors, described below, raise
substantial doubt about the ability of the Company to continue as
a going concern.  The financial statements do not include any
adjustments that might result from the outcome of this
uncertainty.

               Currently, the Company's operations are not
generating sufficient cash flow to fund operations and discharge
the Company's liabilities.  The Company has been economically
dependent upon the Company's parent, Delta.  Delta has no
obligations or commitment to provide further financial support,
although it may do so from time to time as it elects.

     Results of Operations

               Net Earnings (Loss).   The Company's net income
for the year ended June 30, 1997 was $64,260 compared to a net
loss for the year ended June 30, 1996 of $149,538.  

               Revenue.    Total revenue for the year ended June
30, 1997 was $1,113,274 compared to $841,702 for the year ended
June 30, 1996.  Oil and gas sales for the year ended June 30,
1997 was $936,929 compared to $555,268 for the year ended June
30, 1996.  The increase in oil and gas sales for the year ended
June 30, 1997 compared to the year ended June 30, 1996 resulted
from an increase in oil and gas prices during fiscal 1997 and an
increase in the volumes of natural gas produced. 

               Production volumes and average prices received for
the years ended June 30, 1997 and 1996 are as follows:

                        Year Ended                Year Ended      
                     June 30, 1997                June 30, 1996   

Production:         
     Oil (barrels)         1,025                          961         
     Gas (Mcf)           400,725                      309,709
Average Price:        
     Oil (per barrel)     $21.19                        20.85
     Gas (per Mcf)        $ 2.28                         1.73          
   
               Lease Operating Expenses.  Lease operating
expenses for the year ended June 30, 1997 was $203,731 compared
to $205,971 for the year ended June 30, 1996.  On a MCF
equivalent basis production expenses and taxes were $.50 per Mcf
equivalent during the year ended June 30, 1997 compared to $.65
for the year ended June 30, 1996.  

               Depletion Expense.  Depletion expense for the year
ended June 30, 1997 was $120,071 compared to $117,867 for the
year ended June 30, 1996.   On a MCF equivalent basis the
depletion rate was $.30 per Mcf equivalent during year ended June
30, 1997 compared to $.37 per Mcf equivalent for the year ended
June 30, 1996.  The slight increase in depletion expense for the
year ended June 30, 1997 can be attributed to the increase in
production during the year.

               Exploration Expenses.  Exploration expenses
consist of geological and geophysical costs and lease rentals. 
The Company incurred exploration costs of $3,330 and $3,032 for
the years ended June 30, 1997 and 1996, respectively.

               Abandonment and Impairment of Oil and Gas
Properties.  The Company recorded an expense for abandoned and
impaired properties for the year ended June 30, 1997 of $42,000
in accordance with SFAS 121 "Accounting for the Impairment of
Long-Lived Assets and Long-Lived Assets to be Disposed of".  

               General and Administrative Expenses.  General and
administrative expense for the year ended June 30, 1997 was
$679,882 compared to $664,370 for the year ended June 30, 1996.

     Recent Accounting Standards

          Statement of Financial Accounting Standards 123.
"Accounting for Stock Based Compensation" (SFAS 123), was issued
by the Financial Accounting Standards Board in October 1995. 
SFAS 123 establishes financial accounting and reporting standards
for stock-based employee compensation plans as well as
transactions in which an entity issues its equity instruments to
acquire goods and services from non-employees.  Through the year
ended June 30, 1997, the Company has not granted options or
issued equity instruments to any individual as compensation or
for goods and services. 

Statement of Financial Accounting Standards  128, "Earnings Per Share"
(SFAS 128), was issued by the Financial Accounting Standards
Board in February, 1997.  SFAS 128 specifies the computation,
presentation and disclosure requirements for earnings per share
for entities with publicly held common stock.  This statement
simplifies the computation of earnings per share and is required to be
adopted by the Company in the year ending June 30, 1998.  The Company
has not yet evaluated the effects of adopting this statement.

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 the executive officers
and directors of the Company is set forth below:


Aleron H. Larson, Jr.    52   Chairman of the Board,        May 1987  
                              Chief Executive Officer     to Present
                              Secretary, Treasurer,
                              and a Director

Roger A. Parker          35    President and                May 1987  
                                a Director                to Present

Terry D. Enright         48    Director                November 1987 
                                                          to Present

Jerrie F. Eckelberger    53    Director               September 1996
                                                          to Present

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

              Aleron H. Larson, Jr., age 52, 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 17.75% 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 35, 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 48, has been in the oil and
gas business since 1980.  He serves as a Director of both the
Company and Delta.  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 53, is an investor, real
estate developer and attorney who has practiced law in the State
of Colorado for 26 years.  He graduated from Northwestern
University with a Bachelor of Arts degree in 1966 and received
his Juris Doctor degree in 1971 from the University 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 General Partner of 2003 Limited, a Colorado
limited partnership specializing in real estate
development.

              There is no family relationship among any of the
Directors.

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

ITEM 10.      EXECUTIVE COMPENSATION.

                  No officer or director received compensation
directly from the Company during the years ended June 30, 1997,
1996 and 1995.  Messers. Larson and Parker, Chairman and
President, respectively, are compensated by Delta which is paid
under a management agreement with the Company.  No officer or
director received stock appreciation rights, restricted stock
awards, options, warrants or other similar compensation
reportable under this section during any of the above referenced
periods.

ITEM 11.      SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
              MANAGEMENT.

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


Name and Address of          Amount & Nature of       Percent 
Beneficial Owners            Beneficial Ownership     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)
(3) (6) (7) (8) (11)
555 17th St., Ste. 3310
Denver, CO  80202

Aleron H. Larson, Jr.        4,277,977 (1)            91.68% (1)
(2) (6) (7) (11)
555 17th St., Ste. 3310
Denver, CO  80202

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

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

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

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

ITEM 12.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

          Effective March 31, 1993, the Company and Delta entered
into an agreement which provides for the sharing of management
between the two companies.  Under this agreement the Company pays
Delta for its proportionate share of rent, secretarial and
administrative, accounting and management services of Delta
officers and employees.  The amounts paid by the Company to Delta
were $736,145 for the year ended June 30, 1997, $184,053 for the
year ended June 30, 1996.  The Company had a payable to Delta of
$635,139 at June 30, 1997, and $710,229  at June 30, 1996.

                                  PART IV

ITEM 13.  EXHIBITS AND REPORTS ON FORM 8-K

          (a)  Exhibits:

               The Exhibits listed in the Index to Exhibits
appearing at page 20 are filed as part of this report.

          (b)  Reports on Form 8-K:

               None 
                         
                                 SIGNATURE


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

     (Registrant)                  AMBER RESOURCES COMPANY

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

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

     Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has 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                            10/9/97

     By (Signature and Title)       s/Roger A. Parker
                                   Roger A. Parker, Director
     
     Date                            10/9/97
                                                         
     By (Signature and Title)     s/Terry D. Enright
                                 Terry D. Enright, Director

     Date                            10/9/97

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

     Date                            10/9/97
                                                         

                             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. 

(9)  Voting Trust Agreement.  Not applicable.

(10) Material Contracts.  
     
     10.1 Agreement dated March 31, 1993 between Delta Petroleum
          Corporation and Amber Resources Company.     
    
     10.2 Amber Resources Company 1996 Incentive Plan.  Incorporated
          by reference to Exhibit 99.1 of the Company's December 4, 1996
          Form 8-K.

(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 Auditor's Report


The Board of Directors and Stockholders
Amber Resources Company


We have audited the accompanying balance sheets of Amber Resources Company
(a subsidiary of Delta Petroleum Corporation) as of June 30, 1997 and 1996
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, 1997 and 1996, and the results of its operations 
and its cash flows for the years then ended in conformity with generally
accepted accounting principles.

The accompanying financial statements have been prepared assuming the 
Company will continue as a going concern.  As discussed in note 1 to the
financial statements, the Company has suffered recurring losses from 
operations and has a working capital deficiency that raises doubt about
its ability to continue as a going concern.  Management's plans with
regard to these matters are also described in note 1.  The financial
statements do not include any adjustments that might result from
the outcome of this uncertainty.


                                          s/KPMG Peat Marwick LLP
                                          KPMG Peat Marwick LLP
 

Denver, Colorado
September 16, 1997

    
AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)
BALANCE SHEET
June 30, 1997 and 1996                                           
    
    
                                                 1997              1996
                                                                     
    ASSETS
    
    Current Assets:
      Cash                                      $6,440            36,137
      Accounts receivable                      111,728           114,560
      Other current assets                      -                  2,000
    
        Total current assets                   118,168           152,697
    
    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 properties         1,405,645         1,429,967
                                             6,411,921         6,436,243
    
      Less accumulated depreciation
                  and depletion               (846,755)         (726,684)
    
        Net oil and gas properties           5,565,166         5,709,559
    
                                            $5,683,334         5,862,256
    
LIABILITIES AND STOCKHOLDERS' EQUITY         
    
    Current  Liabilities:
      Accounts payable:
        Trade                                  $16,281             8,225
        Affiliate (Note 4)                     635,139           710,229
      Royalties payable                        419,808           595,956
    
        Total current liabilities            1,071,228         1,314,410
    
    Stockholders' Equity
      Preferred stock, $1 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                    (1,434,763)       (1,499,023)
    
        Total stockholders' equity            4,612,106         4,547,846
    
                                             $5,683,334         5,862,256
                                                                     
AMBER RESOURCES COMPANY
(a subsidiary of Delta Petroleum Corporation)
STATEMENT OF OPERATIONS
Years ended June 30, 1997 and 1996
    
                                                     1997             1996
 Revenue:
                                                        
 Oil and gas sales                                $936,929          555,268
 Other income                                      176,345          286,434
    
         Total revenue                           1,113,274          841,702
    
    Expenses:
    
      Lease operating expenses                     203,731          205,971
      Depletion                                    120,071          117,867
      Exploration expenses                           3,330            3,032
      Abandoned and impaired properties             42,000               -
      General and administrative (Note 4)          679,882          664,370
      
         Total expenses                          1,049,014          991,240
    
      Net income (loss)                             64,260         (149,538)
    
    Accumulated deficit at begining of year     (1,499,023)      (1,349,485)
    
    Accumulated deficit at end of year         ($1,434,763)      (1,499,023)
    
    
      Net income (loss) per share                    $0.01            (0.03)
    
    Weighted average number of common
      shares outstanding                          4,666,185        4,666,185
    
    
<TABLE>
    
    AMBER RESOURCES COMPANY
    (A Subsidiary of Delta Petroleum Corporation)
    STATEMENTS OF CASH FLOWS
    Years Ended June 30, 1997 and 1996                                      
<CAPTION>
    
    
                                                            1997               1996
                                                              
<S>                                                        <C>                <C>     
Cash flows from operating activities:                                   
 Net loss                                                   $64,260           (149,538)
 Adjustments to reconcile net income (loss) to cash
     provided by (used in) operating activities:
  Write-off of royalties payable                            (176,148)          (286,244)
   Depletion                                                  120,071            117,867
   Abandoned and impaired properties                           42,000            -
 Net changes in current assets and                       
     and current liabilities:
   Decrease (increase) in accounts receivable                   2,832            (10,513)
   Decrease (increase) in other current assets                  2,000             (2,000)
   Increase (decrease) in accounts payable                      8,056            (70,262)
   Increase in royalties payable                                   -              23,512
   
Net cash provided by (used in) operating activities             63,071           (377,178)
         
Cash flows from investing activities:
   Additions to property and equipment                        (17,678)           (44,294)
    
Net cash used in investing activities                         (17,678)           (44,294)
         
Cash flows from financing activities:
   Decrease (increase) in accounts payable to affiliate       (75,090)           453,858
    
Net cash (used in) provided by financing activities           (75,090)           453,858
         
Net (decrease) increase in cash                               (29,697)            32,386
    
Cash at beginning of year                                       36,137              3,751
    
Cash at end of year                                             $6,440             36,137
</TABLE>
    
    See accompanying notes to financial statements.
    

AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 1997 and 1996
                                                                  
                                       
(1)  Summary of Significant Accounting Policies 

     Organization and Basis of Presentation
     
     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.

     Going Concern Basis of Presentation 

     The financial statements have been prepared on a going
concern basis which contemplates the realization of assets and
the satisfaction of liabilities and commitments in the normal
course of business.  Certain factors, described below, raise
substantial doubt about the ability of the Company to continue as
a going concern.

     At June 30, 1997, the Company has a working capital
deficiency of $953,060.  Current liabilities include royalties
payable of $419,808 at June 30, 1997 which represent the
Company's estimate of royalties payable on production
attributable to it's interest in certain wells in Oklahoma.    

     The Company believes that the operators of the affected
wells have paid some of the royalties on behalf of the Company
and have withheld such amounts from revenues attributable to the
Company's interest in the wells.  The Company has contacted the
operators of the wells in an attempt to determine what amounts
the operators have paid on behalf of the Company over the past
five years, which amounts would reduce the amounts owed by the
Company.  To date the Company has not received information
adequate to allow it to determine the amounts paid by the
operators.  The Company has been informed by its legal counsel
that the applicable statute 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 1997 and 1996.

     Currently, the Company's operations are not generating
sufficient cash flow to fund operations and discharge the
Company's liabilities.  The Company has been economically
dependent upon the Company's parent, Delta Petroleum Corporation. 
Delta has no obligations or commitment to provide further
financial support although it may do so from time to time as it
elects.

     Due to the uncertainties regarding the Company's ability to
generate sufficient cash flow to fund operations and satisfy its
liabilities, there is substantial doubt about the ability of the
Company to continue as a going concern.  The financial statements
do not include any adjustments that might result from the outcome
of this uncertainty.           

     Property and Equipment
     
     The Company follows the successful efforts method of
accounting for its oil and gas activities.  Accordingly, costs
associated with the acquisition, drilling, and equipping of
successful exploratory wells are capitalized.  Geological and
geophysical costs, delay and surface rentals and drilling costs
of unsuccessful exploratory wells are charged to expense as
incurred.  Costs of drilling development wells, both successful
and unsuccessful, are capitalized.
     
     Upon the sale or retirement of oil and gas properties, the
cost thereof and the accumulated depreciation and depletion are
removed from the accounts and any gain or loss is credited or
charged to operations.

     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

     Statement of Financial Accounting Standards 121 "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed of" (SFAS 121) was issued in March 1995.  This
statement requires that long-lived assets be reviewed for
impairment when events or changes in circumstances indicate that
the carrying value of such assets may not be recoverable.  This
review consists of a comparison of the carrying value of the
asset with the asset's expected future undiscounted cash flows
without interest costs.

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

     The Company's proved properties were assessed for impairment
on an individual field basis and the Company recorded an
impairment provision of $42,000 attributable to certain producing
properties for the year ended June 30, 1997.

     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, 1997, the Company had produced approximately
192,000 Mcf more than its entitled share of production.  The
undiscounted value of this imbalance is approximately $420,000
using the lower of the price received for the natural gas, the
current market price or the contract price as applicable.

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

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

     The statute of limitation has expired for royalty owners to
make a claim for a portion of the estimated royalties that had
previously been accrued.  Accordingly, these amount have been
written off and recorded as other income in 1997 and 1996.

     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.

     Income (Loss) Per Common Share

     Income (loss) per share is computed by dividing the net
income or loss for the period by the weighted average number of
shares of common stock outstanding during the year. 

     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.  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.

(3)  Income Taxes
     
     At June 30, 1997 and 1996, the Company s significant
deferred tax assets and liabilities are summarized as follows:

                                            1997         1996   
      Deferred tax assets:                                      
         Net operating loss
           carryforwards               $2,043,000     2,090,000 
         Oil and gas properties,
           principally due to 
           differences in basis and 
           depreciation and depletion       9,000         4,000 
         Gross deferred tax assets      2,052,000     2,094,000 

         Less valuation allowance      (2,052,000)   (2,094,000)
         
         Net deferred tax asset     $       -             -      

         No income tax expense was recorded for the year
ended June 30, 1997 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.

        No income tax benefit has been recorded for the year ended
June 30, 1996 since the benefit of the net operating loss carryforward
and other net tax assets arising in that period has been offset by an
increase in the valuation allowance for such net deferred tax assets.

         At June 30, 1997, the Company had net operating loss
carryforwards for regular and alternative minimum tax purposes of
approximately $5,000,000 and $5,000,000, respectively.  If not
utilized, the tax net operating loss carryforwards will expire
during the period from 1998 through 2012.  

(4)      Related Party Transactions

         Effective March 31, 1993, the Company and Delta entered
into an agreement which provides for the sharing of management
between the two companies.  Under this agreement the Company pays
Delta for its proportionate share of rent, secretarial and
administrative, accounting and management services of Delta's
officers and employees.  Amounts paid by the Company to Delta
were $736,145 for the year ended June 30, 1997 and $184,053 for
the year ended June 30, 1996.  The Company had a payable to Delta
of $635,139 at June 30, 1997 and $710,229 at June 30, 1996.

(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,  
                                      1997              1996     
    
Undeveloped offshore
    California properties          $ 5,006,276         5,006,276 
Developed onshore
    domestic properties              1,405,645         1,429,967 
                                     6,411,921         6,436,243 
Accumulated depreciation
    and depletion                     (846,755)         (726,684)

                                   $ 5,565,166         5,709,559 

    Costs incurred in oil and gas producing activities for the
years ended June 30, 1997 and 1996 are as follows:

                                        1997             1996
     
Exploration costs                    $  3,330           3,032

Development costs                      17,678          44,294

    Sales of major customers accounted for approximately 62%, 22%
and 11% of 1997 oil and gas sales.  Sales to major customers
accounted for approximately 51%, 26% and 15% of 1996 oil and gas
sales.  

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

    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.  Proved developed oil and gas
reserves are those expected to be recovered through existing
wells with existing equipment and operating methods.  The
determination of oil and gas reserves is highly complex and
interpretive.  The estimates are subject to continuing changes as
additional information becomes available.

    The Company s offshore California proved undeveloped reserves
are attributable to its interests in three federal units located
offshore California near Santa Barbara.  While these interests
represent ownership of substantial oil and gas reserves
classified as proved undeveloped, the cost to develop the
reserves will be very substantial.  The Company may be required
to farm out all or a portion of its interests in these properties
if it cannot fund its share of the development costs.  There can
be no assurance that the Company can farm out its interests on
acceptable terms.  If the Company were to farm out its interests
in these properties, its share of the proved reserves
attributable to the properties would be decreased substantially. 
The Company may also incur substantial dilution of its interests
in the properties if it elects to use other methods of financing
the development costs.

    These units have been formally approved and are regulated by
the Minerals Management Service of the Federal Government. 
However, due to a history of opposition to offshore drilling and
production in California by some individuals and groups, the
process of obtaining all of the necessary permits and
authorizations to develop the properties will be lengthy and even
after all required approvals are obtained, lawsuits may possibly
be filed to attempt to further delay the development of the
properties.  While the Federal Government has recently attempted
to expedite this process, there can be no assurance that it will
be successful in doing so.  The Company does not have a
controlling interest in and does not act as the operator of any
of the offshore California properties and consequently will not
control the timing of either the development of the properties or
the expenditures for development.  Management and its independent
engineering consultant have considered these factors relating to
timing of the development of the reserves in the preparation of
the reserve information relating to these properties.  As 
additional information becomes available in the future, the
Company s estimates of the proved undeveloped reserves
attributable to these properties could change,
and such changes could be substantial.

    
A summary of changes in estimated quantities of proved reserves for the year
ended June 30, 1997 and 1996 are as follows:
    
<TABLE>
    
                                                Onshore                      Offshore
                                          GAS         OIL           GAS             OIL
                                         (MCF)       (BBLS)        (MCF)          (BBLS)
    
<S>                                    <C>            <C>        <C>              <C>
Balance at July 1, 1995                1,912,996      5,143      12,965,321       10,582,158
    
 Revisions of quantity estimates         244,595      1,108        (437,396)       (425,072)
 Production                             (308,713)      (961)         -               -
 Balance at June 30, 1996              1,848,878      5,290      12,527,925      10,157,086
    
 Revisions of quantity estimates         423,641      1,551       1,229,841         727,676
 Production                             (400,725)    (1,025)          -               -
Balance at June 30, 1997               1,871,794      5,816      13,757,766      10,884,762
    
Proved developed reserves:
   June 30, 1995                       1,912,996      5,143          -               -
   June 30, 1996                       1,848,878      5,290          -               -
   June 30, 1997                       1,871,794      5,816          -               -
    
The principal sources of changes in the standardized measure of discounted
net cash flows during the year ended June 30, 1997 and 1996 are as follows:

</TABLE>
<TABLE>
      
      
                                                                    Offshore
                                                    Onshore        California        Total
      
<S>                                                <C>             <C>             <C>    
June 30, 1996:
      
 Future cash inflows                               $3,269,173      122,000,784     125,269,957
 Future costs:
   Production                                       1,419,597       24,198,311      25,617,908
   Development                                         -            24,358,749      24,358,749
   Income taxes                                        -            22,466,026      22,466,026
      
 Future net cash flows                              1,849,576       50,977,698      52,827,274
    
  10% discount factor                                 540,036       39,522,746      40,062,782
      
Standardized measure of discounted future
        net cash flows                             $1,309,540       11,454,952      12,764,492
      
June 30, 1997
      
Future cash inflows                                 $4,149,260     141,472,084     145,621,344
  Future costs:
  Production                                         1,559,326      39,050,005      40,609,331
  Development                                          -            27,732,752      27,732,752
  Income taxes                                         -            25,199,636      25,199,636
      
Future net cash flows                                2,589,934      49,489,691      52,079,625
      
 10% discount factor                                   799,581      41,187,165      41,986,746
      
Standardized measure of discounted future
     net cash flows                                 $1,790,353       8,302,526      10,092,879
</TABLE>

The principal sources of changes in the standardized measure of discounted
net cash flows during the year ended June 30, 1997 and 1996 are as follows:


                                                     1997             1996

Beginning of year                              $12,764,492         8,189,628

Sales of oil and gas produced during the
    period, net of production costs               (733,198)         (349,297)
Net change in prices and production costs           63,007           334,973
Changes in estimated future development costs     (938,661)         (340,766)
Revisions of previous quantity estimates,
    estimated timing of development and other   (1,940,936)         5,154,944
Net change in income taxes                        (398,274)        (1,043,951)
Accretion of discount                            1,276,449            818,961

End of year                                    $10,092,879         12,764,492
  

      
The standardized measure of discounted future net cash flows to proved oil
and gas reserves and the changes in standardized measure of discounted
future net cash flows relating to proved oil and gas reserves were
prepared in accordance with the provisions of Statement of Financial
Accounting Standards 69.  Future cash inflows were computed by
applying current prices at year-end to estimated future production.
Future production and development costs are computed by estimating
the expenditures to be incurred in developing and producing the 
proved oil and gas reserves at year-end, based on year-end costs
and assuming continuation of existing economic conditions.  Future
income tax expenses are calculated by applying appropriate year-end
tax rates to future pre-tax net cash flows relating to proved
oil and gas reserves, less the tax basis of properties involved
and tax credits and loss carryforwards relating to oil and gas
producing activities.  Future net cash flows are discounted
at a rate of 10% annually to derive the standardized measure
of discounted future net cash flows.  This calculation
procedure does not necessarily result in an estimate of the
fair market value or the present value of the Company's 
oil and gas properties.