AMBER RESOURCES CO, 10KSB, 1996-10-15

AMBER RESOURCES CO
10KSB, 1996-10-15
CRUDE PETROLEUM & NATURAL GAS

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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, 1996
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 No X

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 aggregate market value as of the Company's voting stock held
by non-affiliates of the Company as of September 23, 1996 could
not be determined because there is no established public trading
market.

As of September 23, 1996 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 4
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 9
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS
OR PLAN OF OPERATIONS 10
ITEM 7. FINANCIAL STATEMENTS 15
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 15

PART III

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE
EXCHANGE ACT 15
ITEM 10. EXECUTIVE COMPENSATION 17
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 (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. At present, 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, 1996, the
Company estimated its proved producing reserves attributable to
its onshore properties to be 5,300 Bbls of oil and 1.85 Bcf of
gas. At June 30, 1996, the Company estimated its proved
undeveloped reserves attributable to its offshore California
properties are estimated to be 10,157,000 Bbls of oil and 12.53
Bcf of gas. There are significant 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, 1996, 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. Under the
agreement, Amber pays Delta for its proportionate share of rent,
secretarial and administrative, accounting and management
services of Delta officers, employees and consultants.

From August 20, 1991 through December 31, 1991,
Underwriters Financial Group, Inc. ("UFG") (formally Chippewa
Resources Corpration) acquired 80.08% of the
outstanding common stock of the Company (3,736,775 shares). The
shares of the Company were acquired in exchange for shares of
common stock of UFG, shares of convertible preferred
stock of UFG, and a note payable secured by a portion of the
shares acquired. On April 30, 1992, UFG acquired an additional
373,885 shares of the Company's common stock in exchange
for shares of its common stock, thereby increasing its ownership
of the Company to 88.09%. In October 1992, UFG concluded a
series of agreements with Delta Petroleum Corporation
("Delta"), then a majority owned public subsidiary of UFG, to
participate in a plan to reorganize and recapitalize Delta (the
"Plan of Reorganization"). Under the terms of the Plan of
Reorganization, UFG transferred 4,110,660 shares it owned of the
Company to Delta. Also in connection with the Plan of
Reorganization, Delta issued shares of its common stock to
Messrs. Burdette A. Ogle and Ronald Heck (collectively "Ogle"),
shareholders of Delta, in exchange for 167,317 shares of common
stock of the Company. As a result of these transactions, at June
30, 1996, Delta owned 4,227,377 shares, or 91.68% of the
outstanding common stock of the Company. As of that date,
3,357,003 shares of common stock of the Company owned by Delta
were pledged to secure a note payable by UFG to Snyder Oil
Corporation in the principal amount of $2,091,761. The note is
currently in default.

(b) Business of Issuer.

(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 four major customers for the sale of oil and gas as
of the date of this report, namely, Natural Gas
Clearinghouse, Tristar Gas Marketing and El Paso Natural Gas
Company. 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
view 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, services or techniques.

(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 operation of 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, 1997.

(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.

(b) Oil and Gas Properties

The Company owns interests in oil and gas
properties located in Oklahoma and 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, 1996 and 1995.

California.

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.

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 1,500' 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, 1996, Mannon Associates, Inc., an independent petroleum
engineering firm based in Santa Barbara, California, issued a
report indicating that Gato Canyon contains recoverable reserves
estimated to be 89.5 million Bbls of oil and 128.1 Bcf of natural
gas representing approximately 5,197,000 Bbls of oil and 7.4 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 per Bbl and $1.68 per Mcf and SEC parameters, the
Company's 6.97% working interest in the Gato Canyon Unit
has a pretax discounted (10%) present value of approximately
$9,345,000. (See "--Oil and Gas Reserves".) No production in
the Gato Canyon Unit is presently anticipated before 2001.

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 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 Mannon Associates, Inc., on July 1, 1996 the Lion
Rock Unit contains proved undeveloped recoverable reserves of 543
million Bbls of oil and 491 Bcf of natural gas,
equivalent to approximately 3,021,000 barrels of oil and 2.7 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 $12.00 per Bbl and $1.68 per Mcf and SEC parameters, the
Company's aggregate interest in the Lion Rock Unit has a pre-tax
present value (discounted at 10%) of approximately
$5,356,000 as of July 1, 1996. (See "--Oil and Gas Reserves".)
No production is presently anticipated before 2001.

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, 1996 report prepared by
Mannon Associates, Inc., the Sword Unit contains proved
undeveloped recoverable reserves of 267 million Bbls of oil and
324 Bcf of natural gas representing reserves of approximately
1,939,000 barrels of oil (having an estimated average gravity of
10.6 API) and 2.4 Bcf of natural gas to the Company's interest.
Based on prices of $12.00 per Bbl and $1.68 per Mcf and SEC
parameters, the Company's interest in the Sword Unit has a
pre-tax present value (discounted at 10%) of approximately
$2,182,000. (See "--Oil and Gas Reserves".) No production is
presently anticipated before 2004.

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.

Approximately half of the Oklahoma wells were acquired
by the Company subject to a recoupment agreement with a gas
purchaser. Under the terms of the recoupment agreement,
the gas purchaser was entitled to receive up to 75% of future
production to recoup gas purchased in connection with the
settlement of a previous take or pay contract covering the
properties. The Company was responsible for royalties and for
production costs associated with the properties
subject to the recoupment agreement.

On November 18, 1994, the Company entered into an
agreement with El Paso Natural Gas Company ("El Paso") under
which the Company agreed to transfer to El Paso it's
interest in four wells and the associated acreage in complete
satisfaction of the recoupment gas obligation to El Paso. As a
result of this agreement, the Company is no longer obligated to
El Paso for recoupment gas from the remaining wells subject to
the recoupment agreement.

The obligation under the recoupment agreement has been
accounted for in a manner similar to a production payment. The
estimated present value of the obligation at the
date of the acquisition of the properties was recorded as a
liability. The liability was calculated based on remaining
volumes of gas due, using the price of gas at the date of the
acquisition of the properties, discounted at 15% over the period
the gas is expected to be recouped. The
liability is periodically increased by the accretion of the
discount and is reduced as the gas was
delivered to the gas purchaser. The gas produced and delivered
to the gas purchaser (recoupment gas) was recorded as revenue at
the then current price of natural gas. Any
difference between the revenue recorded for the recoupment gas
and the reduction in the recoupment obligation was accounted for
as an increase or decrease in interest expense.

Recoupment royalties, included in royalties payable,
represent amounts that may be due on recoupment gas produced and
delivered to the gas purchasers 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. The Company's
method of estimating the liability to royalty owners is based
upon its interpretation of existing law in the jurisdiction as
applied to the circumstances relating to its properties. There
is no assurance that the Company's method
of calculating its liability to the royalty owners would prevail
in court if challenged and if challenged that another method of
calculation would not be imposed on the Company. The
Company believes that the operators of the affected wells have
paid some or all 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, this amount has
been written off and recorded as other income in 1996.

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:

Six Months
Year Ended Year Ended Ended
June 30, 1996 June 30, 1995 June 30, 1994

Average sales price:

Oil (per barrel) $20.85 15.27 14.52
Natural Gas (per Mcf) $1.73 1.55 1.57

Production costs (per
Mcf equivalent) $.65 .57 .61

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, 1996, 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 41 2.51 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, 1996, 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, 1996 and 1995, 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,
1996.

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 1995 and 1996 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, 1996 was approximately 1,031.

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.

Background

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 interest in undeveloped oil and gas
properties offshore California, near Santa Barbara and developed
(and undeveloped) oil and gas properties in the
continental United States.

From August 20, 1991 through December 31, 1991,
Underwriters Financial Group, Inc. ("UFG") acquired 80.08% of the
outstanding common stock of the Company (3,736,775 shares). The
shares of the Company were acquired in exchange for shares
of common stock of UFG, shares of convertible preferred stock of
UFG, and a note payable secured by a portion of the shares
acquired. On April 30, 1992, UFG acquired an additional
373,885 shares of the Company's common stock in exchange for
shares of its common stock, thereby increasing its ownership of
the Company to 88.09%. In October 1992, UFG concluded
a series of agreements with Delta Petroleum Corporation
("Delta"), then a majority owned public subsidiary of UFG, to
participate in a plan to reorganize and recapitalize Delta (the
"Plan of Reorganization"). Under the terms of the Plan of
Reorganization, UFG transferred the 4,110,660 shares of the
Company it owned to Delta. Also in connection with the Plan of
Reorganization, Delta issued shares of its common stock to
Messrs. Burdette A. Ogle and Ronald Heck (collectively "Ogle"),
shareholders of Delta, in exchange for 167,317 shares of
common stock of the Company. As a result of these transactions,
at June 30, 1996, Delta owns 4,227,377 shares, or 91.68% of the
outstanding common stock of the Company. As of that
date, 3,357,003 shares of common stock of the Company owned by
Delta are pledged to secure a note payable by UFG to Snyder Oil
Corporation in the principal amount of $2,091,761. The
note is currently in default.

Liquidity and Capital Resources.

At June 30, 1996, the Company had a working
capital deficit of $1,161,713 compared to a working capital
deficit of $1,085,748 at June 30, 1995. 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
increased from June 30, 1995 as the Company's proportionate share
of rent, secretarial and administrative, accounting and
management services paid by Delta exceeded the Company's
available cash flow during the period.

The Company's current liabilities include
royalties payable of $595,956 at June 30, 1996 which represent
the Company's estimate of royalties payable on production
attributable to it's interest in certain wells in Oklahoma. The
Company is attempting to identify the royalty owners and
calculate the amounts owed to each owner, which it expects will
require some time. To date, no significant claims have been
asserted against the Company by royalty owners for amounts due
for prior production. The Company is awaiting the outcome of
litigation in various courts which may impact the method of
calculating the Company's obligation for royalties payable on
recoupment gas. To date no claims have been asserted against the
Company by royalty owners for royalties due on recoupment gas
produced.

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, approximately
$286,000 has been written off and recorded as other income in 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.

On November 18, 1994, the Company entered into an
agreement with El Paso Natural Gas Company ("El Paso") under
which the Company agreed to transfer to El Paso
the Company's interest in four wells and the associated acreage
in complete satisfaction of the recoupment gas obligation. As a
result of this agreement, the Company is no longer obligated
to El Paso for recoupment gas from the remaining wells subject to
the recoupment agreement. As a result of this transaction, the
Company recorded an extraordinary gain of $493,850 in 1995.

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 explore 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. Through
the period ended June 30, 1996, Delta continued to advance funds
to the Company. 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 loss for
the year ended June 30, 1996 was $149,538 compared to a net loss
for the year ended June 30, 1995 was $118,834,
net of a $493,850 extraordinary gain on the settlement of the
Company's recoupment gas obligation. The loss for the year ended
June 30, 1995 included $178,532 for abandoned and
impaired properties and interest on recoupment obligation of
$113,285.

Revenue. Oil and gas sales for the year ended
June 30, 1996 was $555,268 compared to $730,776 for the year
ended June 30, 1995. The decrease in oil and gas
sales for the year ended June 30, 1996 compared to the year ended
June 30, 1995 resulted from the settlement of the Company's
recoupment gas obligation in 1995. Revenue from oil and gas
sales includes amortization of the Company's recoupment gas
obligation of $167,009 for the year ended June 30, 1995. Revenue
was recorded as the recoupment gas was produced and delivered
to the gas purchaser. The amount of revenue recorded varied with
the amount of gas recouped by the purchaser and the current price
of gas. On November 18, 1994, the Company entered
into an agreement with El Paso Natural Gas Company under which
Amber agreed to transfer to El Paso the Company's interest in
four wells and the associated acreage in complete
satisfaction of the obligation. As a result of this agreement,
the Company is no longer obligated to El Paso for the recoupment
gas from the remaining wells originally subject to the recoupment
agreement.

Production volumes and average prices received for
the years ended June 30, 1996 and 1995 are as follows:

Year Ended Year Ended
June 30, 1996 June 30, 1995

Production:

Oil (barrels) 961 959

Gas (Mcf) 309,709 348,316

Recoupment gas (Mcf) - 113,612

Average Price:

Oil (per barrel) $20.85 15.27

Gas (per Mcf) $ 1.73 1.55

Lease Operating Expenses. Lease operating
expenses for the year ended June 30, 1996 was $205,971 compared
to $200,384 for the year ended June 30, 1995. On a
MCF equivalent basis excluding recoupment gas, production
expenses and taxes were $.65 per Mcf equivalent during the year
ended June 30, 1996 compared to $.57 for the year ended June
30, 1995.

Depletion Expense. Depletion expense for the year
ended June 30, 1996 was $117,867 compared to $212,750 for the
year ended June 30, 1995. On a MCF equivalent
basis the depletion rate was $.37 per Mcf equivalent during year
ended June 30, 1996 compared to $.79 per Mcf equivalent for the
year ended June 30, 1995. The decline in depletion rate per MCF
equivalent can be attributed to the $178,532 impairment recorded
in 1995.

Exploration Expenses. Exploration expenses
consist of geological and geophysical costs and lease rentals.
The Company incurred exploration costs of $3,032 for the
year ended June 30, 1996 and no exploration expenses for the year
ended June 30, 1995.

Abandonment and Impairment of Oil and Gas
Properties. The Company recorded an expense for abandoned and
impaired properties for the year ended June 30, 1995
of $178,532 primarily due to depressed natural gas prices.

General and Administrative Expenses. General and
administrative expense for the year ended June 30, 1996 was
$664,370 compared to $696,352 for the year ended June
30, 1995.

Interest on Recoupment Gas Obligation Expense.
Imputed interest expense on the recoupment gas obligation was
$113,285 for the year ended June 30, 1995.

Future Operations

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.

Recent Accounting Standards

Statement of Financial Accounting Standards No. 123.
Accounting for Stock Based Compensation (SFAS No. 123), was
issued by the Financial Accounting Standards Board
in October 1995. SFAS No. 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. The Company will include the disclosures required
by SFAS No. 123 in the notes to future 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

None.

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:

The directors and officers of the Registrant are
as follows:

Name Position Period of Service

Aleron H.
Larson, Jr. Chairman, Chief Executive August 1991 to
Present
Officer, Secretary
Treasurer and Director

Roger A. Parker President, Chief Operating August 1991 to
Present
Officer and Director

Terry D. Enright Director August 1994 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 any executive
officer and director of the Registrant.

Aleron H. Larson, Jr., age 51, has operated as an
investor and 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. During part of 1989 and part of 1990, he
served as a Director of Apex Operating Company, Inc. and
P & G Exploration (formerly Texco Exploration, Inc.). Mr. Larson
has been principally involved in the oil and gas business since
1978. 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 34, 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 has
operated as an investor and an independent in the oil and gas
industry individually and through public and private ventures
since 1982. He was at various times, from 1982 to 1989, a
Director, Executive Vice President, President and Shareholder of
Ampet, Inc. He received a Bachelor of Science in Mineral Land
Management from the University of Colorado in 1983. He is a
member of the Rocky Mountain Oil and Gas
Association and the Independent Producers Association of the
Mountain States (IPAMS).

Terry D. Enright, age 47, 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.

There is no family relationship among any of the Directors.

The Company has no executive or audit committees, nor any
nominating or compensation committees.

ITEM 10. EXECUTIVE COMPENSATION.

No officer or director received compensation directly
from the Company during the year ended June 30, 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
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)
(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

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

(1) All shares are owned by Delta; Messrs. Larson and Parker are
officers, directors and controlling shareholders of Delta. Mr.
Enright is also a director 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 payable by the Company to Delta were $184,053 for the
year ended June 30, 1996 and $468,658 for the year ended June 30,
1995. The Company had a payable to Delta of $710,229
at June 30, 1996 and $256,371 at June 30, 1995.

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.,
Chairman/C.E.O.

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

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

Date 10/11/96

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

Date 10/11/96

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

Date 10/11/96

INDEX TO EXHIBITS

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

(4) Instruments Defining the Rights of Security Holders. Not
applicable.

(9) Voting Trust Agreement. Not applicable.

(10) Material Contracts. Not applicable.

(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.

(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 (a subsidiary of Delta Petroleum Corporation) as of
June 30, 1996 and 1995 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, 1996 and 1995, 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 substantial 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.

As discussed in Note 1 to the financial statements, the Company
adopted the provisions of Statement of Financial Accounting
Standards No. 121 "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of" in the year
ended June 30, 1995.

KPMG Peat Marwick LLP

Denver, Colorado
September 20, 1996

AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)
BALANCE SHEET
June 30, 1996 and 1995

1996 1995

ASSETS

Current Assets:
Cash $36,137 3,751
Accounts receivable 114,560 104,047
Other current assets 2,000 -

Total current assets 152,697 107,798

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 1,429,967 1,385,673
6,436,243 6,391,949

Less accumulated depreciation and depletion (726,684) (608,817)

Net oil and gas properties 5,709,559 5,783,132

$5,862,256 5,890,930

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities:
Accounts payable:
Trade $8,225 78,487
Affiliate (Note 4) 710,229 256,371
Royalties payable 595,956 858,688

Total current liabilities 1,314,410 1,193,546

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 (1,499,023) (1,349,485)

Total stockholders' equity 4,547,846 4,697,384

$5,862,256 5,890,930

STATEMENTS OF OPERATIONS
Years Ended June 30, 1996 and 1995

1996 1995
Revenue:

Oil and gas sales, including recoupment
gas of $167,009 in 1995 $555,268 730,776
Gain on sale of oil and gas properties - 57,667
Other income 286,434 176

Total revenue 841,702 788,619

Expenses:

Lease operating expenses 205,971 200,384
Depletion 117,867 212,750
Exploration expenses 3,032 -
Abandoned and impaired properties - 178,532
General and administrative 664,370 696,352
Interest on recoupment gas obligation (Note 1) - 113,285

Total expenses 991,240 1,401,303

Loss before extraordinary item (149,538) (612,684)

Extraordinary gain on settlement of recoupment
gas obligation (Note 1) - 493,850

Net loss (149,538) (118,834)

Accumulated deficit at begining of year (1,349,485) (1,230,651)

Accumulated deficit at end of year ($1,499,023) (1,349,485)

Loss per common share:
Loss before extraordinary item ($0.03) (0.13)
Extraordinary gain on settlement of recoupment
gas obigation - 0.10
Net loss ($0.03) (0.03)

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

STATEMENTS OF CASH FLOWS
Years Ended June 30, 1996 and 1995

1996 1995

Cash flows from operating activities:
Net loss ($149,538) (118,834)
Adjustments to reconcile net loss to cash
provided by (used in) operating activities:
Write-off of royalties payable (286,244) -
Depletion 117,867 212,750
Abandoned and impaired properties - 178,532
Interest on recoupment gas obligation - 113,285
Recoupment gas revenue - (167,009)
Gain on sale of oil and gas properties - (57,667)
Extraordinary gain on settlement of
recoupment gas obligation - (493,850)
Net changes in current assets and
and current liabilities:
Increase in accounts receivable (10,513) (44,553)
(Increase) decrease in other current assets (2,000) 2,500
(Decrease) increase in accounts payable (70,262) 32,575
Increase in royalties payable 23,512 29,724

Net cash used in operating activities (377,178) (312,547)

Cash flows from investing activities:
Additions to property and equipment (44,294) (29,094)
Proceeds from sale of oil and gas properties - 137,029

Net cash provided by (used in) investing activities (44,294) 107,935

Cash flows from financing activities:
Increase in accounts payable to affiliate 453,858 204,299

Net cash used in financing activities 453,858 204,299

Net increase (decrease) increase in cash 32,386 (313)

Cash at beginning of year 3,751 4,064

Cash at end of year $36,137 3,751

AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 1996 and 1995

(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 offshore
California, near Santa Barbara and developed oil and gas properties
in the continental United States.

From August 20, 1991 through December 31, 1991, Underwriters
Financial Group , Inc. (UFG) acquired 80.08% of the outstanding
common stock of the Company (3,736,775 shares). The shares of the
Company were acquired in exchange for shares of common stock of
UFG, shares of convertible preferred stock of UFG, and a note
payable secured by a portion of the shares acquired. On April 30,
1992, UFG acquired an additional 373,885 shares of the Company's
common stock in exchange for shares of its common stock, thereby
increasing its ownership of the Company to 88.09%. In October,
1992, UFG concluded a series of agreements with Delta Petroleum
Corporation (Delta), then a subsidiary of UFG, to participate in a
plan to reorganize and recapitalize Delta (the Plan of
Reorganization). Under the terms of the Plan of Reorganization,
UFG transferred the 4,110,660 shares of the Company it owned to
Delta. Also in connection with the Plan of Reorganization, Delta
issued 1,030,000 shares of its common stock to Messrs. Burdette A.
Ogle and Ronald Heck (collectively, Ogle), shareholders of Delta,
in exchange for their working interests in two federal offshore
California oil and gas units and 167,317 shares of common stock of
the Company. As a result of these transactions, at June 30, 1996,
Delta owned 4,277,377 shares, or 91.68% of the outstanding common
stock of the Company. As of that date, 3,357,003 shares of common
stock of Amber transferred to the Company by UFG were pledged to
secure a note payable to Snyder Oil Corporation (the Snyder Note).
The note is currently in default.

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, 1996, the Company has a working capital deficiency
of $1,161,713. Current liabilities include royalties payable of
$595,956 at June 30, 1996 which represent the Company's estimate of
royalties payable on production attributable to it's interest in
certain wells in Oklahoma. The Company is attempting to identify
the royalty owners and calculate the amounts owed to each owner,
which it expects will require some time. To date, no significant
claims have been asserted against the Company by royalty owners for
amounts due for prior production. The Company is awaiting the
outcome of litigation in various courts which may impact the method
of calculating the Company's obligation for royalties payable on
recoupment gas. To date no claims have been asserted against the
Company by royalty owners for royalties due on recoupment gas
produced.

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,
this amount has been written off and recorded as other income in
1996.

Through the period ended June 30, 1996, Delta continued to
advance funds to the Company. 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. The
Company assesses impairment of proved oil and gas properties
on an aggregate basis using undiscounted estimated future net
revenue, calculated using constant prices and costs. 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 No. 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.

In the fourth quarter of fiscal 1995, the Company adopted SFAS
121 for its proved oil and gas properties. The Company's proved
properties were assessed for impairment on an individual field
basis and the Company recorded an impairment provision of $178,532
attributable to certain producing properties.

Prior to the adoption of SFAS 121, the Company assessed its
proved oil and gas properties on an aggregate basis using
undiscounted future net revenue, calculated using constant prices
and costs.

Gas Balancing

The Company uses the sales method of accounting for gas
balancing of gas production. Under this method, all proceeds from
production 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, 1996, the Company had produced approximately
106,000 Mcf more than its entitled share of production. The
undiscounted value of this imbalance is approximately $212,000
using the lower of the price received for the natural gas, the
current market price or the contract price as applicable.

Recoupment Gas Obligation

Certain oil and gas properties were acquired by Amber subject
to a recoupment agreement with a gas purchaser. Under the terms of
the recoupment agreement, the gas purchaser was entitled to receive
up to 75% of future production to recoup gas purchased in
connection with the settlement of a previous take or pay contract
covering the properties. The gas purchaser had recourse only to
the properties subject to the agreement.

The obligation under the recoupment agreement was accounted
for in a manner similar to a production payment. The estimated
present value of the obligation at the date of the acquisition of
the properties was recorded as a liability. The liability was
calculated based on remaining volumes of gas due, using the price
of gas at the date of the acquisition of the properties, discounted
at 15% over the period the gas was expected to be recouped. The
liability was periodically increased by the accretion of the
discount and was reduced as the gas was delivered to the gas
purchaser. The gas produced and delivered to the gas purchaser
(recoupment gas) was recorded as revenue at the then current price
of natural gas. Any difference between the revenue recorded for
the recoupment gas and the reduction in the recoupment obligation
was accounted for as an increase or decrease in interest expense.

The Company was responsible for royalties and for production
costs associated with the properties subject to the recoupment
agreement.

On November 18, 1994, the Company entered into an agreement
with El Paso Natural Gas Company (El Paso) under which the Company
agreed to transfer to El Paso, Amber's interest in four wells and
the associated acreage in complete satisfaction of the recoupment
gas obligation. As a result of this agreement, the Company is no
longer obligated to El Paso for recoupment gas from the remaining
wells originally subject to the recoupment agreement. As a result
of this transaction, the Company recorded an extraordinary gain of
$493,850 in fiscal 1995.

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 and pending the outcome of
litigation involving other operators that may impact the
calculations of the royalties.

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, this amount has been written
off and recorded as other income in 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 No. 109 (SFAS No. 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 No. 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 liabilites 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.

Reclassifications

Certain amounts in the 1995 fincial statements have been
reclassified to conform to the 1996 financial statement
presentation.

(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, 1996 and 1995, the Company's significant deferred
tax assets and liabilities are summarized as follows:

1996 1995
Deferred tax assets:
Net operating loss
carryforwards $ 1,536,000 1,862,000

Gross deferred tax assets 1,536,000 1,862,000

Less valuation allowance (26,000) (122,000)

Net deferred tax assets 1,510,000 1,740,000

Deferred tax liabilities:
Oil and gas properties,
principally due to
differences in basis and
depreciation and depletion (1,510,000)(1,740,000)

Net deferred tax asset $ - -

No income tax benefit has been recorded for the years ended
June 30, 1996 and 1995 since the benefit of the net operating loss
carryforward and other net deferred tax assets arising in those
periods has been offset by an increase in the valuation allowance
for such net deferred tax assets.

At June 30, 1996, the Company had net operating loss
carryforwards for regular and alternative minimum tax purposes of
approximately $4,500,000 and $4,100,000, respectively. If not
utilized, the tax net operating loss carryforwards will expire
during the period from 1997 through 2011.

(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 officers and employees.
Amounts payable by the Company to Delta were $184,053 for the year
ended June 30, 1996 and $468,658 for the year ended June 30, 1995.
The Company had a payable to Delta of $710,229 at June 30, 1996 and
$256,371 at June 30, 1995.

(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,
1996 1995

Undeveloped offshore
California properties $ 5,006,276 5,006,276

Developed onshore
domestic properties 1,429,967 1,385,673
6,436,243 6,391,949
Accumulated depreciation
and depletion (726,684) (608,817)

$ 5,709,559 5,783,132

Costs incurred in oil and gas producing activities for the year
ended June 30, 1996 and 1995 are as follows:

1996 1995

Exploration costs $ 3,032 -

Development costs 44,294 29,094

Sales of major customers accounted for approximately 51%, 26%
and 15% of 1996 oil and gas sales. Sales to major customers
accounted for approximately 38%, 25% and 17% of 1995 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.

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

A summary of changes in estimated quantities of proved reserves, net of
recoupment gas, for the year
ended June 30, 1996 and 1995 are as follows:

Onshore Offshore
GAS OIL GAS OIL
(MCF) (BBLS) (MCF) (BBLS)

<S> <C> <C> <C> <C>
Balance at July 1, 1995 2,997,691 17,609 12,975,847 10,592,365

Revisions of quantity estimates (637,773) (11,507) (10,526) (10,207)
Sale of properties (98,606) - - -
Production (348,316) (959) - -
Balance at June 30, 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

Proved developed reserves:
June 30, 1994 2,997,691 17,609 - -
June 30, 1995 1,912,996 5,143 - -
June 30, 1996 1,848,878 5,290 - -

</TABLE>

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

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.

Offshore
Onshore California Total

June 30, 1995:

<S> <C> <C> <C>
Future cash inflows $2,565,747 119,023,005 121,588,752
Future costs:
Production 1,182,691 18,611,457 19,794,148
Development - 22,948,450 22,948,450
Income taxes - 22,970,738 22,970,738

Future net cash flows 1,383,056 54,492,360 55,875,416

10% discount factor 404,515 47,281,273 47,685,788

Standardized measure of discounted future
net cash flows $978,541 7,211,087 8,189,628

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 flow 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

</TABLE>

The principal sources of changes in the standardized measure of discounted net
cash flows during the year ended
June 30, 1996 and 1995 are as follows:

1996 1995

Beginning of year $8,189,628 8,913,296

Sales of oil and gas produced during the
period , net of production costs (349,297) (530,392)
Net change in prices and production costs 334,973 47,972
Changes in estimated future development costs (340,766) (5,344)
Revisions of previous quantity estimates,
estimated timing of development and other 5,154,944 (1,437,620)
Net change in income taxes (1,043,951) 372,798
Sales of reserves in place - (62,412)
Accretion of discount 818,961 891,330

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

The standardized measure of discounted future net cash flows relating 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
Standard No. 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
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.

<ARTICLE> 5

<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> JUN-30-1996
<PERIOD-END> JUN-30-1996
<CASH> 36,137
<SECURITIES> 0
<RECEIVABLES> 114,560
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 152,697
<PP&E> 6,436,243
<DEPRECIATION> 726,684
<TOTAL-ASSETS> 5,862,256
<CURRENT-LIABILITIES> 1,314,410
<BONDS> 0
291,637
0
<COMMON> 0
<OTHER-SE> 4,266,209
<TOTAL-LIABILITY-AND-EQUITY> 4,547,846
<SALES> 555,268
<TOTAL-REVENUES> 841,702
<CGS> 0
<TOTAL-COSTS> 991,240
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (149,538)
<INCOME-TAX> 0
<INCOME-CONTINUING> (149,538)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (149,538)
<EPS-PRIMARY> (.03)
<EPS-DILUTED> 0

</TABLE>