AMBER RESOURCES CO, 10KSB, 1996-06-19

AMBER RESOURCES CO
10KSB, 1996-06-19
CRUDE PETROLEUM & NATURAL GAS

Previous: CENTURY PROPERTIES FUND XIII, 8-K, 1996-06-19

Next: EMERGENT GROUP INC, 8-K, 1996-06-19

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, 1995
or
[ ] Transition Report under Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transition period .

Commission File No. 0-8874

AMBER RESOURCES COMPANY
(Exact name of registrant as specified in its charter)

Delaware 84-0750506
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)

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

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

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

Securities registered pursuant to Section 12(g) of the Act:

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

Check whether issuer (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes 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 May 31, 1996 could not be
determined because there is no established public trading market.

As of May 31, 1996, 4,666,185 shares of registrant's Common Stock
$.0625 par value were issued and outstanding.

The Index to Exhibits appears at Page 22.

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 10
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS
OR PLAN OF OPERATIONS 11
ITEM 7. FINANCIAL STATEMENTS 16
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 16

PART III

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE
EXCHANGE ACT 16
ITEM 10. EXECUTIVE COMPENSATION 18
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT 19
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS 19
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K 20

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, 1995, the Company estimated its proved producing
reserves attributable to its onshore properties to be 1.9 Bcf of
gas. At June 30, 1995, the Company estimated its proved
undeveloped reserves attributable to its offshore California
properties to be 10,582,158 Bbls of oil and 12.96 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, 1995,
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.

In September 1989, the Company's common stock was reverse
split on the basis of one share for each 20 shares previously
outstanding. All references to common stock herein give effect to
the reverse split.

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, 1995, 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 amount of
$2,091,761, including accrued interest. The note is currently in
default.

The Company adjusted the basis of its assets and
liabilities in 1991 to reflect the new basis of accounting
resulting from the acquisition for more than 80% of its common
shares by UFG. The Company's net assets were adjusted to reflect
UFG's acquisition costs of the shares of $5,406,408. The minority
shareholders' interest in the Company was not reflected in this
adjustment as accumulated losses had exceeded their original
investment at that date. The subsequent acquisition of additional
shares of the Company by UFG in 1992 was accounted for as an
increase in oil and gas properties and an increase in additional
paid-in capital of $595,461, representing the estimated fair value
of the UFG shares issued in the exchange. The acquisition by Delta
of additional shares from Ogle was also accounted for in 1992 as an
increase in oil and gas properties and an increase in additional
paid-in capital of $45,000, representing Ogle's predecessor cost of
the shares of the Company. The additional shares acquired from
Ogle by Delta were accounted for at predecessor cost due to the
related party nature of the transaction.

Ownership by Delta. At June 30, 1995, Delta owned
4,277,977 shares of the common stock of Amber, which were the
equivalent of 91.68% of the outstanding common stock of Amber.
Delta and Amber entered into an 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.

(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 three major customers for the sale of oil and gas as of
the date of this report, namely, Apache Corporation, Natural Gas
Clearinghouse 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, 1996.

(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 year ended
December 31, 1993, the six month period ended June 30, 1994, or the
year ended June 30, 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 the 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 most significant unit is known as
the Gato Canyon Unit, in which the Company owns a 6.97% working
interest. 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, 1995, 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 72.6 million Bbls of oil and
102.6 Bcf of natural gas representing 5,060,365 Bbls of oil and 7.1
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 $11 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 $7,607,000.
(See "--Oil and Gas Reserves".) No production in the Gato Canyon
Unit is presently anticipated before 2002.

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, 1995 the Lion Rock Unit contains
proved undeveloped recoverable reserves of 453 million Bbls of oil
and 409 Bcf of natural gas, equivalent to 3,242,548 barrels of oil
and 2.9 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
$11.00 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 $4,127,000 as of July 1,
1995. (See "--Oil and Gas Reserves".) No production is presently
anticipated before 2002.

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, 1995 report prepared by Mannon Associates, Inc., the
Sword Unit contains proved undeveloped recoverable reserves of 261
million Bbls of oil and 330 Bcf of natural gas representing
reserves of 2,279,418 barrels of oil (having an estimated average
gravity of 10.6 API) and 2.9 Bcf of natural gas to the Company's
interest. Based on prices of $11.00 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 $1,769,000.
(See "--Oil and Gas Reserves".) No production is presently
anticipated before 2006.

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. During
1993, the Company assigned all of its existing acreage, except for
its interest in producing wellbores, to Delta in exchange for
$20,000 and a 10% working interest after "pay-out" in any wells
drilled thereon.

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 is
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 has
recourse only to the properties subject to the agreement and as a
result, if the dedicated properties deplete prior to full
recoupment, all further obligations to deliver gas are
extinguished. The Company is responsible for royalties and for
production costs associated with the properties subject to the
recoupment agreement. In no case is Amber liable for any cash
payments to the purchaser. The taking of less than the maximum
recoupment extends the time period over which the gas can be
recovered.

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 is delivered to
the gas purchaser. The gas produced and delivered to the gas
purchaser (recoupment gas) is 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 is accounted for as an increase or decrease in interest
expense.

Recoupment gas royalties represent royalties 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 the liability 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 estimating liability to the
royalty owners would prevail in court if challenged and that
another method less favorable to the Company would not be imposed
upon the Company.

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 will no longer be obligated to El Paso for
recoupment gas from the remaining wells subject to the recoupment
agreement. Consequently, the Company will lose the revenues from
the wells transferred to El Paso and gain the revenues from the
remaining wells attributable to production amounts freed from the
recoupment requirements.

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 Ended Year Ended
June 30, 1995 June 30, 1994 December 31, 1993

Average sales price:

Oil (per barrel) $15.27 $14.52 $13.54
Natural Gas (per Mcf) $1.55 $1.57 $1.89

Production costs (per
Mcf equivalent) $.57 $.61 $.48

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, 1995, 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 2.76 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, 1995, 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 year ended June 30, 1995, the Company
participated in the recompletion of one well, but did not
participate in the drilling of any new wells. During the six
months ended June 30, 1994, the Company did not drill any wells.
During 1993 the Company participated in one gross (.0078 net) well
in Oklahoma which was productive of gas.

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,
1995.

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

No matter was submitted to a vote of the Company's
security holders through the solicitation of proxies or otherwise
during the year ended June 30, 1995.

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 1994 and 1995 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, 1995 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.

Liquidity and Capital Resources.

At June 30, 1995, the Company had a working capital
deficit of $1,085,748 compared to a working capital deficit of
$860,890 at June 30, 1994. The Company's working capital deficit
is in part a result of the royalties payable and recoupment
royalties payable held in suspense. The Company's account payable,
affiliate has increased from June 30, 1994 as the Company's
proportionate share of rent, secretarial and administrative,
accounting and management services paid by Delta exceeded the
Company's revenue.

The Company's royalties payable in suspense at June
30, 1995 is $188,847, which represent the Company's estimate of
royalties payable on production attributable to its 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 has estimated that
royalties are payable on recoupment gas produced on certain of its
wells of $669,841 at June 30, 1995. 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 sufficient to
allow it to determine the amounts paid by the operators.

The Company believes that it is unlikely that all
claims that might be made for payment of royalties payable in
suspense or for recoupment 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 in
suspense and recoupment 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 will no longer be obligated to El Paso for recoupment gas
from the remaining wells subject to the recoupment agreement.
Consequently, the Company will lose the revenues from the wells
transferred to El Paso and gain the revenues from the remaining
wells attributable to production amounts freed from the recoupment
requirements. As a result of this transaction, the Company
recorded an extraordinary gain of $493,850.

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.

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.

Through the period ended June 30, 1995, 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.

Results of Operations

Net Earnings (Loss). The Company's 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 compared to a net loss of $249,183 for the six
months ended June 30, 1994 and a net loss of $366,797 for the year
ended December 31, 1993. The loss for the year ended June 30, 1995
included $178,532 for abandoned and impaired properties. The
losses for the six months ended June 30, 1994 and year ended
December 31, 1993 included $21,491 and $8,252, respectively, for
abandoned and impaired properties.

Revenue. Oil and gas sales for the year ended
June 30, 1995 were $730,776 compared to $368,304 for the six months
ended June 30, 1994 and $1,077,905 for the year ended December 31,
1993. Oil and gas revenue stayed consistent for the year ended June
30, 1995 compared with the annualized six months ended June 30,
1994. The decrease in oil and gas sales from the year ended
December 31, 1993 to the annualized six months ended June 30, 1994
resulted from a normal decline in production rates from the
Company's wells and the over production of gas by other working
interest owners in certain gas wells in Oklahoma. 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 and
$255,859 for the six months ended June 30, 1994 and $632,116 for
the year ended December 31, 1993. Revenue is recorded as the
recoupment gas is produced and delivered to the gas purchaser. The
amount of revenue recorded varies 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 will no longer be 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 year ended June 30, 1995, six months ended June 30, 1994 and
the year ended December 31, 1993 are as follows:

Year Ended Six Months Ended Year Ended
June 30, 1995 June 30, 1994 December 31, 1993
Production:

Oil (barrels) 959 469 1,940
Gas (Mcf) 348,316 230,481 557,254
Recoupment gas (Mcf) 113,612 146,205 322,508

Average Price:

Oil (per barrel) $15.27 $14.52 $13.54
Gas (per Mcf) $ 1.55 $ 1.57 $ 1.89

Lease Operating Expenses. Lease operating expenses
for the year ended June 30, 1995 was $200,384 compared to $141,772
and $275,861 for the six months ended June 30, 1994 and December
31, 1993, respectively. On a MCF equivalent basis excluding
recoupment gas, production expenses and taxes were $.57 per Mcf
equivalent during the year ended June 30, 1995 compared to $.61 and
$.48, respectively, per Mcf equivalent for the six months ended
June 30, 1994 and year ended December 31, 1993.

Depreciation and Depletion Expense. Depreciation
and depletion expense for the year ended June 30, 1995 was $212,750
compared to $184,547 and $393,395, and $587,669, respectively, for
the six months ended June 30, 1994 and the year ended December 31,
1993. On a MCF equivalent basis the depletion rate was $.79 per
Mcf equivalent during year ended June 30, 1995 compared to $.70 and
$.73 per Mcf equivalent, respectively, for the six months ended
June 30,1994 and the year ended December 31, 1993.

Exploration Expenses. Exploration expenses consist
of geological and geophysical costs and lease rentals. There were
no exploration expenses for the year ended June 30, 1995 compared
to $4,088 and $7,352, respectively, for the six months ended June
30, 1994 and year ended December 31, 1993. Exploration expenses in
1995, 1994 and 1993 decreased primarily as a result of decreased
exploration activity in Oklahoma.

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
compared to $21,491 and $8,252, respectively, for the six months
ended June 30, 1994 and year ended December 31, 1993. In 1995 the
write down of the Company's producing oil and gas properties was
primarily due to the depressed natural gas prices at June 30, 1995.
In 1994 and 1993 the write downs, primarily relate to the
abandonment or impairment of undeveloped properties.

General and Administrative Expenses. General and
administrative expense for the year ended June 30, 1995 were
$696,352 compared to $165,986 and $316,705, respectively, for the
six months ended June 30, 1994 and year ended December 31, 1993.
General and administrative expenses increased from 1993 to 1994 and
in 1995 as the Company's level of activity increased following the
reorganization of Delta.

Interest on Recoupment Gas Obligation Expense.
Imputed interest expense on the recoupment gas obligation was
$113,285 for the year ended June 30, 1995 and $99,603 and $443,676,
respectively, for the six months ended June 30, 1994 and year ended
December 31, 1993.

Future Operations

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 the 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.

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 50, 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 listed on the American Stock
Exchange which presently owns in excess of 20% of the outstanding
equity securities of Delta. Mr. Larson submitted his resignation
from all positions with UFG effective March 31, 1993. Mr. Larson
serves as Chairman, CEO, Secretary, Treasurer and a Director of the
Company, which was a majority-owned subsidiary of UFG from August
1991 until October 1992, at which time it became a majority-owned
subsidiary of Delta. Mr. Larson serves as the Chairman, CEO,
Secretary, Treasurer and a Director of Delta. 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
submitted his resignation from all positions with UFG effective
March 31, 1993. Mr. Parker also serves as President, Chief
Operating Officer and a Director of both the Company and Delta. He
also serves as a Director and Executive Vice President of P & G
Exploration, Inc., a private oil and gas company (formerly Texco
Exploration, Inc.). Mr. Parker has also been the President 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 was a Director of Universal Exploration, Inc., from
1986 to 1989. He attended the University of Colorado where he
received a Bachelor of Science in Mineral Land Management in the
spring of 1983. He is a member of the Rocky Mountain Oil and Gas
Association and the National Federation of Independent Businesses.

Terry D. Enright, age 46, 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 year ended December 31, 1993, the six month
period ended June 30, 1994, the year ended June 30, 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
(3 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. 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 Company paid Delta $468,658 for the
year ended June 30, 1995. The Company had a payable to Delta of
$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 22 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 5/31/96

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

Date 5/31/96

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

Date 5/31/96

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, 1995, and 1994, and the related statements of operations and
accumulated deficit, and cash flows for the year ended June 30,
1995, the six months ended June 30, 1994, and the year ended
December 31, 1993. 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, 1995 and 1994, and the results of
its operations and its cash flows for the year ended June 30, 1995,
the six months ended June 30, 1994 and the year ended December 31,
1993 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.

KPMG Peat Marwick LLP

Denver, Colorado
October 10, 1995

AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)

BALANCE SHEET

June 30, June 30,
1995 1994

ASSETS

Current Assets:
Cash $3,751 4,064
Accounts receivable 104,047 59,494
Other current assets - 2,500

Total current assets 107,798 66,058

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 1,385,673 2,722,260
6,391,949 7,728,536

Less accumulated depreciation and depletion (608,817) (1,083,517)

Net oil and gas properties 5,783,132 6,645,019

$5,890,930 6,711,077

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities:
Accounts payable trade:
Trade $78,487 45,912
Affiliate (Note 4) 256,371 52,072
Royalties payable held in suspense 188,847 185,123
Recoupment gas royalties payable 669,841 643,841

Total current liabilities 1,193,546 926,948

Recoupment gas obligation - 967,911

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 (1,349,485) (1,230,651)

Total stockholders' equity 4,697,384 4,816,218

$5,890,930 6,711,077

STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>

Year Ended Six Months Year Ended
June 30, June 30, December 31,
1995 1994 1993
<S> <C> <C> <C>

Revenue:

Oil and gas sales, including recoupment
gas $167,009 in 1995 and $226,907 in 1994
and $609,750 in 1993 (Note 1) $730,776 368,304 1,077,905
Gain on sale of oil and gas properties 57,667 - -
Interest income 176 - 539

Total revenue 788,619 368,304 1,078,444

Expenses:

Lease operating expenses 200,384 141,772 275,861
Depletion 212,750 184,547 393,395
Exploration expenses - 4,088 7,352
Abandoned and impaired properties 178,532 21,491 8,252
General and administrative 696,352 165,986 316,705
Interest on recoupment gas obligation (Note 1) 113,285 99,603 443,676

Total expenses 1,401,303 617,487 1,445,241

Loss before extraordinary item (612,684) (249,183) (366,797)

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

Net Loss (118,834) (249,183) (366,797)

Accumulated deficit at begining of period (1,230,651) (981,468) (614,671)

Accumulated deficit at end of period ($1,349,485) (1,230,651) (981,468)

Loss per common share:
Loss before extraordinary item ($0.13) (0.05) (0.08)
Extraordinary gain on settlement of recoupment
gas obigation 0.10 - -
Net Loss ($0.03) (0.05) (0.08)

Weighted average number of common
shares outstanding 4,666,185 4,666,185 4,666,185
</TABLE>

STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>

Year Ended Six Months Year Ended
Ended June 30, Ended June 30, December 31,
1995 1994 1993

Cash flows from operating activities:
Net loss ($118,834) (249,183) (366,797)
Adjustments to reconcile net loss to cash
provided by (used in) operating activities:
Recoupment gas revenue (167,009) (226,907) (609,750)
Interest on recoupment gas obligation 113,285 99,603 443,676
Depletion 212,750 184,547 393,395
Gain on sale of oil and gas properties (57,667) - -
Abandoned and impaired properties 178,532 21,491 8,252
Extraordinary gain on settlement of
recoupment gas obligation (493,850) - -
Net changes in current assets and
and current liabilities:
(Increase) decrease in accounts
receivable (44,553) 77,991 (4,479)
Decrease (increase) in other current assets 2,500 - (2,500)
Increase (decrease) in accounts payable 32,575 (31,903) (75,732)
Increase in royalties payable held in suspense 3,724 14,103 27,987
Increase in recoupment gas royalties payable 26,000 55,484 139,453

Net cash used in operating activities (312,547) (54,774) (46,495)

Cash flows from investing activities:
Additions to property and equipment (29,094) - (11,247)
Proceeds from sale of oil and gas properties 137,029 - -

Net cash provided by (used in) investing activities 107,935 - (11,247)

Cash flows from financing activities:
Change in accounts payable to/receivable from
affiliate 204,299 54,222 62,358

Net cash provided by (used in) financing activities 204,299 54,222 62,358

Net (decrease) increase in cash (313) (552) 4,616

Cash at beginning of period 4,064 4,616 -

Cash at end of period $3,751 $4,064 4,616

Supplemental cashflow information:

Cash paid for interest - - -

</TABLE>

AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Year Ended June 30, 1995, Six Months Ended June 30, 1994
and Year Ended December 31, 1993 and 1992

(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, 1995,
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.

The Company adjusted the basis of its assets and liabilities
in 1991 to reflect the new basis of accounting resulting from the
acquisition of more than 80% of its common shares by UFG. The
Company's net assets were adjusted to reflect UFG's acquisition
(1) Summary of Significant Accounting Policies (continued)
cost of the shares of $5,406,408. The minority shareholders
interest in the Company was not reflected in this adjustment as
accumulated losses had exceeded their original investment at that
date. The subsequent acquisition of additional shares of the
Company by UFG in 1992 was accounted for as an increase in oil and
gas properties and an increase in additional paid-in capital of
$595,461, representing the estimated fair value of the UFG shares
issued in the exchange. The acquisition by Delta of additional
shares from Ogle was also accounted for in 1992 as an increase in
oil and gas properties and an increase in additional paid-in
capital of $45,000, representing Ogle's predecessor cost of the
shares of the Company. The additional shares acquired from Ogle by
Delta were accounted for at predecessor cost due to the related
party nature of the transaction.

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, 1995, the Company has a working capital deficiency
of $1,085,748. Included in the Company's current liabilities are
royalties payable held in suspense of $188,847 at June 30, 1995
which represent the Company's estimate of royalties payable on
production attributable the Company'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's current liabilities also include
royalties payable on recoupment gas produced on certain wells of
$669,841 at June 30, 1995. 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 believes that it is unlikely that all claims that
might be made for payment of royalties payable in suspense or for
recoupment 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 in suspense and
recoupment royalties payable.

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.

Through the period ended June 30, 1995, 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
(1) Summary of Significant Accounting Policies (continued)
unsuccessful exploratory wells are charged to expense as incurred.
Costs of drilling development wells, both successful and
unsuccessful, are capitalized.

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

Depreciation and depletion of capitalized acquisition,
exploration and development costs is computed on the
units-of-production method by individual fields as the related
proved reserves are produced. 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, 1995, the Company had produced approximately
112,000 Mcf more than its entitled share of production. The
undiscounted value of this imbalance is approximately $170,000
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.

Recoupment Gas Royalties Payable

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. Common stock options and
warrants have not been considered in the calculation of loss per
share as their effect is antidilutive.

(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, 1995 and 1994, the Company's significant deferred
tax assets and liabilities are summarized as follows:

1995 1994
Deferred tax assets:
Net operating loss
carryforwards $ 1,862,000 1,806,000
Recoupment gas obligation - 368,000

Gross deferred tax assets 1,862,000 2,174,000

Less valuation allowance (122,000) (365,000)

Net deferred tax assets 1,740,000 1,809,000

Deferred tax liabilities:
Oil and gas properties,
principally due to
differences in basis and
depreciation and depletion (1,740,000) (1,809,000)

Net deferred tax asset $ - -

No income tax benefit has been recorded for the year ended June
30, 1995, the six months ended June 30, 1994 or the year ended
December 31, 1993 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, 1995, the Company had net operating loss
carryforwards for regular and alternative minimum tax purposes of
approximately $4,900,000 and $4,500,000, respectively. If not
utilized, the tax net operating loss carryforwards will expire
during the period from 1997 through 2010.

(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.
The Company paid Delta $468,658 for the year ended June 30, 1995
$191,788 for the six months ended June 30, 1994 and $243,357 for
the year ended December 31, 1993. The Company had a payable to
Delta of $256,371 at June 30, 1995 and $52,072 at June 30, 1994.

During the year ended December 31, 1993, the Company sold to
Delta various non-producing leasehold interests which were assigned
to Delta in exchange for $20,000 and a 10% working interest, after
well payout.

(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,
1995 1994

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

Developed onshore
domestic properties 1,385,673 2,722,260
6,391,949 7,728,536
Accumulated depreciation
and depletion (608,817) (1,083,517)
$ 5,783,132 6,645,019

Costs incurred in oil and gas producing activities for the year
ended June 30, 1995, six months ended June 30, 1994 and year ended
December 31, 1993 are as follows:

1995 1994 1993

Exploration costs $ - 4,088 7,352

Development costs 29,094 - 11,247

Sales to major customers accounted for approximately 38%, 25%
and 17% of 1995 oil and gas sales. Sales to major customers
accounted for approximately 62%, 18%, and 11% of 1994 oil and gas
sales. Sales to major customers accounted for 57% 12% and 10% of
1993 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, net of
recoupment gas, for the year ended June 30, 1995, the six months ended
June 30, 1994 and year ended December 31, 1993 are as follows:

<TABLE>

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

Balance at January 1, 1993 3,988,611 12,839 12,975,847 10,592,365
Revisions of quantity estimates 411,759 8,506 - -
Sale of properties (408,032) (1,005) - -
Production (234,746) (1,940) - -
Balance at December 31, 1993 3,757,592 18,400 12,975,847 10,592,365

Revisions of quantity estimates (675,625) (322) - -
Production (84,276) (469) - -
Balance at June 30, 1994 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

Proved developed reserves:
December 31, 1992 3,580,579 11,834 - -
December 31, 1993 3,757,592 18,400 - -
June 30, 1994 2,997,691 17,609 - -
June 30, 1995 1,912,996 5,143

</TABLE>

Future net cash flows presented below are computed using year-end prices
and costs and exclude amounts attributable to recoupment gas.
Future corporate overhead expenses and interest expense have not been
included.
<TABLE>
<CAPTION>

Offshore
Onshore California Total

December 31, 1993:

Future cash inflows $7,637,089 118,736,564 126,373,653
Future costs:
Production 2,510,610 18,611,457 21,122,067
Development 77,198 22,948,450 23,025,648
Income taxes - 26,240,063 26,240,063

Future net cash flows 5,049,281 50,936,594 55,985,875

10% discount factor 2,668,854 42,056,470 44,725,324

Standardized measure of discounted future
net cash flows $2,380,427 8,880,124 11,260,551

June 30, 1994:

Future cash inflows $5,073,304 118,736,564 123,809,868
Future costs:
Production 2,004,387 18,611,457 20,615,844
Development - 22,948,450 22,948,450
Income taxes - 23,486,944 23,486,944

Future net cash flows 3,068,917 53,689,713 56,758,630

10% discount factor 1,483,544 46,361,790 47,845,334

Standardized measure of discounted future
net cash flows $1,585,373 7,327,923 8,913,296

June 30, 1995:

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

</TABLE>

The principal sources of changes in the standardized measure of discounted
net cash flows during the year ended June 30, 1995,
six months ended June 30, 1994 and year ended December 31, 1993
are as follows:
<TABLE>
<CAPTION>

Year Ended Six Months Year Ended
June 30, Ended June 30, December 31,
1995 1994 1993

Beginning of year $8,913,296 11,260,551 14,626,769

Sales of oil and gas produced during the
period , net of production costs (530,392) 375 (192,294)
Net change in prices and production costs 47,972 (755,956) (6,483,906)
Changes in estimated future development costs (5,344) (170,601) (41,593)
Revisions of previous quantity estimates and
other (1,437,620) (2,522,336) 50,732
Net change in income taxes 372,798 538,235 1,949,178
Sales of reserves in place (62,412) - (111,012)
Accretion of discount 891,330 563,028 1,462,677

End of year $8,189,628 8,913,296 11,260,551

</TABLE>

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> 12-MOS
<FISCAL-YEAR-END> JUN-30-1995
<PERIOD-END> JUN-30-1995
<CASH> 3,751
<SECURITIES> 0
<RECEIVABLES> 104,047
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 107,798
<PP&E> 6,391,949
<DEPRECIATION> 608,817
<TOTAL-ASSETS> 5,890,930
<CURRENT-LIABILITIES> 1,193,546
<BONDS> 0
0
0
<COMMON> 291,637
<OTHER-SE> 4,405,747
<TOTAL-LIABILITY-AND-EQUITY> 5,890,930
<SALES> 730,776
<TOTAL-REVENUES> 788,619
<CGS> 0
<TOTAL-COSTS> 1,401,303
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> (612,684)
<INCOME-TAX> 0
<INCOME-CONTINUING> (612,684)
<DISCONTINUED> 0
<EXTRAORDINARY> 493,850
<CHANGES> 0
<NET-INCOME> (118,834)
<EPS-PRIMARY> (.03)
<EPS-DILUTED> (.03)

</TABLE>