AMBER RESOURCES CO, 10KSB40, 1998-10-09

AMBER RESOURCES CO
10KSB40, 1998-10-09
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, 1998

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

Commission File No. 0-8874

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

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

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

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

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

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

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

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

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

The issuer's revenue for the fiscal year ended June 30, 1998
totaled $1,173,329.

The aggregate market value as of the Company's voting stock held
by non-affiliates of the Company as of September 23, 1998 could
not be determined because there is no established public trading
market.

As of September 23, 1998, 4,666,185 shares of registrant's Common
Stock $.0625 par value were issued and outstanding.

The Index to Exhibits appears at Page 25.

TABLE OF CONTENTS

PART I

PAGE

ITEM 1. DESCRIPTION OF BUSINESS 1
ITEM 2. DESCRIPTION OF PROPERTY 3
ITEM 3. LEGAL PROCEEDINGS 14
ITEM 4. SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS 14

PART II

ITEM 5. MARKET FOR COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS 15
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS
OR PLAN OF OPERATION 15
ITEM 7. FINANCIAL STATEMENTS 19
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 19

PART III

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE
EXCHANGE ACT 19
ITEM 10. EXECUTIVE COMPENSATION 21
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT 22
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS 23
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K 23

PART I

ITEM 1. DESCRIPTION OF BUSINESS

(a) Business Development

Amber Resources Company ("Amber" or "the Company") is
engaged in the exploration, development and production of oil and
gas properties. The Company's business is conducted onshore in
the continental United States and in the coastal waters of
California. As of June 30, 1998, 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 37 producing wells in western
Oklahoma (the "Oklahoma Properties"). At June 30, 1998, the
Company estimated its proved undeveloped reserves attributable to
its offshore California properties to be approximately 12.86 Bcf
of gas and 9.68 million Bbls of oil and proved producing reserves
attributable to its onshore properties to be approximately 1.47
Bcf of gas and 2,400 Bbls of oil. There are uncertainties as to
the timing of the development of the offshore properties. (See
"Description of Properties"; Item 2 herein.)

The Company, a Delaware corporation, was established
January 17, 1978. The Company's offices are located at Suite
3310, 555 17th Street, Denver, Colorado 80202. As of June 30,
1998, Delta Petroleum Corporation ("Delta") owned 4,277,977
shares (91.68%) of the Company's outstanding common stock. The
Company is managed by Delta under a management agreement
effective March 31, 1993 which provides for the sharing of the
management between the two companies and allocation of expenses
related thereto.

At June 30, 1998, Amber had an authorized capital of
5,000,000 shares of $1.00 par value preferred stock of which no
shares were issued and 25,000,000 shares of $0.0625 common stock
of which 4,666,185 shares were issued and outstanding.

(b) Business of Issuer.

During the year ended June 30, 1998, Amber was engaged
in only one industry, namely the acquisition, exploration,
development, and production of oil and gas properties and related
business activities. The Company's oil and gas operations have
been comprised primarily of production of oil and gas. The
Company currently has producing oil and gas interests in the
Anadarko Basin in Oklahoma and interests in proven but
undeveloped offshore Federal leases and units near Santa Barbara,
California.

(1) Principal Products or Services and Their Markets.
The principal products produced by the Company are crude oil and
natural gas. The products are generally sold at the wellhead to
purchasers in the immediate area where the product is produced.
The principal markets for oil and gas are refineries and
transmission companies which have facilities near the Company's
producing properties.

(2) Distribution Methods of the Products or Services.
Oil and natural gas produced from the Company's wells are
normally sold to the purchasers referenced in (6) below. Oil is
picked up and transported by the purchaser from the wellhead. In
some instances the Company is charged a fee for the cost of
transporting the oil, which fee is deducted from or calculated
into the price paid for the oil. Natural gas wells are connected
to pipelines owned by the natural gas purchasers. A variety of
pipeline transportation charges are usually included in the
calculation of the price paid for the natural gas.

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

(4) Competitive Business Conditions. Oil and gas
exploration and acquisition of undeveloped properties is a highly
competitive and speculative business. The Company competes with
a number of other companies, including major oil companies and
other independent operators which are more experienced and which
have greater financial resources. The Company does not hold a
significant competitive position in the oil and gas industry.

(5) Sources and Availability of Raw Materials and
Names of Principal Suppliers. Oil and gas may be considered raw
materials essential to the Company's business. The acquisition,
exploration, development, production, and sale of oil and gas are
subject to many factors which are outside of the Company's
control. These factors include national and international
economic conditions, availability of drilling rigs, casing, pipe,
and other equipment and supplies, proximity to pipelines, the
supply and price of other fuels, and the regulation of prices,
production, transportation, and marketing by the Department of
Energy and other federal and state governmental authorities.

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

(7) Patents, Trademarks, Licenses, Franchises,
Concessions, Royalty Agreements and Labor Contracts. The Company
does not own any patents, trademarks, licenses, franchises,
concessions, or royalty agreements except oil and gas interests
acquired from industry participants, private landowners and state
and federal governments. The Company is not a party to any labor
contracts.

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

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

(10) Research and Development. The Company does not
engage in any research and development activities. Since its
inception, the Company has not had any customer or government-
sponsored material research activities relating to the
development of any new products, services or techniques, or the
improvement of existing products.

(11) Environmental Protection. Because the Company is
engaged in acquiring, operating, exploring for and developing
natural resources, it is subject to various state and local
provisions regarding environmental and ecological matters.
Therefore, compliance with environmental laws may necessitate
significant capital outlays, may materially affect the Company's
earnings potential, and could cause material change in the
Company's proposed business. At the present time, however, the
existence of environmental law does not materially hinder nor
adversely affect the Company's business. Capital expenditures
relating to environmental control facilities have not been
material to the Company since its inception. In addition, the
Company does not anticipate that such expenditures will be
material during the fiscal year ending June 30, 1999.

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

ITEM 2. DESCRIPTION OF PROPERTIES

(a) Office Facilities:

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

(b) Oil and Gas Properties

The Company owns interests in oil and gas properties
located offshore California and in Oklahoma. 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, 1998 and 1997.

Offshore Federal Waters: Santa Barbara, California Area

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

The Santa Barbara Channel and the offshore Santa Maria
Basin are the seaward portions of geologically well-known onshore
basins with over 90 years of production history. These offshore
areas were first explored in the Santa Barbara Channel along the
near shore three mile strip controlled by the state. New field
discoveries in Pliocene and Miocene age reservoir sands led to
exploration into the federally controlled waters of the Pacific
Outer Continental Shelf ("POCS"). Eight POCS lease sales and
subsequent drilling conducted between 1966 and 1984 have resulted
in the discovery of an estimated two billion Bbls of oil and
three trillion cubic feet of gas. Of these totals, some 814
million Bbls of oil and 756 billion cubic feet of gas have been
produced and sold. Currently, POCS production is approximately
160,000 Bbls of oil and 200 million cubic feet of gas per day
according to the Minerals Management Service of the Department of
the Interior ("MMS").

Most of the early offshore production was from Pliocene
age sandstone reservoirs. The more recent developments are from
the highly fractured zones of the Miocene age Monterey Formation.
The Monterey is productive in both the Santa Barbara Channel and
the offshore Santa Maria Basin. It is the principal producing
horizon in the Point Arguello field, the Point Pedernales field,
and the Hondo and Pescado fields in the Santa Ynez Unit. Because
the Monterey is capable of relatively high productive rates, the
Hondo field, which has been on production since late 1981, has
already surpassed 150 million Bbls of production.

California's active tectonic history over the last few
million years has formed the large linear anticlinal features
which trap the oil and gas. Marine seismic surveys have been
used to locate and define these structures offshore. Recent
seismic surveying utilizing modern 3-D seismic technology,
coupled with exploratory well data, has greatly improved
knowledge of the size of reserves in fields under development and
in fields for which development is planned. Currently, 10 fields
are producing from 18 platforms in the Santa Barbara Channel and
offshore Santa Maria Basin. Implementation of extended
high-angle to horizontal drilling methods is reducing the number
of platforms and wells needed to develop reserves in the area.
Use of these new drilling methods and seismic technologies is
expected to continue to improve development economics.

Leasing, lease administration, development and
production within the Federal POCS all fall under the Code of
Federal Regulations administered by the MMS. The EPA controls
disposal of effluents, such as drilling fluids and produced
waters. Other Federal agencies, including the Coast Guard and
the Army Corps of Engineers, also have oversight on offshore
construction and operations.

The first three miles seaward of the coastline are
administered by each state and are known as "State Tidelands" in
California. Within the State Tidelands off Santa Barbara County,
the State of California, through the State Lands Commission,
regulates oil and gas leases and the installation of permanent
and temporary producing facilities. Because the three units in
which the Company owns interests are located in the POCS seaward
of the three mile limit, leasing, drilling, and development of
these units are not directly regulated by the State of
California. However, to the extent that the production will be
transported to an on-shore facility through the state waters, the
Company's pipelines (or other transportation facilities) will be
subject to California state regulations. Construction and
operation of the pipelines will require permits from the state.
Additionally, all development plans must be consistent with the
Federal Coastal Zone Management Act ("CZM"). In California the
decision of CZM consistency is made by the California Coastal
Commission.

The Santa Barbara County Energy Division and the Board
of Supervisors will have a significant impact on the method and
timing of any offshore field development through its permitting
and regulatory authority over the construction and operation of
on-shore facilities. In addition, the Santa Barbara County Air
Pollution Control District has authority in the federal waters
off Santa Barbara County through the Federal Clean Air Act as
amended in 1990.

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 substantial. The estimated cost, which will be
incurred over the life of the properties (assumed to be 38
years), for the complete development of all of the properties in
which Amber owns an interest, including delineation wells,
environmental mitigation, development wells, fixed platforms,
fixed platform facilities, pipelines and power cables, onshore
facilities and platform removal is currently estimated to be
slightly in excess of approximately $3 billion. The Company's
share of such costs is estimated to be approximately $26,938,000.
Operating expenses for the same properties over the same period
of time, including platform operating costs, well maintenance and
repair costs, oil, gas and water treating costs, lifting costs
and pipeline transportation costs are expected to be
approximately $2,286,486,000 with the Company's share estimated
to be $36,354,000.

Each working interest owner will be required to pay its
proportionate share of these costs based upon the amount of the
interest that it owns. The size of Amber's working interest
varies from .87% to 6.97%. The Company may be required to farm
out all or a portion of its interests in these properties to a
third party 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. Net revenues over the
same time period, to be shared by all of the working interest
owners in proportion to the size of their respective working
interests, are estimated to be approximately $2,216,067,000 after
the payment of all of the above expenses and amounts due to
owners of royalty interests with Amber's share estimated to be
approximately $35,833,000 before taxes.

These units have been formally approved and are
regulated by the MMS. However, due to a history of opposition to
offshore drilling and production in California by some
individuals and groups, the process of obtaining all of the
necessary permits and authorizations to develop the properties
will be lengthy. While the Federal Government has recently
attempted to expedite this process, there can be no assurance
that it will be successful in doing so. The Company does not
have a controlling interest in and does not act as the operator
of any of the offshore California properties and consequently
will not control the timing of either the development of the
properties or the expenditures for development. Management and
its independent engineering consultant have considered these
factors relating to timing of the development of the reserves in
the preparation of the reserve information relating to these
properties. It is anticipated that, based upon discussion with
appropriate governmental agencies, development of
the subject leases will require from three to five years for
permitting. Because of the substantial reserves contained in the
projects, it is generally accepted that they will be developed;
however, the time required to complete development may be from
five to ten years. As additional information becomes available
in the future, the Company's estimates of the proved undeveloped
reserves attributable to these properties could materially
change.

The MMS initiated the California Offshore Oil and Gas
Energy Resources (COOGER) study at the request of the local
regulatory agencies of the three counties (Ventura, Santa Barbara
and San Luis Obispo) affected by offshore oil and gas
development. A private consulting firm is currently conducting
the study under a contract with the MMS. The COOGER study seeks
to present a long-term regional perspective of potential onshore
constraints that should be considered when developing existing
undeveloped offshore leases. COOGER will project the
economically recoverable oil and gas production from offshore
leases which have not yet been developed. These projections will
be utilized to assist in identifying a potential range of
scenarios for developing these leases. These scenarios will then
be compared to the projected infrastructural, environmental and
socioeconomic baselines between 1995 and 2015.

No specific decisions regarding levels of offshore oil
and gas development or individual projects will occur in
connection with the COOGER study. Information presented in the
study is intended to be utilized as a reference document to
provide the public, decision makers and industry with a broad
overview of cumulative industry activities and key issues
associated with a range of development scenarios. The exact
effects of each of the scenarios are not yet capable of analysis
because the study has not yet been completed. However, the
Company has evaluated its position with regard to the scenarios
currently being studied with respect to properties located in the
eastern and central subregions (which include the Sword Unit and
the Gato Canyon Unit) and the results of such evaluation are set
forth below:

Scenario 1 No new development of existing
offshore leases. If this scenario were ultimately
to be adopted by governmental decisionmakers and
the industry as the proper course of action for
development, Amber's offshore California
properties would in all likelihood have little
or no value.

Scenario 2 Development of existing leases,
using existing onshore facilities as currently
permitted, constructed and operated (whichever is
less) without additional capacity. This scenario
includes modifications to allow processing and
transportation of oil and natural gas with
different qualities. Although the exact effects
upon offshore development are not yet capable of
analysis because the study has not yet been
completed, it is likely that the adoption of this
scenario by governmental decisionmakers and the
industry as the proper course of action for
development would result in lower than anticipated
costs, but would cause the subject properties to
be developed over a significantly extended period of
time.

Scenario 3 Development of existing leases,
using existing onshore facilities by constructing
additional capacity at existing sites to handle
expanded production. Although the details of this
scenario are not yet available because the study
has not been completed, it would appear that this
is approximately the same scenario that is
anticipated by the Company's reserve report.

Scenario 4 Development of existing leases
after decommissioning and removal of some or all
existing onshore facilities. This scenario includes
new facilities, and perhaps new sites, to handle
anticipated potential future production. There is
currently insufficient information available to
assess the impact of this scenario on Amber, but
it would appear likely that Amber would incur
increased costs and that revenues would be
received more quickly.

The Company has also evaluated its position with
regard to the scenarios currently being studied with respect
to properties located in the northern subregion (which
includes the Lion Rock Unit), the results of which are as
follows:

Scenario 4 Development of existing offshore
leases, using existing onshore facilities with
additional capacity or adding new facilities to
handle a relatively low rate of expanded
development. This scenario allows for a new
site(s). There is currently insufficient
information available to assess the impact of this
scenario on Amber.

Scenario 5 Development of existing offshore
leases, using existing onshore facilities with
additional capacity or adding new facilities to
handle a relatively higher rate of expanded
development. This scenario allows for a new
site(s). There is currently insufficient
information available to assess the impact of this
scenario on Amber, but it would appear likely that
Amber would incur increased costs and that
revenues would be received more quickly.

The Company's development plan currently provides for
22 wells from one platform set in a water depth of approximately
328 feet for the Gato Canyon Unit; 63 wells from one platform set
in a water depth of approximately 1,300 feet for the Sword Unit;
and 183 wells from two platforms for the Lion Rock Unit. On the
Lion Rock Unit, platform A will be set in a water depth of
approximately 507 feet, and Platform B will be set in a water
depth of approximately 484 feet. The reach of the deviated wells
from each platform required to drain in each unit was found to
fall within the reach limits now considered to be
"state-of-the-art."

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

The MMS issued a second letter on December 24, 1996
with the intent to notify all lease owners of the course of
action to be followed by the lease and unit operators prior to
the expiration of the SOO. In another letter, on September 17,
1998, the MMS informed all owners and operators that due to
delays in the COOGER Study the SOO's on all the units would be
extended through the first quarter of 1999 and revised the dates
for actions required by the previous letters. During 1998 each
operator is to meet with the MMS to discuss conceptual plans that
will lead to eventual development. By January 15, 1999, each
operator will submit what the MMS has termed a Schedule of Events
for a specific lease or unit that it operates and also a request
for a Suspension of Production time period to execute the
Schedule of Events. The lease and unit Schedule of Events, when
approved by the MMS, will go into effect on April 1, 1999.

In order to carry out the requirements of the December
24, 1996 and September 17, 1998 MMS letters, all operators of the
units in which the Company owns non-operating interests
(described below) are currently engaged in studies to develop a
conceptual framework and general timetable for continued
delineation and development of the leases. For delineation, the
operators will outline the mobile drilling unit well activities,
including number and location. For development, the operators'
reports will cover the total number of facilities involved,
including platforms, pipelines, onshore processing facilities,
transportation systems and marketing plans. The Company is
participating with the operators in meeting the MMS schedules
through meetings, and consultations and is sharing in the costs
as invoiced by the operators.

Based on prices of $9.11 per Bbl and $1.41 per Mcf and
applicable regulatory parameters, the Company's aggregate working
interests in these properties had a pre-tax present value
(discounted at 10%) of approximately $1,601,000 as of July 1,
1998 according to a reserve report issued by Forrest A. Garb &
Associates ("Garb"), an independent petroleum engineering firm of
Dallas, Texas. According to Garb's report, Delta's Offshore
California reserves from these units totalled approximately 9.68
million Bbls of oil and 12.86 Bcf of gas for an aggregate
equivalent of 11.82 BOE.

Gato Canyon Unit. The Company holds a 6.97% working
interest (directly 8.63% and through Amber 6.97%) in the Gato
Canyon Unit. This 10,100 acre unit is operated by Samedan Oil
Corporation. Seven test wells have been drilled on the Gato
Canyon Unit structure. Five of these were drilled within the
boundaries of the Unit and two were drilled outside the Unit
boundaries in the adjacent State Tidelands. The test wells were
drilled as follows: within the boundaries of the Unit; three
wells were drilled by Exxon, two in 1968 and one in 1969; one
well was drilled by Arco in 1985; and, one well was drilled by
Samedan in 1989. Outside the boundaries of the Unit, in the
State Tidelands but still on the Gato Canyon Structure, one well
was drilled by Mobil in 1966 and one well was drilled by Union
Oil in 1967. In April 1989, Samedan announced the completion and
test of the Samedan P-0460 #2 which yielded a test flow rate of
5,500 Bbls of oil per day from the Monterey Formation between
5,000 and 6,800 feet of drill depth. The
Monterey Formation is a highly fractured shale formation. The
Monterey (which ranges from 500' to 2,900' in thickness) is the
main productive and target zone in many offshore California oil
fields (including the Company's federal leases and/or units). As
of July 1, 1998, Forrest A. Garb & Associates, Inc. ("Garb"), an
independent petroleum engineering firm based in Dallas, Texas,
issued a report stating that Gato Canyon contains proved
recoverable reserves estimated to be 119.8 million Bbls of oil
and 16.78 Bcf of natural gas, representing 6.96 million Bbls of
oil and 9.75 Bcf of natural gas net to the Company's 6.97%
working interest at July 1, 1998. The oil has an estimated
average gravity of 16 degrees API. (See Item 7. Financial Statements:
Footnote 6, "Information Regarding Proved Oil and Gas Reserves".)

The Gato Canyon field is located in the Santa Barbara
Channel approximately three to five miles offshore (see Map).
Water depths range from 280 feet to 600 feet in the area of the
field. Oil and gas produced from the field will be processed
onshore at the existing Las Flores Canyon facility (see Map).
Prior to construction Las Flores Canyon was designated a
"consolidated site" by Santa Barbara County and is available for
use by offshore operators. The processed oil is expected to be
transported out of Santa Barbara County in the All American
Pipeline (see Map). Offshore pipeline distances to access the
Las Flores site is approximately six miles. Amber's share of
estimated capital costs to develop the Gato Canyon field are
approximately $20,174,000.

The Gato Canyon Unit leases are currently held under a
Suspension of Operations until March 31, 1999. Thereafter, the
Unit operator will carry out a Schedule of Events under a
Suspension of Production. The Schedule of Events will include
the preparation of an updated Exploration Plan, which will
ultimately lead to the drilling of one additional delineation
well. This well will be used to determine the final location of
the development platform. Following the platform decision a
Development Plan will be prepared for submittal to the MMS and
the other involved agencies. Two to three years will likely be
required to process the Development Plan and receive the
necessary approvals.

Lion Rock Unit. The Company holds a 1% net profits
interest in the Lion Rock Unit. The Lion Rock Unit is operated
by Aera Energy LLC. An aggregate of seven test wells have been
drilled on the Lion Rock Unit. Four of these wells were
completed and tested and indicated the presence of oil and gas in
the Monterey Formation. One test well was drilled by Socal (now
Chevron) in 1965 and six wells were drilled by Phillips
Petroleum, one in 1982, two in 1983, two in 1984 and one in 1985.
Based on a report prepared by Garb as of July 1, 1998, the Lion
Rock Unit contains proved undeveloped recoverable reserves of
516.2 million Bbls of oil and 464.5 Bcf of natural gas,
equivalent to 1.56 million Bbls of oil and 1.74 Bcf of natural
gas net to the Company's interest at July 1, 1998. The oil has
an average estimated gravity of 10.7 degrees API. (See Item 7. Financial
Statements: Footnote 6, "Information Regarding Proved Oil and Gas
Reserves".)

The Lion Rock Unit is located in the Offshore Santa
Maria Basin eight to ten miles from the coastline (see Map).
Water depths range from 300 feet to 600 feet in the area of the
field. The oil and gas produced at Lion Rock will be processed
at a new facility in the onshore Santa Maria Basin or at the
existing Lompoc facility (see Map). The oil will be transported
out of Santa Barbara County in the All American Pipeline or the
Tosco-Unocap Pipeline (see Map). Offshore pipeline distance will
be eight to ten miles depending on the point of landfill.

The Lion Rock Unit is currently held under a Suspension
of Operations until March 31, 1999. Thereafter, the Unit
operator will carry out a Schedule of Events under a Suspension
of Production. The Schedule of Events will include
interpretation of the 3D seismic survey and the preparation of an
updated Plan of Development leading to production. Additional
delineation wells may or may not be drilled depending on the
outcome of the interpretation of the 3D survey.

Sword Unit. 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 were completed and tested in the Monterey
formation with calculated flow rates of from 4,000 to 5,000 Bbls
per day with an estimated average gravity of 10.6 degrees API. The two
completed test wells were drilled by Conoco, one in 1982 and the
second in 1985. Based on a July 1, 1998 report prepared by Garb,
the Sword Unit contains proved undeveloped recoverable reserves
of 158.1 million Bbls of oil and 189.8 Bcf of natural gas
representing reserves of 1.15 million Bbls of oil and 1.38 Bcf of
natural gas net to the Company's interest at July 1, 1998. (See
Item 7. Financial Statements: Footnote 6, "Information Regarding
Proved Oil and Gas Reserves".)

The Sword field is located in the western Santa Barbara
Channel ten miles west of Point Conception and five miles south
of Point Arguello's field Platform Hermosa (see Map). Water
depths range from 1000 feet to 1800 feet in the area of the
field. The oil and gas produced from the Sword Field will likely
be processed at the existing Gaviota consolidated facility and
the oil transported out of Santa Barbara County in the All
American Pipeline (see Map). Access to the Gaviota plant is
through Platform Hermosa and the existing Point Arguello Pipeline
system. A pipeline laid from a platform located in the northern
area of the Sword field to Platform Hermosa will be approximately
five miles in length. Amber's share of the estimated capital
costs to develop the Sword field is approximately $6,764,000.

The Sword Unit leases are currently held under a
Suspension of Operations until March 31, 1999. Thereafter, the
Unit operator will carry out a Schedule of Events under a
Suspension of Production. Included in the Schedule of Events
will be preparation of an updated Exploration Plan leading to the
drilling of an additional delineation well.

MAP

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

Oklahoma.

The Company owns non-operated working interests in 37
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. 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.

The Company is not obligated to provide a fixed and
determined quantity of oil and gas in the future under existing
contracts or agreements. During the last three fiscal years the
Company has not had, nor does it now have, any long-term supply
or similar agreements with governments or authorities pursuant to
which the Company acted as producer. The following table sets
forth the Company's net production of oil and gas, average sales
prices and average production costs during the periods indicated.

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

Year Ended Year Ended Year Ended
June 30, 1998 June 30, 1997 June 30, 1996

Average sales price:

Oil (per barrel) $17.31 21.19 20.85
Natural Gas (per Mcf) $2.34 2.28 1.73

Production costs (per
Mcf equivalent) $.57 .50 .65

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 Plan of Operation" )

(d) Productive Wells and Acreage.

The table below shows, as of June 30, 1998, 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 Gas Developed Acres
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)

Oklahoma 0 0 37 2.22 5,920 390

(1) A "gross well" or "gross acre" is a well or acre in
which a working interest is held. The number of gross wells or
acres is the total number of wells or acres in which a
working interest is owned.

(2) A "net well" or "net acre" is deemed to exist when the
sum of fractional ownership interests in gross wells or
acres equals one. The number of net wells or net acres
is the sum of the fractional working interests owned in
gross wells or gross acres expressed as whole numbers and
fractions thereof.

(e) Undeveloped Acreage.

At June 30, 1998, 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, 1998 and 1997, 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,
1998.

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 1997
and 1998 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, 1998 was approximately 1,000.

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

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

Liquidity and Capital Resources.

At June 30, 1998, the Company had a working capital
deficit of $522,028 compared to a working capital deficit of
$953,060 at June 30, 1997. The Company's working capital deficit
is primarily a result of amounts payable to Delta and royalties
payable. The Company's account payable to affiliate has
decreased from June 30, 1997 as the Company's available cash flow
during the period exceeded the Company's proportionate share of
rent, secretarial and administrative, accounting and management
services paid by Delta and the Company sold certain oil and gas
properties, and proceeds were used to reduce the account payable
to Delta.

The Company's current liabilities include royalties
payable of $232,832 at June 30, 1998 which represent the
Company's estimate of royalties payable on production
attributable to it's interest in certain wells in Oklahoma. The
Company believes that the operators of the affected wells have
paid some of the royalties on behalf of the Company and have
withheld such amounts from revenues attributable to the Company's
interest in the wells. The Company has contacted the operators
of the wells in an attempt to determine what amounts the
operators have paid on behalf of the Company over the past five
years, which amounts would reduce the amounts owed by the
Company. The Company has been informed by its
legal counsel that the applicable statue of limitations period
for actions on written contracts arising in the state of Oklahoma
is five years. The statute of limitation has expired for royalty
owners to make a claim for a portion of the estimated royalties
that had previously been accrued. Accordingly, these amounts
have been written off and recorded as other income in 1998 and
1997.

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

The Company does not currently have a credit facility
with any bank and it has not determined the amount, if any, that
it could borrow against its existing properties. The Company
will continue to seek additional sources of both short-term and
long-term liquidity to fund its working capital deficit and its
capital requirements for development of its properties, including
establishing a credit facility, sale of equity or debt securities
and sale of non-strategic properties although there can be no
assurance that the company will be successful in its efforts.
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.

After evaluation of the considerations described above,
the Company believes that its existing cash balances, cash flow
from its existing producing properties, proceeds from the sale of
producing properties, and other sources of funds will be adequate
to fund its operating expenses and satisfy its other current
liabilities over the next year or longer.

Results of Operations

Net Income. The Company's net income for the years
ended June 30, 1998 and 1997 was $288,172 and $64,260,
respectively. The increase in net earnings can primarily be
attributed to a gain on the sale of oil properties of $283,993
during the year ended June 30, 1998.

Revenue. Total revenue for the year ended June 30,
1998 was $1,173,329 compared to $1,113,274 for the year ended
June 30, 1997. Oil and gas sales for the year ended June 30,
1998 was $702,161 compared to $936,929 for the year ended June
30, 1997. The decrease in oil and gas sales for the year ended
June 30, 1998 compared to the year ended June 30, 1997 resulted
from the sale of certain oil and gas wells during the year which
resulted in a gain of $283,993.

Production volumes and average prices received for the
years ended June 30, 1998 and 1997 are as follows:

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

Production:

Oil (barrels) 565 1,025
Gas (Mcf) 296,329 400,725

Average Price:

Oil (per barrel) $17.31 21.19
Gas (per Mcf) $ 2.34 2.28

Lease Operating Expenses. Lease operating expenses for
the year ended June 30, 1998 was $171,354 compared to $203,731
for the year ended June 30, 1997. On a MCF equivalent basis
production expenses and taxes were $.57 per Mcf equivalent during
the year ended June 30, 1998 compared to $.50 for the year ended
June 30, 1997. Lease operating expenses increased from 1997 to
1998 primarily as a result of certain workover costs expensed
during 1998.

Depletion Expense. Depletion expense for the year
ended June 30, 1998 was $90,108 compared to $120,071 for the year
ended June 30, 1997. On a MCF equivalent basis the depletion
rate was $.30 per Mcf equivalent during year ended June 30, 1998
compared to $.30 per Mcf equivalent for the year ended June 30,
1997.

Exploration Expenses. Exploration expenses consist of
geological and geophysical costs and lease rentals. The Company
incurred exploration costs of $20,464 and $3,330 for the years
ended June 30, 1998 and 1997, respectively.

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

General and Administrative Expenses. General and
administrative expense for the year ended June 30, 1998 was
$603,231 compared to $679,882 for the year ended June 30, 1997.
General and administrative expenses decreased from 1997 to 1998
primarily as a result of the reduction in salary expense of the
Company's parent, which is allocated to the Company.

Year 2000

The Company relies upon its parent to provide
accounting, management and secretarial services, including
various computer facilities. The Company's parent initiated the
process of preparing its computer system and applications for the
Year 2000 during fiscal 1997. The Company's parent is
identifying areas of potential concern and ensuring that timely
corrective actions are taken. The Company's parent is also
working with key suppliers, vendors and customers to ensure Year
2000 compliance. The ultimate outcome of the Year 2000 project
cannot be guaranteed; however, the Company believes that the
program under way will provide a smooth transition into the Year
2000 and reduces risk to a manageable level. The cost of
addressing the Year 2000 issue is not considered material to the
consolidated statements of operations or financial condition of
the Company.

Recent Accounting Standards and Pronouncements

Statement of Financial Accounting Standards 130
"Reporting Comprehensive Income" (SFAS 130), was issued by the
Financial Accounting Standards Board in June, 1997. SFAS 130
established standards for reporting and displaying comprehensive
income and its components in a full set of general purpose
financial statements. This statement is effective for fiscal
years beginning after December 15, 1997. The Company does not
expect the adoption of SFAS 130 will have a material effect on
the presentation of its financial statements.

Statement of Financial Accounting Standards 131
"Disclosures about segments of an enterprises and Related
Information" (SFAS 131), was issued by the Financial Accounting
Standards Board in June, 1997. SFAS 131 establishes standards
for reporting information about operating segments in annual and
interim financial statements. SFAS 131 also establishes
standards for related disclosures about products and services,
geographic areas and major customers. This statement is
effective for fiscal years beginning after December 15, 1997.
The Company does not expect the adoption of SFAS 130 will have a
material effect on the presentation of its financial statements.

Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities"
(SFAS 133), was issued in June 1998, by the Financial Accounting
Standards Board. SFAS 133 establishes new accounting and
reporting standards for derivative instruments and for hedging
activities. This statement required an entity to establish at
the inception of a hedge, the method it will use for assessing
the effectiveness of the hedging derivative and the measurement
approach for determining the ineffective aspect of the hedge.
Those methods must be consistent with the entity's approach to
managing risk. SFAS 133 is effective for all fiscal quarters of
fiscal years beginning after June 15, 1999. The Company has not
assessed the impact, if any, that SFAS 133 will have on its
consolidated financial statements.

ITEM 7. FINANCIAL STATEMENTS

Financial Statements are included beginning on Page
F-1.

ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE

Not applicable.

PART III

ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

(a) Executive Officers and Directors:

Information with respect to the executive officers and
directors of the Company is set forth below:

Aleron H. Larson, Jr. 53 Chairman of the Board, May 1987 to
Chief Executive Officer Present
Secretary, Treasurer,
and a Director

Roger A. Parker 36 President and May 1987 to
a Director Present

Terry D. Enright 49 Director November 1987 to
Present

Jerrie F. Eckelberger 54 Director September 1996
to Present

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

Aleron H. Larson, Jr., age 53, has operated as an
independent in the oil and gas industry individually and through
public and private ventures since 1978. From July of 1990
through March 31, 1993, Mr. Larson served as the Chairman,
Secretary, C.E.O. and a Director of Underwriters Financial Group,
Inc. ("UFG") (formerly Chippewa Resources Corporation), a public
company then listed on the American Stock Exchange which
presently owns approximately 16.67% of the outstanding equity
securities of Delta. Subsequent to a change of control, Mr.
Larson resigned from all positions with UFG effective March 31,
1993. Mr. Larson serves as Chairman, CEO, Secretary, Treasurer
and Director of Delta Petroleum Corporation, a public oil and gas
company which is the parent and majority owner of Amber. He has
also served, since 1983, as the President and Board Chairman of
Western Petroleum Corporation, a public Colorado oil and gas
Company which is now inactive. Mr. Larson practiced law in
Breckenridge, Colorado from 1971 until 1974. During this time he
was a member of a law firm, Larson & Batchellor, engaged
primarily in real estate law, land use litigation, land planning
and municipal law. In 1974, he formed Larson & Larson, P.C., and
was engaged primarily in areas of law relating to securities,
real estate, and oil and gas until 1978. Mr. Larson received a
Bachelor of Arts degree in Business Administration from the
University of Texas at El Paso in 1967 and a Juris Doctor degree
from the University of Colorado in 1970.

Roger A. Parker, age 36, served as the President, a
Director and Chief Operating Officer of Underwriters Financial
Group from July of 1990 through March 31, 1993. Mr. Parker
resigned from all positions with UFG effective March 31, 1993.
Mr. Parker also serves as President, Chief Operating Officer and
Director of Delta Petroleum Corporation, which is the parent and
majority owner of Amber. He also serves as a Director and
Executive Vice President of P & G Exploration, Inc., a private
oil and gas company (formerly Texco Exploration, Inc.). Mr.
Parker has also been the President and a Director of Apex
Operating Company, Inc. since its inception in 1987. He was at
various times, from 1982 to 1989, a Director, Executive Vice
President, President and Shareholder of Ampet, Inc. He received
a Bachelor of Science in Mineral Land Management from the
University of Colorado in 1983. He is a member of the Rocky
Mountain Oil and Gas Association and the Independent Producers
Association of the Mountain States (IPAMS).

Terry D. Enright, age 49, has been in the oil and
gas business since 1980. He serves as a Director of both the
Company and Delta. Mr. Enright was a reservoir engineer until
1981 when he became Operations Engineer and Manager for Tri-Ex
Oil & Gas. In 1983, Mr. Enright founded and is President and a
Director of Terrol Energy, a private, independent oil company
with wells and operations primarily in the Central Kansas Uplift
and D-J Basin. In 1989, he formed and became President and a
Director of a related company, Enright Gas & Oil, Inc. Since
then, he has been involved in the drilling of prospects for
Terrol Energy, Enright Gas & Oil, Inc., and for others in
Colorado, Montana and Kansas. He has also participated in
brokering and buying of oil and gas leases and has
been retained by others for engineering, operations, and general
oil and gas consulting work. Mr. Enright received a B.S. in
Mechanical Engineering with a minor in Business Administration
from Kansas State University in Manhattan, Kansas in 1972, and
did graduate work toward an MBA at Wichita State University in
1973. He is a member of the Society of Petroleum Engineers and a
past member of the American Petroleum Institute and the American
Society of Mechanical Engineers.

Jerrie F. Eckelberger, age 54, is an investor, real
estate developer and attorney who has practiced law in the State
of Colorado for 26 years. He serves as a Director of both the
Company and Delta. He graduated from Northwestern University
with a Bachelor of Arts degree in 1966 and received his Juris
Doctor degree in 1971 from the University Colorado School of Law.
From 1972 to 1975, Mr. Eckelberger was a staff attorney with the
eighteenth Judicial District Attorney's Office in Colorado .
After spending two years in the litigation department of a Denver
law firm, he founded Eckelberger & Associates of which he is
still the principal member. From 1982 to 1992 Mr. Eckelberger
was the senior partner of Eckelberger & Feldman, a law firm with
offices in Englewood, Colorado. Mr. Eckelberger previously
served as an officer, director and corporate counsel for
Roxborough Development Corporation. He is presently the
President and Chief Executive Officer of 1998, Ltd., a Colorado
corporation actively engaged in the development of real estate in
Colorado. He is the Managing Member of The Francis Companies,
LLC, a Colorado limited liability company, which actively invests
in real estate. Additionally, Mr. Eckelberger is the Managing
Member of the Woods at Pole Creek, LLC, a Colorado limited
liability company, specializing in real estate development.

There is no family relationship among any of the
Directors.

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

ITEM 10. EXECUTIVE COMPENSATION.

No officer or director received compensation
directly from the Company during the years ended June 30, 1998,
1997 and 1996. 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

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

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

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

ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

Effective March 31, 1993, the Company and Delta entered
into an agreement which provides for the sharing of management
between the two companies. Under this agreement the Company pays
Delta for its proportionate share of rent, secretarial and
administrative, accounting and management services of Delta
officers and employees. The charges to the Company for the
sharing of management by Delta were $570,000 for the year ended
June 30, 1998, and $661,055 for the year ended June 30, 1997.
The Company had a payable to Delta of $333,976 at June 30, 1998
and $635,139 at June 30, 1997.

PART IV

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits:

The Exhibits listed in the Index to Exhibits appearing
at page 25 are filed as part of this report.

(b) Reports on Form 8-K: None

SIGNATURE

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

(Registrant) AMBER RESOURCES COMPANY

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

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

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

Date 9/23/98

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

Date 9/23/98

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

Date 9/23/98

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

Date 9/23/98

INDEX TO EXHIBITS

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

(3) Articles of Incorporation and By-Laws' The Articles of
Incorporation (Certificate of Incorporation) and By-Laws of
the Registrant filed as Exhibits 4 and 5 to Registrant's
Form S-1 Registration Statement filed August 28, 1978 with
the Securities and Exchange Commission are incorporated
herein by reference. The Restated Articles of Incorporation
(Restated Certificate of Incorporation) dated January 26,
1988 and Amendment to Restated Certificate of Incorporation
dated September 18, 1989 are attached hereto as Exhibits 3.1
and 3.2, respectively.

(4) Instruments Defining the Rights of Security Holders.

4.1 Certificate of Designation of the Relative Rights of
the Class A Preferred Stock of Amber Resources Company dated
July 25, 1989. Incorporated by reference to Exhibit 4.1
of the Company's Form 10-KSB for the fiscal year ended
June 30, 1997.

(9) Voting Trust Agreement. Not applicable.

(10) Material Contracts.

10.1 Agreement dated March 31, 1993 between Delta Petroleum
Corporation and Amber Resources Company. Incorporated by
reference from Exhibit 10.1 of the Company's Form 10-KSB for the
fiscal year ended June 30, 1997.

10.2 Amber Resources Company 1996 Incentive Plan.
Incorporated by reference from Exhibit 99.1 of the Company's
December 4, 1996 Form 8-K.

(11) Statement Regarding Computation of Per Share Earnings. Not
applicable.

(12) Statement Regarding Computation of Ratios. Not applicable.

(13) Annual Report to Security Holders, Form 10-Q or Quarterly
Report to Security Holders. Not applicable.

(16) Letter re: Change in Certifying Accountants. Not applicable.

(17) Letter re: Director Resignation. Not applicable.

(18) Letter Regarding Change in Accounting Principals. Not
applicable.

(19) Previously Unfiled Documents. Not applicable.

(21) Subsidiaries of the Registrant. Not applicable.

(22) Published Report Regarding Matters Submitted to Vote of
Security Holders. Not applicable.

(23) Consent of Experts and Counsel. Not applicable.

(24) Power of Attorney. Not applicable.

(27) Financial Data Schedule. Filed herewith electronically.

(99) Additional Exhibits. Not applicable.

Independent Auditors Report

The Board of Directors and Stockholders
Amber Resources Company:

We have audited the accompanying balance sheets of Amber Resources
Company (the "Company"), a subsidiary of Delta Petroleum
Corporation, as of June 30, 1998 and 1997 and the related
statements of operations and accumulated deficit, and cash flows
for the years then ended. These financial statements are the
responsibility of the Company s management. Our responsibility is
to express an opinion on these financial statements based on our
audits.

We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.

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

s/KPMG Peat Marwick LLP
KPMG Peat Marwick LLP

Denver, Colorado
September 18, 1998

AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)
BALANCE SHEET
June 30, 1998 and 1997

1998 1997

ASSETS

Current Assets:
Cash $14,661 6,440
Accounts receivable 71,178 111,728

Total current assets 85,839 118,168

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 1,264,134 1,405,645
6,270,410 6,411,921

Less accumulated depreciation and depletion (848,104) (846,755)

Net oil and gas properties 5,422,306 5,565,166

$5,508,145 5,683,334

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities:
Accounts payable:
Trade $41,059 16,281
Parent (Note 4) 333,976 635,139
Royalties payable 232,832 419,808

Total current liabilities 607,867 1,071,228

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 (1,146,591) (1,434,763)

Total stockholders' equity 4,900,278 4,612,106

$5,508,145 5,683,334

AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)
STATEMENTS OF OPERATIONS
Years Ended June 30, 1998 and 1997

1998 1997

Revenue:
Oil and gas sales $702,161 936,929
Gain on sale of oil and gas properties 283,993 -
Other income 187,175 176,345

Total revenue 1,173,329 1,113,274

Expenses:
Lease operating expenses 171,354 203,731
Depletion 90,108 120,071
Exploration expenses 20,464 3,330
Abandoned and impaired properties - 42,000
General and administrative, including $570,000
and $661,055 to parent (Note 4) 603,231 679,882

Total expenses 885,157 1,049,014

Net income 288,172 64,260

Accumulated deficit at begining of year (1,434,763) (1,499,023)

Accumulated deficit at end of year ($1,146,591) (1,434,763)

Basic earnings per common share $0.06 0.01

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

AMBER RESOURCES COMPANY
(A Subsidiary of Delta Petroleum Corporation)
STATEMENTS OF CASH FLOWS
Years Ended June 30, 1998 and 1997

1998 1997

Cash flows from operating activities:
Net income $288,172 64,260
Adjustments to reconcile net income to cash
provided by (used in) operating activities:
Gain on sale of oil and gas properties (283,993) -
Write-off of royalties payable (186,976) (176,148)
Depletion 90,108 120,071
Abandoned and impaired properties - 42,000
Net changes in current assets and
and current liabilities:
Decrease in accounts receivable 40,550 2,832
Decrease in other current assets - 2,000
Increase in accounts payable 24,778 8,056

Net cash provided by (used in)
operating activities (27,361) 63,071

Cash flows from investing activities:
Additions to property and equipment (1,318) (17,678)
Proceeds from sale of oil and
gas properties 338,063 -

Net cash provided by (used in)
investing activities 336,745 (17,678)

Cash flows from financing activities -
Decrease in accounts payable
to affiliate (301,163) (75,090)

Net increase (decrease) in cash 8,221 (29,697)

Cash at beginning of year 6,440 36,137

Cash at end of year $14,661 6,440

AMBER RESOURCES COMPANY
(A subsidiary of Delta Petroleum Corporation)

Notes to Financial Statements
Years Ended June 30, 1998 and 1997

(1) Summary of Significant Accounting Policies

Organization

Amber Resources Company ("the Company") was incorporated in
January, 1978, and is principally engaged in acquiring,
exploring, developing, and producing oil and gas properties. The
Company owns interests in undeveloped oil and gas properties in
federal units offshore California, near Santa Barbara, and
developed oil and gas properties in the continental United
States.

Property and Equipment

The Company follows the successful efforts method of
accounting for its oil and gas activities. Accordingly, costs
associated with the acquisition, drilling, and equipping of
successful exploratory wells are capitalized. Geological and
geophysical costs, delay and surface rentals and drilling costs
of unsuccessful exploratory wells are charged to expense as
incurred. Costs of drilling development wells, both successful
and unsuccessful, are capitalized.

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

Depletion of capitalized acquisition, exploration and
development costs is computed on the units-of-production method
by individual fields as the related proved reserves are produced.
Capitalized costs of unproved properties are assessed
periodically and a provision for impairment is recorded, if
necessary, through a charge to operations.

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

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

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

Gas Balancing

The Company uses the sales method of accounting for gas
balancing of gas production. Under this method, all proceeds
from production credited to the Company are recorded as revenue
until such time as the Company has produced its share of related
reserves. Thereafter, additional amounts received are recorded
as a liability.

As of June 30, 1998, the Company had produced approximately
28,600 Mcf less than its entitled share of production. The
undiscounted value of this imbalance is approximately $64,000
using the lower of the price received for the natural gas, the
current market price or the contract price as applicable.

Royalties Payable

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

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

The statute of limitation has expired for royalty owners to
make a claim for a portion of the estimated royalties that had
previously been accrued. Accordingly, these amount have been
written off and recorded as other income in 1998 and 1997.

Income Taxes

The Company uses the asset and liability method of
accounting for income taxes as set forth in Statement of
Financial Accounting Standards 109 (SFAS 109), Accounting for
Income Taxes. Under the asset and liability method, deferred tax
assets and liabilities are recognized for the future tax
consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and
their respective tax bases and net operating loss and tax credit
carryforwards. Deferred tax assets and liabilities are measured
using enacted income tax rates expected to apply to taxable
income in the years in which those differences are expected to be
recovered or settled. Under SFAS 109, the effect on deferred tax
assets and liabilities of a change in income tax rates is
recognized in the results of operations in the period that
includes the enactment date.

Earnings (Loss) per Share

In February 1997, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards No. 128,
Earnings per Share (Statement No. 128) effective for periods
ending after December 15, 1997. Statement No. 128 changes the
computation, presentation and disclosure requirements for
earnings per share for entities with publicly held common stock
or potential common stock. Under such requirements the Company
is required to present both basic earnings per share and diluted
earnings per share. Basic earnings (loss) per share is computed
by dividing net earnings (loss) attributes to common stock by the
weighted average number of common shares outstanding during each
period, excluding treasury shares.

Diluted earnings (loss) per share is computed by adjusting
the average number of common share outstanding for the dilutive
effect, if any, of convertible preferred stock, stock options and
warrant. The effect of potentially dilutive securities is based
on earnings (loss) before extraordinary items.

The Company adopted the provisions of Statement No. 128 as
of December 31, 1997. As prescribed by Statement No. 128, the
Company has restated prior periods' earnings per share of common
stock, including interim earnings per share of common stock, in
the period of adoption.

Use of Estimates

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

(2) Preferred Stock

The Board of Directors is authorized to issue 5,000,000
shares of 9% Class A convertible preferred stock having a par
value of $1 per share. At the option of the Company, this
preferred stock is convertible at a rate of .625 shares of common
stock for each share of Class A convertible preferred stock.

(3) Income Taxes

At June 30, 1998 and 1997, the Company s significant
deferred tax assets and liabilities are summarized as follows:

1998 1997
Deferred tax assets:
Net operating loss
carryforwards $1,199,000 1,228,000
Oil and gas properties,
principally due to
differences in basis and
depreciation and depletion - 9,000
Gross deferred tax assets 1,199,000 1,237,000

Less valuation allowance (1,158,000) (1,237,000)

41,000 -

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

Net deferred tax asset $ - -

No income tax expense has been recorded for the years ended
June 30, 1998 and 1997 since the deferred income taxes that would
have otherwise been provided were offset by a decrease in the
valuation allowance for the net deferred tax assets.

At June 30, 1998, the Company had net operating loss
carryforwards for regular and alternative minimum tax purposes of
approximately $3,155,000 and $3,361,000, respectively. If not
utilized, the tax net operating loss carryforwards will expire
during the period from 1998 through 2013.

(4) Related Party Transactions

Effective March 31, 1993, the Company and Delta entered
into an agreement which provides for the sharing of management
between the two companies. Under this agreement the Company pays
Delta for its proportionate share of rent, secretarial and
administrative, accounting and management services of Delta's
officers and employees. Amounts charged to the Company for
the sharing of management by Delta were $570,000 for the year
ended June 30, 1998 and $661,055 for the year ended June 30,
1997. The Company had a payable to Delta of $333,976 at June 30,
1998 and $635,139 at June 30, 1997.

(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,
1998 1997

Undeveloped offshore
California properties $ 5,006,276 5,006,276
Developed onshore
domestic properties 1,264,134 1,405,645
6,270,410 6,411,921
Accumulated depreciation
and depletion (848,104) (846,755)

$ 5,422,306 5,565,166

Costs incurred in oil and gas producing activities for the
years ended June 30, 1998 and 1997 are as follows:

1998 1997

Exploration costs $ 20,464 3,330

Development costs 1,318 17,678

Sales of major customers accounted for approximately 62%, 14%
and 11% of 1998 oil and gas sales. Sales to major customers
accounted for approximately 62%, 22% and 11% of 1997 oil and gas
sales.

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

Proved Oil and Gas Reserves. Proved oil and gas reserves are
the estimated quantities of crude oil, natural gas, and natural
gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is
made. Prices include consideration of changes in existing prices
provided only by contractual arrangements, but not on escalations
based upon future conditions.

(i) Reservoirs are considered proved if economic
producibility is supported by either actual production or
conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by
drilling and defined by gas-oil and/or oil-water contacts, if
any; and (B) the immediately adjoining portions not yet
drilled, but which can be reasonably judged as economically
productive on the basis of available geological and
engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved
limit of the reservoir.

(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid
injection) are included in the "proved" classification when
successful testing by a pilot project, or the operation of an
installed program in the reservoir, provides support for the
engineering analysis on which the project or program was
based.

(iii) Estimates of proved reserves do not include the
following: (A) oil that may become available from known
reservoirs but is classified separately as "indicated
additional reserves"; (B) crude oil, natural gas, and natural
gas liquids, the recovery of which is subject to reasonable
doubt because of uncertainty as to geology, reservoir
characteristics, or economic factors; (C) crude oil, natural
gas, and natural gas liquids, that may occur in underlaid
prospects; and (D) crude oil, natural gas, and natural gas
liquids, that may be recovered from oil shales, coal,
gilsonite and other such sources.

Proved undeveloped oil and gas reserves are reserves that are
expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is
required for recompletion. Reserves on undrilled acreage shall
be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved
reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of
production from the existing productive formation. Under no
circumstances should estimates for proved undeveloped reserves be
attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated,
unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.

Offshore Properties. 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. 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.

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 Standards 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 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.

AMBER RESOURCES COMPANY
(A SUBSIDIARY OF DELTA PETROLEUM CORPORATION
Notes to Financial Statements

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

A summary of changes in estimated quantities of proved reserves for the years
ended June 3, 1998 and 1997 are as follows:

<TABLE>

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

<S> <C> <C> <C> <C>
Balance at July 1, 1996 1,848,878 5,290 12,527,925 10,157,086

Revisions of quantity estimates 423,641 1,551 1,229,841 727,676
Production (400,725) (1,025) - -
Balance at June 30, 1997 1,871,794 5,816 13,757,766 10,884,762

Revisions of quantity estimates 333,171 (2,136) (892,983) (1,208,488)
Sale of oil and gas properties (441,765) (708) - -
Production (296,329) (565) - -
Balance at June 30, 1998 1,466,871 2,407 12,864,783 9,676,274

Proved developed reserves:
June 30, 1996 1,848,878 5,290 - -
June 30, 1997 1,871,794 5,816 - -
June 30, 1998 1,466,871 2,407 - -
</TABLE>

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.

<TABLE>

Offshore
Onshore California Total

June 30, 1997

<S> <C> <C> <C>
Future cash inflows $4,149,260 141,472,084 145,621,344
Future costs:
Production 1,559,326 39,050,005 40,609,331
Development - 27,732,752 27,732,752
Income taxes - 25,199,636 25,199,636

Future net cash flows 2,589,934 49,489,691 52,079,625

10% discount factor 799,581 41,187,165 41,986,746

Standardized measure of discounted future
net cash flows $1,790,353 8,302,526 10,092,879

June 30, 1998

Future cash inflows $3,492,318 99,125,074 102,617,392
Future costs:
Production 1,337,464 36,354,442 37,691,906
Development - 26,937,979 26,937,979
Income taxes - 11,248,364 11,248,364

Future net cash flows 2,154,854 24,584,289 26,739,143

10% discount factor 613,372 24,035,334 24,648,706

Standardized measure of discounted future
net cash flows $1,541,482 548,955 2,090,437

</TABLE>

The principal sources of changes in the standardized measure of discounted
net cash flows during the year ended June 30, 1998 and 1997 are as follows:

1998 1997

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

Sales of oil and gas produced during the
period, net of production costs (530,807) (733,198)
Net change in prices and production costs (2,168,966) 63,007
Changes in estimated future development costs 65,629 (938,661)
Revisions of previous quantity estimates,
estimated timing of development and other (2,439,248) (1,940,936)
Net change in income taxes (3,938,338) (398,274)
Accretion of discount 1,009,288 1,276,449

End of year $2,090,437 10,092,879

<ARTICLE> 5

<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> JUN-30-1998
<PERIOD-END> JUN-30-1998
<CASH> 14,661
<SECURITIES> 0
<RECEIVABLES> 71,178
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 85,839
<PP&E> 6,270,410
<DEPRECIATION> 848,104
<TOTAL-ASSETS> 5,508,145
<CURRENT-LIABILITIES> 607,867
<BONDS> 0
0
0
<COMMON> 291,637
<OTHER-SE> 4,608,641
<TOTAL-LIABILITY-AND-EQUITY> 5,508,145
<SALES> 702,161
<TOTAL-REVENUES> 1,173,329
<CGS> 0
<TOTAL-COSTS> 885,157
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 288,172
<INCOME-TAX> 0
<INCOME-CONTINUING> 288,172
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 288,172
<EPS-PRIMARY> .06
<EPS-DILUTED> .06

</TABLE>