DELTA PETROLEUM CORP/CO, 10KSB, 1999-09-28

DELTA PETROLEUM CORP/CO
10KSB, 1999-09-28
CRUDE PETROLEUM & NATURAL GAS

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-KSB

[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 1999.

[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from .

Commission File No. 0-16203

DELTA PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)

Colorado 84-1060803
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

555 17th Street, Suite 3310
Denver, Colorado 80202
(Address of principal executive offices) (Zip Code)

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

Securities registered under Section 12(b) of the Exchange
Act: None

Securities registered under to Section 12(g) of the Exchange
Act:
Common Stock, $.01 par value

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 revenues for the fiscal year ended June 30, 1999
total $1,717,651.

The aggregate market value as of September 15, 1999 of voting
stock held by non-affiliates of the registrant was $15,132,592.

As of September 15, 1999, 6,653,902 shares of registrant's Common
Stock $.01 par value were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: DEFINITIVE PROXY MATERIALS
FOR THE 1999 ANNUAL MEETING OF SHAREHOLDERS - PART III, ITEMS 9,
10, 11, AND 12.

The Index to Exhibits appears at Page 37.

TABLE OF CONTENTS

PART I

PAGE

ITEM 1. DESCRIPTION OF BUSINESS 1
ITEM 2. DESCRIPTION OF PROPERTY 6
ITEM 3. LEGAL PROCEEDINGS 23
ITEM 4. SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS 23
ITEM 4A. DIRECTORS AND EXECUTIVE OFFICERS 24

PART II

ITEM 5. MARKET FOR COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS 26
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS
OR PLAN OF OPERATION 28
ITEM 7. FINANCIAL STATEMENTS 33
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 33

PART III

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE
EXCHANGE ACT 34
ITEM 10. EXECUTIVE COMPENSATION 34
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT 34
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS 34
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K 34

FORWARD-LOOKING STATEMENTS 34

The terms "Delta", "Company", "we", "our", and "us" refer to
Delta Petroleum Corporation and its subsidiaries unless the
context suggests otherwise.

PART I

ITEM 1. DESCRIPTION OF BUSINESS

(a) Business Development.

Delta Petroleum Corporation ("Delta", "the Company") is
a Colorado corporation organized on December 21, 1984. We
maintain our principal executive offices at Suite 3310, 555
Seventeenth Street, Denver, Colorado 80202, and our telephone
number is (303) 293-9133. Our common stock is listed on NASDAQ
under the symbol DPTR.

We are engaged in the acquisition, exploration,
development and production of oil and gas properties. As of June
30, 1999, we had varying interests in 72 gross (17.1 net)
productive wells located in six states. We have undeveloped
properties in five states, and interests in four federal units
and one lease offshore California near Santa Barbara. We
operate 24 of the wells and the remaining wells are operated by
independent operators. All wells are operated under contracts
that are standard in the industry. At June 30, 1999, we
estimated proved reserves to be approximately 143,000 Bbls of oil
and 3.83 Bcf of gas, of which approximately 13,000 Bbls of oil
and 2.29 Bcf of gas were proved developed reserves. (See
"Description of Property;" Item 2 herein.)

At September 15, 1999, we had an authorized capital of
3,000,000 shares of $.10 par value preferred stock, of which no
shares of preferred stock were issued, and 300,000,000 shares of
$.01 par value common stock of which 6,653,902 shares of common
stock were issued and outstanding. We have outstanding warrants
and options to purchase 1,054,500 shares of common stock at
prices ranging from $1.25 per share to $6.13 per share at
September 15, 1999. Additionally, we have outstanding options
which were granted to our officers, employees and directors under
our 1993 Incentive Plan, as amended, to purchase up to 1,634,063
shares of common stock at prices ranging from $0.05 to $9.75 per
share at September 15, 1999.

At June 30, 1999, we owned 4,277,977 shares of common
stock of Amber Resources Company ("Amber"), representing 91.68%
of the outstanding common stock of Amber. Amber is a public
company (registered under the Securities Exchange Act of 1934)
whose activities include oil and gas exploration, development,
and production operations. Amber owns interests in producing oil
and gas properties in Oklahoma and non-producing oil and gas
properties offshore California near Santa Barbara. The Company
and Amber entered into an agreement effective October 1, 1998
which provides, in part, for the sharing of the management
between the two companies and allocation of expenses related
thereto.

(b) Business of Issuer.

During the year ended June 30, 1999, we were engaged in
only one industry, namely the acquisition, exploration,
development, and production of oil and gas properties and related
business activities. Our oil and gas operations have been
comprised primarily of production of oil and gas, drilling
exploratory and development wells and related operations and
acquiring and selling oil and gas properties. We, directly and
through Amber, currently have producing oil and gas interests,
undeveloped leasehold interests and related assets in south
Texas; interests in undeveloped offshore Federal leases and units
near Santa Barbara, California; producing and non-producing
interests in the Denver-Julesburg and Piceance Basins of
Colorado; the Sacramento Basin of California, the Wind River
Basin of Wyoming, the Anadarko Basin in Oklahoma and in the
Arkoma Basin in western Arkansas. We intend to continue our
emphasis on the drilling of exploratory and development wells
primarily in Colorado, California, Texas, Wyoming and Oklahoma.
We are in the process of acquiring an interest in a producing
offshore Federal unit and an undeveloped offshore Federal unit
near Santa Barbara, California.

We intend to drill on some of our leases (presently
owned or subsequently acquired); may farm out or sell all or part
of some of the leases to others; and/or may participate in joint
venture arrangements to develop certain other leases. Such
transactions may be structured in any number of different manners
which are in use in the oil and gas industry. Each such
transaction is likely to be individually negotiated and no
standard terms may be predicted.

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

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

(3) Status of Any Publicly Announced New Product or
Service. We have not made a public announcement of, and no
information has otherwise become public about, a new product or
industry segment requiring the investment of a material amount of
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. We compete with a number
of other companies, including major oil companies and other
independent operators which are more experienced and which have
greater financial resources. We do not hold a significant
competitive position in the oil and gas industry.

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

(6) Dependence on One or a Few Major Customers. We do
not depend upon one or a few major customers for the sale of oil
and gas as of the date of this report. The loss of any one or
several customers would not have a material adverse effect on our
business.

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

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

(9) Government Regulation of the Oil and Gas Industry.

General.

Our business is affected by numerous governmental laws
and regulations, including energy, environmental, conservation,
tax and other laws and regulations relating to the energy
industry. Changes in any of these laws and regulations could
have a material adverse effect on our business. In view of the
many uncertainties with respect to current and future laws and
regulations, including their applicability to us, we cannot
predict the overall effect of such laws and regulations on our
future operations.

We believe that our operations comply in all material
respects with all applicable laws and regulations and that the
existence and enforcement of such laws and regulations have no
more restrictive effect on our method of operations than on other
similar companies in the energy industry.

The following discussion contains summaries of certain
laws and regulations and is qualified in its entirety by the
foregoing.

Environmental Regulation.

Together with other companies in the industries in
which we operate, our operations are subject to numerous federal,
state, and local environmental laws and regulations concerning
its oil and gas operations, products and other activities. In
particular, these laws and regulations require the acquisition of
permits, restrict the type, quantities, and concentration of
various substances that can be released into the environment,
limit or prohibit activities on certain lands lying within
wilderness, wetlands and other protected areas, regulate the
generation, handling, storage, transportation, disposal and
treatment of waste materials and impose criminal or civil
liabilities for pollution resulting from oil, natural gas and
petrochemical operations.

Governmental approvals and permits are currently, and
may in the future be, required in connection with our operations.
The duration and success of obtaining such approvals are
contingent upon many variables, many of which are not within our
control. To the extent such approvals are required and not
obtained, operations may be delayed or curtailed, or we may be
prohibited from proceeding with planned exploration or operation
of facilities.

Environmental laws and regulations are expected to have
an increasing impact on our operations, although it is impossible
to predict accurately the effect of future developments in such
laws and regulations on our future earnings and operations. Some
risk of environmental costs and liabilities is inherent in
particular operations and products of ours, as it is with other
companies engaged in similar businesses, and there can be no
assurance that material costs and liabilities will not be
incurred. However, we do not currently expect any material
adverse effect upon our results of operations or financial
position as a result of compliance with such laws and
regulations.

Although future environmental obligations are not
expected to have a material adverse effect on our results of
operations or financial condition of the Company, there can be no
assurance that future developments, such as increasingly
stringent environmental laws or enforcement thereof, will not
cause us to incur substantial environmental liabilities or costs.

Hazardous Substances and Waste Disposal.

We currently own or lease interests in numerous
properties that have been used for many years for natural gas and
crude oil production. Although the operator of such properties
may have utilized operating and disposal practices that were
standard in the industry at the time, hydrocarbons or other
wastes may have been disposed of or released on or under the
properties owned or leased by us. In addition, some of these
properties have been operated by third parties over whom we had
no control. The U.S. Comprehensive Environmental Response,
Compensation and Liability Act ("CERCLA") and comparable state
statutes impose strict, joint and several liability on owners and
operators of sites and on persons who disposed of or arranged for
the disposal of "hazardous substances" found at such sites. The
Resource Conservation and Recovery Act ("RCRA") and comparable
state statutes govern the management and disposal of wastes.
Although CERCLA currently excludes petroleum from cleanup
liability, many state laws affecting our operations impose
clean-up liability regarding petroleum and petroleum related
products. In addition, although RCRA currently classifies
certain exploration and production wastes as "nonhazardous," such
wastes could be reclassified as hazardous wastes thereby making
such wastes subject to more stringent handling and disposal
requirements. If such a change in legislation were to be
enacted, it could have a significant impact on our operating
costs, as well as the gas and oil industry in general.

Oil Spills.

Under the Federal Oil Pollution Act of 1990, as amended
("OPA"), (i) owners and operators of onshore facilities and
pipelines, (ii) lessees or permittees of an area in which an
offshore facility is located and (iii) owners and operators of
tank vessels ("Responsible Parties") are strictly liable on a
joint and several basis for removal costs and damages that result
from a discharge of oil into the navigable waters of the United
States. These damages include, for example, natural resource
damages, real and personal property damages and economic losses.
OPA limits the strict liability of Responsible Parties for
removal costs and damages that result from a discharge of oil to
$350 million in the case of onshore facilities, $75 million plus
removal costs in the case of offshore facilities, and in the case
of tank vessels, an amount based on gross tonnage of the vessel.
However, these limits do not apply if the discharge was caused by
gross negligence or wilful misconduct, or by the violation of an
applicable Federal safety, construction or operating regulation
by the Responsible Party, its agent or subcontractor or in
certain other circumstances.

In addition, with respect to certain offshore
facilities, OPA requires evidence of financial responsibility in
an amount of up to $150 million. Tank vessels must provide such
evidence in an amount based on the gross tonnage of the vessel.
Failure to comply with these requirements or failure to cooperate
during a spill event may subject a Responsible Party to civil or
criminal enforcement actions and penalties.

Offshore Production.

Offshore oil and gas operations in U.S. waters are
subject to regulations of the United States Department of the
Interior which currently impose strict liability upon the lessee
under a Federal lease for the cost of clean-up of pollution
resulting from the lessee's operations, and such lessee could be
subject to possible liability for pollution damages. In the
event of a serious incident of pollution, the Department of the
Interior may require a lessee under Federal leases to suspend or
cease operations in the affected areas.

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

(11) Environmental Protection. Because we are engaged
in acquiring, operating, exploring for and developing natural
resources, we are subject to various state and local provisions
regarding environmental and ecological matters. Therefore,
compliance with environmental laws may necessitate significant
capital outlays, may materially affect our earnings potential,
and could cause material changes in our proposed business. At
the present time, however, the existence of environmental law
does not materially hinder nor adversely affect our business.
Capital expenditures relating to environmental control facilities
have not been material to the operation of Delta since its
inception. In addition, we do not anticipate that such
expenditures will be material during the fiscal year ending June
30, 2000.

(12) Employees. We have four full time employees.
Operators, engineers, geologists, geophysicists, landmen,
pumpers, draftsmen, title attorneys and others necessary for our
operations are retained on a contract or fee basis as their
services are required.

ITEM 2. DESCRIPTION OF PROPERTY

(a) Office Facilities.

Our offices are located at 555 Seventeenth Street,
Suite 3310, Denver, Colorado 80202. We lease approximately 4,800
square feet of office space for $7,125 per month and the lease
will expire in April of 2002. Currently, we sublease
approximately 2,500 square feet to Bion Environmental
Technologies, Inc. for $3,575 per month.

(b) Oil and Gas Properties.

We own interests in oil and gas properties located in
California, Colorado, Oklahoma, Texas, Wyoming and elsewhere.
Most wells from which we receive revenues are owned only
partially by us. For information concerning our oil and gas
production, average prices and costs, estimated oil and gas
reserves and estimated future cash flows, see the tables set
forth below in this section and "Notes to Financial Statements"
included in this report. We did not file oil and gas reserve
estimates with any federal authority or agency other than the
Securities and Exchange Commission during the years ended June
30, 1999, 1998 and 1997.

Principal Properties.

The following is a brief description of our principal
properties:

Onshore:

California: Sacramento Basin Area

We have participated in three 3-D seismic survey
programs located in Colusa and Yolo counties in the Sacramento
Basin in California with interests ranging from 12% to 15%. We
sold our interest in a fourth such survey in the area in March of
1998. These programs are operated by Slawson Exploration
Company, Inc. The program areas contain approximately 90 square
miles in the aggregate upon which we have participated in the
costs of collecting and processing 3-D seismic data, acquiring
leases and drilling wells upon these leases. As of September 15,
1999 leases or options to lease have been acquired within the
program areas totaling approximately 3,000 gross acres. Seismic
information has been gathered, processed and interpreted on all
three surveys. Interpretation of the 90 square miles of seismic
information revealed approximately 25 drillable prospects. As of
September 15, 1999, 18 wells have been drilled of which nine are
now producing and one is waiting on completion. We expect to
participate in the drilling of two additional wells during the
remainder of fiscal 2000 assuming we have adequate funds. The
area has adequate markets for the volumes of natural gas that are
projected from the drilling activity in the area.

Colorado.

Denver-Julesburg Basin. We own leasehold interests in
approximately 480 gross (47 net) acres and has interests in eight
gross (.77 net) wells in the Denver-Julesburg Basin producing
primarily from the D-Sand and J-Sand formations. No new activity
is planned for this area for the next fiscal year.

Piceance Basin. We own working interests in 13 gas
wells (10.3 net), and oil and gas leases covering 14,328 net
acres in the Piceance Basin in Mesa and Rio Blanco counties,
Colorado. We are evaluating the possibility of recompleting
additional zones in many of our wells. The acreage is located in
and around the Plateau and Vega Fields.

Oklahoma.

Directly (12 wells) and through Amber (20 wells) we own
non-operating working interests in 32 natural gas wells in
Oklahoma. The wells range in depth from 4,500 to 15,000 feet and
produce from the Red Fork, Atoka, Morrow and Springer formations.
Most of our reserves are in the Red Fork/Atoka formation. The
working interests range from less than 1% to 23% and average
about 7% per well. Many of the wells have remaining productive
lives of 20 to 30 years. During fiscal 1999 we sold interests in
23 wells in Oklahoma for an aggregate proceeds of $1,384,000.

Wyoming.

Moneta Hills. In 1997 we sold an 80% interest in its
Moneta Hills project to KCS Energy ("KCS"), a subsidiary of KCS
Mountain Resources, Inc. The Moneta Hills project presently
consists of approximately 9,696 acres, six wells and a 13 mile
gas gathering pipeline. Under the terms of the sale, KCS paid
$450,000 to Delta for the interests acquired and agreed to drill
two wells to the Fort Union formation at approximately 10,000
feet. KCS will carry Delta for a 20% backin after payout interest
in each of the two wells. The first well has been drilled and is
producing. The second well was scheduled to be drilled prior to
the end of calendar 1997, but has been delayed indefinitely. We
will evaluate the results of these first two wells in addition to
other factors in making our decisions to participate for our 20%
working interest in any subsequent wells.

Texas.

Austin Chalk Trend. We own leasehold interests in
approximately 1,558 gross acres (1,111 net acres) and own
substantially all of the working interests in three horizontal
wells in the area encompassing the Austin Chalk Trend in Gonzales
County and a small minority interest in one additional horizontal
well in Zavala County, Texas. We are evaluating the possibility
of re-entering one or more of these wells and drilling additional
horizontal bores in other untapped zones.

Offshore:

Offshore Federal Waters: Santa Barbara, California Area

Directly and through our subsidiary, Amber Resources
Company, we own interests in four undeveloped federal units
(plus one additional lease) located in federal waters offshore
California near Santa Barbara.

The Santa Barbara Channel and the offshore Santa Maria
Basin are the seaward portions of geologically well-known onshore
basins with over 90 years of production history. These offshore
areas were first explored in the Santa Barbara Channel along the
near shore three mile strip controlled by the state. New field
discoveries in Pliocene and Miocene age reservoir sands led to
exploration into the federally controlled waters of the Pacific
Outer Continental Shelf ("POCS"). Eight POCS lease sales and
subsequent drilling conducted between 1966 and 1984 have resulted
in the discovery of an estimated two billion Bbls of oil and
three trillion cubic feet of gas. Of these totals, some 869
million Bbls of oil and 819 billion cubic feet of gas have been
produced and sold. During 1998, POCS production was
approximately 150,000 Bbls of oil and 210 million cubic feet of
gas per day according to the Minerals Management Service of the
Department of the Interior ("MMS").

Most of the early offshore production was from Pliocene
age sandstone reservoirs. The more recent developments are from
the highly fractured zones of the Miocene age Monterey Formation.
The Monterey is productive in both the Santa Barbara Channel and
the offshore Santa Maria Basin. It is the principal producing
horizon in the Point Arguello field, the Point Pedernales field,
and the Hondo and Pescado fields in the Santa Ynez Unit. Because
the Monterey is capable of relatively high productive rates, the
Hondo field, which has been on production since late 1981, has
already surpassed 190 million Bbls of production.

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

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

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

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

Each working interest owner will be required to pay its
proportionate share of these costs based upon the amount of the
interest that it owns. The size of our working interest in the
units varies from 2.492% to 15.60%. We may be required to farm
out all or a portion of our interests in these properties to a
third party if we cannot fund our share of the development costs.
There can be no assurance that we can farm out our interests on
acceptable terms.

These units have been formally approved and are
regulated by the MMS. While the Federal Government has recently
attempted to expedite the process of obtaining permits and
authorizations necessary to develop the properties, there can be
no assurance that it will be successful in doing so. We do not
have a controlling interest in and do not act as the operator of
any of the offshore California properties and consequently will
not generally control the timing of either the development of the
properties or the expenditures for development unless we choose
to unilaterally propose the drilling of wells under the relevant
operating agreements.

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

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

Scenario 1 No new development of existing
offshore leases. If this scenario were ultimately
to be adopted by governmental decision makers as
the proper course of action for development, our
offshore California properties would in all
likelihood have little or no value. In this
scenario we would seek to cause the Federal
government to reimburse us for all money spent by
us and our predecessors for leasing and other
costs and for the value of the oil and gas
reserves found on the leases through our exploration
activities and those of our predecessors.

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

Scenario 3 Development of existing leases,
using existing onshore facilities by constructing
additional capacity at existing sites to handle
expanded production. 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 scenario that is currently
anticipated by our management.

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

We have also evaluated our position with regard to
the scenarios currently being studied with respect to
properties located in the northern subregion (which includes
the Lion Rock Unit and the Point Sal Unit), the results of
which are as follows:

Scenario 1 No new development of existing
offshore leases. If this scenario were ultimately
to be adopted by governmental decision makers as
the proper course of action for development, our
offshore California properties would in all
likelihood have little or no value. In this
scenario we would seek to cause the Federal
government to reimburse us for all money spent by
us and our predecessors for leasing and other
costs and for the value of the oil and gas reserves
found on the leases through our exploration activities
and those of our predecessors.

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

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

Our development plans currently provide for 22 wells
from one platform set in a water depth of approximately 300 feet
for the Gato Canyon Unit; 63 wells from one platform set in a
water depth of approximately 1,100 feet for the Sword Unit; 60
wells from one platform set in a water depth of approximately 336
feet for the Point Sal Unit; and 183 wells from two platforms for
the Lion Rock Unit. On the Lion Rock Unit, platform A would be
set in a water depth of approximately 507 feet, and Platform B
would be set in a water depth of approximately 484 feet. The
reach of the deviated wells from each platform required to drain
each unit falls within the reach limits now considered to be
"state-of-the-art."

Current Status. On October 15, 1992 the MMS directed
a Suspension of Operations ("SOO") effective January 1, 1993, for
the POCS non-producing leases and units, pursuant to CFR 250.110,
to enable the lease owners to participate in what became known as
the COOGER Study. This allowed the leases to be held under an
SOO during the term of the study thereby permitting the owners to
cease paying lease payments to the Federal government and
suspending the requirements relating to development of these
leases during this period.

The MMS has extended the SOO from time to time to allow
completion of the COOGER Study. Most recently the MMS directed
an additional SOO through November 15, 1999 when unit operators
are required to have submitted descriptions of their exploration
plans for the leases to support their requests for Suspension of
Production ("SOP") status for the leases. Each operator has or
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 an
SOP time period to execute the Schedule of Events.

In order to carry out the requirements of the MMS, all
operators of the units in which we own 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. We are participating
with the operators in meeting the MMS schedules through meetings,
and consultations and in sharing in the costs as invoiced by the
operators.

Cost to Develop Offshore California Properties. The
cost to develop all of the offshore California properties in
which Delta owns an interest, including delineation wells,
environmental mitigation, development wells, fixed platforms,
fixed platform facilities, pipelines and power cables, onshore
facilities and platform removal over the life of the properties
(assumed to be 38 years), is estimated to be slightly in excess
of $3 billion. Our share of such costs over the life of the
properties is estimated to be $216,000,000.

To the extent that we do not have sufficient cash
available to pay our share of expenses when they become payable
under the respective operating agreements, it will be necessary
for us to seek funding from outside sources. Likely potential
sources for such funding are currently anticipated to include (a)
public and private sales of our Common Stock (which may result in
substantial ownership dilution to existing shareholders), (b)
bank debt from one or more commercial oil and gas lenders, (c)
the sale of debt instruments to investors, (d) entering into
farm-out arrangements with respect to one or more of our
interests in the properties whereby the recipient of the farm-out
would pay the full amount of our share of expenses and we would
retain a carried ownership interest (which would result in a
substantial diminution of our ownership interest in the
farmed-out properties), (e) entering into one or more joint
venture relationships with industry partners, (f) entering into
financing relationships with one or more industry partners, and
(g) the sale of some or all of our interests in the properties.

It is unlikely that any one potential source of funding
would be utilized exclusively. Rather, it is more likely that we
will pursue a combination of different funding sources when the
need arises. Regardless of the type of financing techniques that
are ultimately utilized, however, it currently appears likely
that because of our small size in relation to the magnitude of
the capital requirements that will be associated with the
development of the subject properties, we will be forced in the
future to issue significant amounts of additional shares, pay
significant amounts of interest on debt that presumably would be
collateralized by all of our assets (including its offshore
California properties), reduce our ownership interest in the
properties through sales of interests in the property or as the
result of farm-outs, industry financing arrangements or other
partnership or joint venture relationships, or to enter into
various transactions which will result in some combination of the
foregoing. In the event that we are not able to pay our share of
expenses as a working interest owner as required by the
respective operating agreements, it is possible that we might
lose some portion of our ownership interest in the properties
under some circumstances, or that we might be subject to
penalties which would result in the forfeiture of
substantial revenues from the properties.

While the cost to develop the offshore California
properties in which we own an interest are anticipated to be
substantial in relation to our small size, management believes
that the opportunities for us to increase our asset base and
ultimately improve our cash flow are also substantial in relation
to our size. Although there are several factors to be considered
in connection with our plans to obtain funding from outside
sources as necessary to pay our proportionate share of the costs
associated with developing our offshore properties (not the least
of which is the possibility that prices for petroleum products
could decline in the future to a point at which development of
the properties is no longer economically feasible), we believe
that the timing and rate of development in the future will in
large part be motivated by the prices paid for petroleum
products.

To the extent that prices for petroleum products were
to decline below their recent near historic lows, it is likely
that development efforts will proceed at a slower pace to the end
that costs will be incurred over a more extended period of time.
If petroleum prices increase, however, we believe that
development efforts will intensify. Our ability to successfully
negotiate financing to pay our share of development costs on
favorable terms will be inextricably linked to the prices that
are paid for petroleum products during the time period in which
development is actually occurring on each of the subject
properties.

Gato Canyon Unit. We hold a 15.60% 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 structure.
Five of these were drilled within the boundaries of the Unit and
two were drilled outside the Unit boundaries in the adjacent
State Tidelands. The test wells were drilled as follows: within
the boundaries of the Unit; three wells were drilled by Exxon,
two in 1968 and one in 1969; one well was drilled by Arco in
1985; and, one well was drilled by Samedan in 1989. Outside the
boundaries of the Unit, in the State Tidelands but still on the
Gato Canyon Structure, one well was drilled by Mobil in 1966 and
one well was drilled by Union Oil in 1967. In April 1989,
Samedan tested the P-0460 #2 which yielded a combined test flow
rate of 5,160 Bbls of oil per day from six intervals in the
Monterey Formation between 5,880 and 6,700 feet of drilled depth.
The Monterey Formation is a highly fractured shale formation. The
Monterey (which ranges from 500' to 2,900' in thickness) is the
main productive and target zone in many offshore California oil
fields (including our federal leases and/or units).

The Gato Canyon field is located in the Santa Barbara
Channel approximately three to five miles offshore (see Map).
Water depths range from 280 feet to 600 feet in the area of the
field. Oil and gas produced from the field is anticipated to be
processed onshore at the existing Las Flores Canyon facility (see
Map). Las Flores Canyon has been designated a "consolidated
site" by Santa Barbara County and is available for use by
offshore operators. Any processed oil is expected to be
transported out of Santa Barbara County in the All American
Pipeline (see Map). Offshore pipeline distances to access the
Las Flores site is approximately six miles. Delta's share of the
estimated capital costs to develop the Gato Canyon field are
approximately $45,000,000.

The Gato Canyon Unit leases are currently held under a
Suspension of Operations until November 15, 1999. Thereafter,
the Unit operator intends to 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 is expected
to include plans to drill an additional delineation well. This
well will be used to determine the final location of the
development platform. Following the platform decision, a
Development Plan will be prepared for submittal to the MMS and
the other involved agencies. Two to three years will likely be
required to process the Development Plan and receive the
necessary approvals.

Point Sal Unit. We hold a 6.83% working interest in
the Point Sal Unit. This 22,772 acre unit is operated by Aera
Energy LLC, a limited liability company jointly owned by Shell
Oil Company and Mobil Oil Company. Four test wells were drilled
within this unit. These test wells were drilled as follows: two
wells were drilled by Sun Oil (now Oryx Energy), one in 1984 and
one in 1985; and the other two wells were drilled by Reading &
Bates, both in 1984. All four wells drilled on this unit have
indicated the presence of oil and gas in the Monterey Formation.
The largest of these, the Sun P-0422 #1, yielded a combined test
flow rate of 3,750 Bbls of oil per day from the Monterey. The oil
in the upper block has an average estimated gravity of 10 degrees API
and the oil in the subthrust block has an average estimated
gravity of 15 degrees API.

The Point Sal field is located in the Offshore Santa
Maria Basin approximately six miles seaward of the coastline (see
Map). Water depths range from 300 feet to 500 feet in the area
of the field. It is anticipated that oil and gas produced from
the field will be processed in a new facility at an onshore site
or in the existing Lompoc facility (see Map). Any processed oil
would then be transported out of Santa Barbara County in either
the All American Pipeline or the Tosco-Unocal Pipeline (see Map).
Offshore pipeline distance is approximately six to eight miles
depending on the final choice of the point of landfall. Delta's
share of the estimated capital costs to develop the Point Sal
unit are approximately $38,000,000.

The Point Sal Unit leases are currently held under a
Suspension of Operations until November 15, 1999. Thereafter,
the Unit operator intends to carry out a Unit Schedule of Events
under a Suspension of Production. The Schedule of Events will
include preparation of an updated Exploration Plan which is
expected to include plans to drill an additional delineation well
prior to preparing the Development Plan.

Lion Rock Unit and Federal OCS Lease P-0409. We hold a
1% net profits interest (through Amber) in the Lion Rock Unit and
a 24.21692% working interest (directly) in 5,693 acres in Federal
OCS Lease P-0409 which is immediately adjacent to the Lion Rock
Unit and contains a portion of the San Miguel Field reservoir.
The Lion Rock Unit is operated by Aera Energy LLC. An aggregate
of 13 test wells have been drilled on the Lion Rock Unit and OCS
lease P-0409. Nine of these wells were completed and tested and
indicated the presence of oil and gas in the Monterey Formation.
The test wells were drilled as follows: one well was drilled by
Socal (now Chevron) in 1965; six wells were drilled by Phillips
Petroleum, one in 1982, two in 1983, two in 1984 and one in 1985;
six wells were drilled by Occidental Petroleum in Lease P-0409,
three in 1983 and three in 1984. The oil has an average
estimated gravity of 10.7 degrees API.

The Lion Rock Unit and Lease P-0409 are 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. It is anticipated that any oil and gas
produced at Lion Rock and P-0409 would be processed at a new
facility in the onshore Santa Maria Basin or at the existing
Lompoc facility (see Map), and would be transported out of Santa
Barbara County in the All American Pipeline or the Tosco-Unocal
Pipeline (see Map). Offshore pipeline distance will be eight to
ten miles depending on the point of landfill. Delta's share of
the estimated capital costs to develop the Lion Rock/San Miguel
field is approximately $113,000,000.

The Lion Rock Unit and Lease P-0409 are currently held
under a Suspension of Operations until November 15, 1999.
Thereafter, the Unit operator intends to 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. We hold a 2.492% working interest (directly
1.6189% and through Amber .8731%) 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.

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. It is anticipated that the oil and gas produced from the
Sword Field will likely be processed at the existing Gaviota
consolidated facility and the oil would then be transported out
of Santa Barbara County in the All American Pipeline (see Map).
Access to the Gaviota plant is through Platform Hermosa and the
existing Point Arguello Pipeline system. A pipeline proposed to
be laid from a platform located in the northern area of the Sword
field to Platform Hermosa would be approximately five miles in
length. Delta's share of the estimated capital costs to develop
the Sword field is approximately $19,300,000.

The Sword Unit leases are currently held under a
Suspension of Operations until November 15, 1999. Thereafter,
the Unit operator intends to 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 which is
expected to include plans to drill 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.

Acquisition of Interests in the Point Arguello and
Rocky Point Units. On June 9, 1999 we announced that we had
entered into an agreement which gives us the opportunity to
acquire Whiting Petroleum Corporation's ("Whiting") interest in
the Point Arguello Unit, with its three platforms (Hidalgo,
Harvest, and Hermosa), along with Whiting's interest in the
adjacent undeveloped Rocky Point Unit. These properties are also
located in Federal waters offshore Santa Barbara, California.
Whiting has a 6.07% working interest in the Point Arguello Unit
and a 100% working interest in the adjacent OCS Blocks 452 and
453 of the undeveloped Rocky Point Unit. Whiting will retain its
proportionate share of future abandonment liability associated
with both the onshore and offshore facilities of the Point
Arguello Unit.

As of August 2, 1999 we had issued 300,000 shares of
our common stock and paid Whiting $3,000,000 for 50% of the
interest in these properties. We have agreed to pay an
additional $3,000,000 by December 1, 1999 for the balance of the
interests in these properties. Whiting will retain its
proportionate share of future abandonment liability associated
with the Point Arguello unit project for both onshore and
offshore facilities.

The Point Arguello unit platforms are currently
producing a combined 22,000 barrels of oil per day. We expect to
participate in additional development from the three existing
platforms of the Point Arguello unit and in any development of
the adjacent undeveloped Rocky Point unit.

The effective date of the transfer of these properties
under our agreement with Whiting is retroactive to April 1, 1999
after which all revenues and expenses belong to us provided that
we pay for and close on the transaction as agreed upon. The
purchase price will be adjusted at closing to account for the
revenues and expenses from April 1, 1999 to closing.

Kazakhstan

Acquisition of Exploration Licenses in Kazakhstan.
During fiscal year 1999 we acquired two licenses for exploration
of approximately 1.9 million acres in the Pavlodar region of
Eastern Kazakhstan by agreeing to exchange our common stock and
warrants in a private transaction for 100% of Ambir Properties,
Inc. ("Ambir"), a private company which held the licenses as its
sole asset. The transaction included the exchange of 250,000
shares of restricted Delta common stock and 500,000 warrants to
purchase common stock at prices ranging from $3.50 to $5.00 per
share. A work plan prepared by Delta was approved by the
Kazakhstan government which established minimum work and spending
commitments until February 1, 2003. We are in the process of
transferring the licenses into the name of Delta and extending
the time for certain commitments under the workplan. The
acquisition is a high risk, frontier exploration
project. Delta does not presently have the expertise nor the
resources to meet all commitments that will be required in the
later years of the work plan. Delta may seek other companies in
the oil and gas industry to participate in the implementation of
the work plan.

The acquisition agreement includes a voting agreement
under which the officers of Delta, Aleron H. Larson, Jr.,
Chairman and CEO, and Roger A. Parker, President, vote all shares
owned by the selling shareholders of Ambir until December 31,
2002.

We are not obligated to provide a fixed and determined
quantity of oil and gas in the future under existing contracts or
agreements. During the years ended June 30, 1999, 1998 and
1997, we have not had, nor do we now have, any long-term supply
or similar agreements with governments or authorities pursuant to
which we acted as producer.

The following table sets forth our average sales prices and
average production costs during the periods indicated:

Year Ended Year Ended Year Ended
June 30, June 30, June 30,
1999 1998 1997

Average sales price:
Oil (per barrel) $10.24 16.46 22.36
Natural Gas (per Mcf) $1.97 2.26 2.41
Production costs
(per Mcf equivalent) $.73 .67 .85

The profitability of the our oil and gas production activities is
affected by the fluctuations in the sale prices of our oil and
gas production. (See "Management's Discussion and Analysis or
Plan of Operation.")

(d) Productive Wells and Acreage.

The table below shows, as of June 30, 1999, the
approximate number of gross and net producing oil and gas wells
by state and their related developed acres owned by us.
Calculations include 100% of wells and acreage owned by us and by
Amber. Productive wells are producing wells capable of
production, including shut-in wells. Developed acreage consists
of acres spaced or assignable to productive wells.

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

Texas 4 1.82 0 .0 1,558 1,111
Colorado 8 .8 13 10.3 2,560 2,127
Oklahoma 0 .0 32 2.03 17,120 1,198
California 0 .0 9 1.0 1,200 132
Wyoming 0 .0 6 1.2 960 192
12 2.62 60 14.53 23,398 4,760

(1) All of the wells classified as "oil" wells also produce
various amounts of natural gas.

(2) 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.

(3) 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, 1999, we held undeveloped acreage by state
as set forth below:

Undeveloped Acres (1) (2)
Location Gross Net

California, offshore(3) 50,805 4,244
California, onshore 3,000 391
Colorado 16,888 14,265
Wyoming 9,696 1,939
Oklahoma 1,600 112
Total 81,989 20,951

(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) Includes acreage owned by Amber.

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

(f) Drilling Activity

During the years indicated, we drilled or participated
in the drilling of the following productive and nonproductive
exploratory and development wells:

Year Ended Year Ended Year Ended
June 30, June 30, June 30,
1999 1998 1997
Gross Net Gross Net Gross Net

Exploratory Wells(1):
Productive:
Oil. . . . . . . . . . . . 0 .0 0 .0 0 .0
Gas. . . . . . . . . . . . 4 .44 5 .545 0 .0
Nonproductive. . . . . . . . 7 .77 1 .113 1 1.0
Total. . . . . . . . . . . . 11 1.21 6 .658 1 1.0

Development Wells(1):.
Productive:
Oil. . . . . . . . . . . . 0 .0 0 .0 0 .0
Gas. . . . . . . . . . . . 0 .0 1 .042 4 .2
Nonproductive. . . . . . . . 0 .0 0 .0 0 .0
Total. . . . . . . . . . . . 0 .0 1 .042 4 .2

Total Wells(1):
Productive:
Oil. . . . . . . . . . . . 0 .0 0 .0 0 .0
Gas. . . . . . . . . . . . 4 .44 6 .587 4 .2
Nonproductive. . . . . . . . 7 .77 1 .113 1 1.0
Total Wells. . . . . . . . . 11 1.21 7 .700 5 1.2

(1) Does not include wells in which the Company had only a
royalty interest.

(g) Present Drilling Activity

Between July 1, 1999 and September 15, 1999, the Company
participated in the drilling of 1 new well on its properties in
the Sacramento Basin. The well is successful and will be selling
gas within a few weeks. We plan to participate in the drilling
of one additional well on these properties during the next 90
days.

ITEM 3. LEGAL PROCEEDINGS

We are not directly engaged in any material pending
legal proceedings to which we or our subsidiaries are a party or
to which any of our property is subject.

The operators of the offshore Federal units in which we
own interests have each filed Notices of Appeal on behalf of
themselves and the co-owners of the various units, including
Delta, with the United States Department of Interior of a June
25, 1999 order issued by the Regional Director, Pacific OCS
Region, terminating existing Suspensions of Production in effect
prior to the present Suspension of Operations. We do not expect
that the outcome of any later appeal that might be filed pursuant
to the Notice of Appeal will have any material affect upon our
property interests because the operators are in the process of
requesting new Suspension of Production status for each of the
units which, if granted, will replace the existing Suspension of
Operations.

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

The 1998 Annual Meeting of the shareholders of the
Company was held on June 30, 1999.

At the Annual Meeting the following persons,
constituting the entire board of directors, were elected as
directors of the Company to serve until the next annual meeting:

Abstentions, Votes
Withheld &
Name Affirmative Votes Negative Votes

Aleron H. Larson, Jr. 5,165,994 63,509
Roger A. Parker 5,165,994 63,509
Jerrie F. Eckelberger 5,165,994 63,509
Terry D. Enright 5,165,994 63,509

At the Annual Meeting the shareholders also voted to
ratify, approve and adopt an amendment to the Delta 1993
Incentive Plan, as amended, revising the compensation formula for
non-employee directors with 4,979,731 votes in the affirmative,
198,266 votes in the negative, 0 abstentions, and 0 votes
withheld for the proposition.

Also ratified, approved, and adopted was the appointment
of KPMG, LLP for our auditors for the year ended June 30, 1999
with 5,207,376 affirmative votes, 26,505 negative votes, 0
abstentions, and 0 votes withheld for the proposition.

ITEM 4A. DIRECTORS AND EXECUTIVE OFFICERS.

The following information with respect to Directors and
Executive Officers is furnished pursuant to Item 401(a) of
Regulation S-B.

Name Age Positions Period of Service

Aleron H. Larson, Jr. 54 Chairman of the Board, May 1987
Chief Executive Officer, to present
Secretary, Treasurer,
and a Director

Roger A. Parker 37 President and May 1987
a Director to present

Terry D. Enright 50 Director November 1987
to Present

Jerrie F. Eckelberger 55 Director September 1996
to Present

The following is biographical information as to the business
experience of each current officer and director of the Company.

Aleron H. Larson, Jr., age 54, 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, CEO 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
13.8% 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 Amber
Resources Company ("Amber"), a public oil and gas company which
is a majority-owned subsidiary 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. 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 37, 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
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, a Director and sole shareholder of Apex
Operating Company, Inc. since its inception in 1987. He has
operated as an independent in the oil and gas industry
individually and through public and private
ventures since 1982. He was at various times, from 1982 to 1989,
a Director, Executive Vice President, President and shareholder
of Ampet, Inc. He received a Bachelor of Science in Mineral
Land Management from the University of Colorado in 1983. He is a
member of the Rocky Mountain Oil and Gas Association and the
Independent Producers Association of the Mountain States (IPAMS).

Terry D. Enright, age 50, has been in the oil and gas
business since 1980. 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 55, is an investor, real estate
developer and attorney who has practiced law in the State of
Colorado for 28 years. He graduated from Northwestern University
with a Bachelor of Arts degree in 1966 and received his Juris
Doctor degree in 1971 from the University of Colorado School of
Law. From 1972 to 1975, Mr. Eckelberger was a staff attorney
with the eighteenth Judicial District Attorney's Office in
Colorado. From 1982 to 1992 Mr. Eckelberger was the senior
partner of Eckelberger & Feldman, a law firm with offices in
Englewood, Colorado. In 1992, Mr. Eckelberger founded
Eckelberger & Associates of which he is still the principal
member. Mr. Eckelberger previously served as an officer,
director and corporate counsel for Roxborough Development
Corporation. Since March 1996, Mr. Eckelberger has acted as
President and Chief Executive Officer of 1998, Ltd., a Colorado
corporation actively engaged in the development of real estate in
Colorado. He is the Managing Member of The Francis Companies,
L.L.C., a Colorado limited liability company, which actively
invests in real estate and has been since June, 1996.
Additionally, since November, 1997, Mr. Eckelberger
has served as the Managing Member of the Woods at Pole Creek, a
Colorado limited liability company, specializing in real estate
development.

There is no family relationship among or between any of the
Directors.

Messrs. Enright and Eckelberger serve as the Audit Committee
and as the Compensation Committee. Messrs. Enright and
Eckelberger also constitute the Incentive Plan Committee for the
Delta 1993 Incentive Plan for the Company.

All directors will hold office until the next annual meeting
of shareholders. There are no arrangements or understandings
among or between any director of the Company and any other person
or persons pursuant to which such director was or is to be
selected as a director.

All officers of the Company will hold office until the next
annual directors' meeting of the Company. There is no
arrangement or understanding among or between any such officer or
any person pursuant to which such officer is to be selected as an
officer of the Company.

PART II

ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

(a) Market Information.

Delta's common stock currently trades under the
symbol "DPTR" on NASDAQ. The following quotations reflect inter-
dealer high and low sales prices, without retail mark-up,
mark-down or commission and may not represent actual
transactions.

Quarter Ended High Low

September 30, 1997 4.00 2.88
December 31, 1997 3.88 1.66
March 31, 1998 3.13 2.06
June 30, 1998 4.44 3.13
September 30, 1998 3.19 1.63
December 31, 1998 2.50 1.50
March 31, 1999 3.00 1.75
June 30, 1999 2.75 1.75

On September 15, 1999, the closing price of the Common
Stock was $3.13.

(b) Approximate Number of Holders of Common Stock.

The number of holders of record of the Company's
Common Stock at September 15, 1999 was approximately 1,000 which
does not include an estimated 2,600 additional holders whose
stock is held in "street name".

We have not paid dividends on our stock and does
not expect to do so in the foreseeable future.

(d) Recent Sales of Unregistered Securities.

Unregistered securities sold within the last three
fiscal years in the following private transactions were exempt
from registration under the Securities Act of 1933 pursuant to
Section 4(2).

On December 20, 1996, we issued 63,000 shares of
common stock to SOCO Offshore, Inc., an affiliate of Snyder Oil
Corporation ("SOCO") in exchange for working interests in
undeveloped properties offshore Santa Barbara, California. The
transaction was recorded at the estimated fair market value of
the common stock issued based upon the quoted market price at the
time.

On December 23, 1997, we completed a sale of
156,950 shares of the Company s common stock to Evergreen
Resources, Inc. ("Evergreen"), another oil and gas company, for
net proceeds to the Company of $350,000.

During the year ended June 30, 1997, we issued
100,117 shares of our common stock in exchange for oil and gas
properties, for services, and in connection with a settlement
agreement. These transactions were recorded at the estimated
fair value of the common stock issued, which was based on the
quoted market price of the stock at the time of issuance.

On July 8, 1998, we completed a sale of 2,000
shares of our common stock to an unrelated individual for net
proceeds to the Company of $6,475.

On October 12, 1998, we issued 250,000 shares of
our common stock and 500,000 options to purchase our common stock
at various prices ranging from $3.50 to $5.00 per share to the
shareholders of an unrelated entity in exchange for two licenses
for exploration with the government of Kazakhstan.

On December 1, 1998, we issued 10,000 shares of our
common stock to an unrelated entity for public relation services.

On January 1, 1999, we completed a sale of 194,444
shares, of our common stock to Evergreen, another oil and gas
company, for net proceeds to us of $350,000.

During fiscal 1999, we issued 300,000 shares of our
common stock to Whiting Petroleum Corporation ("Whiting"), an
unrelated entity, along with a $1,000,000 deposit to acquire a
portion of Whiting's interest in the Point Arguello Unit, its
three platforms (Hidalgo, Harvest, and Hermosa), along with
Whiting's interest in the adjacent undeveloped Rocky Point Unit.
(See Item 2. Descriptions of Properties.)

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

Liquidity and Capital Resources.

At June 30, 1999 we had a working capital deficit of
$295,635 compared to a working capital deficit of $465,854 at
June 30, 1998.

Our current liabilities include royalties payable of
$127,166 at June 30, 1999 which represent our estimate of
royalties payable on production attributable to Amber's interest
in certain wells in Oklahoma, including production prior to the
acquisition of Amber. We believe that the operators of the
affected wells have paid some of the royalties on behalf of us
and have withheld such amounts from revenues attributable to our
interest in the wells. We have contacted the operators of the
wells in an attempt to determine what amounts the operators have
paid on behalf of us over the past five years, which amounts
would reduce the amounts owed by us. To date we have not
received information adequate to allow us to determine the
amounts paid by the operators. We have been informed by our
legal counsel that the applicable statute of limitations period
for actions on written contracts arising in the state of Oklahoma
is five years. The statute of limitation has expired for royalty
owners to make a claim for a portion of the estimated royalties
that had previously been accrued. Accordingly, these amounts
have been written off and recorded as other income in
1999 and 1998.

We believe 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. Further,
Amber, rather than Delta, would be directly liable for payment of
any such claims. We believe, although there can be no assurance,
that Amber may ultimately be able to settle with potential
claimants for less than the amounts recorded for royalties
payable.

We estimate our capital expenditures for onshore
properties to be approximately $1,000,000 for the year ended June
30, 2000. However, we are not obligated to participate in future
drilling programs and will not enter into future commitments to
do so unless management believes we have the ability to fund such
projects.

Our working interest share of the future estimated
development costs relating to our undeveloped offshore California
properties approximates $217 million. No significant amounts are
expected to be incurred during fiscal 2000 and $1.0 million and
$4.2 million are expected to be incurred during fiscal 2001 and
2002, respectively. The amounts required for development of
these undeveloped properties are so substantial relative to our
present financial resources, we may ultimately determine to
farmout all or a portion of its interest. If we were to farmout
our interests, our interest in the properties would be decreased
substantially. Alternatively, we may pursue other methods of
financing, including selling equity or debt securities. There
can be no assurance that we can obtain any such financing. If we
were to sell additional equity securities to finance the
development of the properties, the existing common shareholders'
interest would be diluted significantly.

On December 23, 1997, we completed a sale of 156,950
shares of our Common stock to Evergreen Resources, Inc., another
oil and gas company, for net proceeds to the Company of $350,000.

We received the proceeds from the exercise of options to
purchase shares of our common stock of $160,000 and $163,536
during the years ended June 30, 1999 and 1998, respectively.

On August 20, 1998, we entered into a loan agreement
with Labyrinth Enterprises, L.L.C., an unrelated entity, for
$400,000. The loan bore interest at the annual rate of 10% and
was collateralized by all producing oil and gas properties owned
by us and was paid in full in November 1998. In addition to the
principal and interest payment required, we paid a $50,000
origination fee. Our officers personally guaranteed this loan.

On May 24, 1999, we borrowed $1,000,000 at an annual
interest rate of 18% from our officers maturing on June 1, 2001.
We agreed to make monthly principal and interest payments of
$29,375 commencing on December 1, 1999 with the remaining
principal amount payable at the maturity date.

We expect to raise additional capital by selling our
common stock in order to fund our capital requirements for our
portion of the costs of the drilling and completion of
development wells on our undeveloped properties during the next
twelve months. We also expect to raise additional capital for
the acquisition of additional oil and gas properties. There is
no assurance that we will be able to do so or that we will be
able to do so upon terms that are acceptable. We do not
currently have a credit facility with any bank and we have not
determined the amount, if any, that we could borrow against our
existing properties. We will continue to explore additional
sources of both short-term and long-term liquidity to fund our
working capital deficit and our capital requirements for
development of our properties, including establishing a credit
facility, sale of equity or debt securities and sale of
non-strategic properties. Many of the factors which
may affect our future operating performance and liquidity are
beyond our control, including oil and natural gas prices and the
availability of financing.

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

Results of Operations

Net Earnings (Loss). The Company's net loss for the
year ended June 30, 1999 was $2,998,759 compared to the net loss
of $962,003 for the year ended June 30, 1998. The losses for the
years ended June 30, 1999 and 1998 were effected by numerous
items described in detail below.

Revenue. Total revenue for the year ended June 30, 1999
was $1,717,651 compared to $2,211,955 for the year ended June 30,
1998. Oil and gas sales for the year ended June 30, 1999 were
$557,503 compared to $1,225,115 for the year ended June 30,
1998. The decrease in oil and gas sales during the year ended
June 30, 1999 resulted from the sale of certain properties, which
resulted in a gain of $957,147, and the decrease in oil and gas
prices during fiscal 1999.

Production volumes and average prices received for the
years ended June 30, 1999 and 1998 are as follows:

1999 1998
Production:
Oil (barrels) 5,574 11,632
Gas (Mcf) 254,291 457,758

Average Price:
Oil (per barrel) $10.24 $16.46
Gas (per Mcf) $ 1.97 $ 2.26

Lease Operating Expenses. Lease operating expenses for
the year ended June 30, 1999 were $209,438 compared to $349,551
for the year ended June 30, 1998. On an Mcf equivalent basis,
production expenses and taxes were $.73 per Mcf equivalent during
the year ended June 30, 1999 compared to $.67 per Mcf equivalent
for the year ended June 30, 1998. The increase in lease
operating costs on an equivalent basis compared to 1998 resulted
primarily from the selling of lower operated properties.

Depreciation and Depletion Expense. Depreciation and
depletion expense for the year ended June 30, 1999 was $229,292
compared to $303,563 for the year ended June 30, 1998. On a Mcf
equivalent basis, the depletion rate was $.80 per Mcf equivalent
during the year ended June 30, 1999 compared to $.58 per Mcf
equivalent for the year ended June 30, 1998. The increase in
depreciation and depletion expense is a result of lower average
lives on newly drilled wells.

Exploration Expenses. Exploration expenses consist of
geological and geophysical costs and lease rentals. Exploration
expenses were $74,670 for the year ended June 30, 1999 compared
to $515,383 for the year ended June 30, 1998. The exploration
expenses during fiscal 1998 were abnormally high and primarily
represent costs associated with our participation in the shooting
of 3-D seismic on prospects in the Sacramento Basin of Northern
California.

Abandonment and Impairment of Oil and Gas Properties.
We recorded an expense for the abandonment and impairment of oil
and gas properties for the year ended June 30, 1999 of $273,041
compared to $128,993 in 1998. Our proved properties were
assessed for impairment on an individual field basis and we
recorded impairment provisions attributable to certain producing
properties of $103,230 and $128,993 for the years ended June 30,
1999 and 1998, respectively. The expense in 1999 also includes a
provision for impairment of the costs associated with the
Sacramento Basin of Northern California of $169,811. We made a
determination based on drilling results that it will not be
economical to develop certain prospects and as such we will not
proceed with these prospects.

General and Administrative Expenses. General and
administrative expenses for the year ended June 30, 1999 were
$1,506,683 compared to $1,433,461 for the year ended June 30,
1997.

Stock Option Expense. Stock option expense has been
recorded for the years ended June 30, 1999 and 1998 of $2,080,923
and $46,402, respectively, for options granted to certain
officers, directors, employees and consultants at option prices
below the market price at the date of grant. The most
significant amount of the stock option expense for fiscal 1999
can be attributed to a grant by the Incentive Plan Committee
("Committee") of options to purchase 89,686 shares of our common
stock and the repricing of 980,477 options to purchase shares of
our common stock for the two officers of the Company at a price
of $.05 per share under the Incentive Plan. The Committee also
repriced 150,000 options to purchase shares of our common stock
to two employees at a price of $1.75 per share under the
Incentive Plan. Stock option expense of $1,985,414 has been
recorded based on the difference between the option price and the
quoted market price on the date of grant and repricing of the
options.

Royalty to Related Party. The royalty to related party
represents the $350,000 paid in 1998 pursuant to the terms of the
agreement with Ogle to acquire interests in three undeveloped
offshore Santa Barbara, California federal oil and gas units. On
December 17, 1998, we amended our Purchase and Sale Agreement
with Burdette A. Ogle ("Ogle") dated January 3, 1995. As a
result of this amended agreement, at the time of each minimum
annual payment we will be assigned an interest in three
undeveloped offshore Santa Barbara, California, federal oil and
gas units proportionate to the total $8,000,000 production
payment. Accordingly, the annual $350,000 minimum payment has
been recorded as an addition to undeveloped offshore California
properties. In addition, pursuant to this agreement, we extended
and repriced a previously issued warrant to purchase 100,000
shares of our common stock. The $60,000 fair value placed on the
extension and repricing of this warrant was recorded as an
addition to undeveloped offshore California properties. As of
June 30, 1999, we have paid a total of $1,550,000 in minimum
royalty payments.

Year 2000

We have completed a review of our computer system and
applications (which began in fiscal 1997) to identify the systems
that could be affected by the "Year 2000" issue. The Year 2000
problem is the result of computer programs being written using
two digits rather than four to define the applicable year. Any
of our programs that have time-sensitive software may recognize a
date using "00" as the year 1900 rather than the year 2000. This
could result in a major system failure or miscalculations.

On the basis of our review, we currently believe that the
Year 2000 issue will not pose material operational problems for
the Company. To our knowledge, after investigation, no "embedded
technology" (such as microchips in an electronic control system)
of the Company poses a material Year 2000 concern.

Because we believe that we have no material internal Year
2000 problems, we have not and do not expect to expend a
significant amount of funds to address Year 2000 issues. It is
our policy to continue to review our suppliers' Year 2000
compliance and require assurance of Year 2000 compliance from new
suppliers; however, such monitoring does not involve a
significant cost to us.

In addition to the foregoing, we have contacted our major
vendors and have received either oral or written assurances from
our major vendors or have reviewed assurances contained on
vendors' web sites that they have no material Year 2000 problems.
We believe that our vendors are largely fungible; therefore, in
the event a vendor's representations regarding its Year 2000
compliance were untrue for any reason, we believe that we could
find adequate Year 2000-compliant vendors as substitutes.

We have also received either oral or written assurances from
our customers or have reviewed assurances contained on our
customers' web sites that they have no Year 2000 problems which
would materially adversely affect the business or operations of
the Company.

The information contained in this Year 2000 discussion is
forward-looking and involves risks and uncertainties that may
cause actual results to vary materially from those projected.
Some factors that could significantly impact our expected Year
2000 compliance and the estimated cost thereof include internal
computer hardware or software problems which have not as yet been
identified by us, and currently undisclosed and unanticipated
problems which may be encountered by third parties with whom
Delta has business relationships.

Recently Issued or Proposed Accounting Standards and
Pronouncements

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, 2000. The Company has not
assessed the impact, if any, that SFAS 133 will have on its
financial statements.

The Financial Accounting Standards Board issued an exposure
draft of the proposed interpretation, Accounting for Certain
Transactions involving Stock Compensation: an interpretation of
APB Opinion 25 on March 31, 1999. The exposure draft addresses
outstanding practice issues relating to stock based compensation
including but not limited too, option repricing, independent
directors and contractors, vesting changes and plan
modifications. The exposure draft if adopted as currently
released would require prospective adoption for all events
subsequent to December 15, 1998. The Company has not completed a
full assessment of the impact o the exposure draft on its
consolidated financial statement. However, if the exposure draft
is adopted as currently released, the Company would be required
to account for a signification portion of their stock options
outstanding under variable plan accounting and as such a
compensation charge would be recognized in the financial
statements as the Companies stock price fluctuated.

ITEM 7. FINANCIAL STATEMENTS

Financial Statements are included herein beginning on
page F-1.

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

Not applicable.

PART III

The information required by Part III, Items 9
"Compliance with Section 16(a) of the Exchange Act", 10
"Executive Compensation", 11 "Security Ownership of Certain
Beneficial Owners and Management", and 12 "Certain Relationships
and Related Transactions", is incorporated by reference to
Registrant's definitive Proxy Statement which will be filed with
the Securities and Exchange Commission in connection with the
Annual Meeting of Shareholders. For information concerning Item
9 "Directors and Executive Officers"; see Part I; Item 4A.

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits.

The Exhibits listed in the Index to Exhibits
appearing at Page 37 filed as part of this report.

(b) Reports on Form 8-K.

Form 8-K dated October 16, 1998; Items 5 & 7.
Form 8-K dated November 23, 1998; Items 2 & 7.
Form 8-K dated June 9, 1999; Items 5 & 7.
Form 8-K dated August 25, 1999; Items 5 & 7.

FORWARD-LOOKING STATEMENTS

This Form 10-KSB contains forward-looking statements within
meaning of section 27A of the Securities Act of 1933 and section
21E of the Securities Exchange Act of 1934, including statements
regarding, among other items, our growth strategies, anticipated
trends in our business and our future results of operations,
market conditions in the oil and gas industry, the status of
and/or future expectations for our offshore properties, our
ability to make and integrate acquisitions and the outcome of
litigation and the impact of governmental regulation. These
forward-looking statements are based largely on our expectations
and are subject to a number of risks and uncertainties, many of
which are beyond our control. Actual results could differ
materially from these forward-looking statements as a result of,
among other things:

* a decline in oil and/or gas production or prices,

* incorrect estimates of required capital expenditures,

* increases in the cost of drilling, completion and gas
collection or other costs of production and operations,

* an inability to meet growth projections, and

* other risk factors discussed or not discussed herein.

In addition, the words "believe", "may", "will", "estimate",
"continue", "anticipate", "intend", "expect" and similar
expressions, as they relate to Delta, our business or our
management, are intended to identify forward-looking statements.

We undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new
information, future events or otherwise after the date of this
Form 10-KSB. In light of these risks and uncertainties, the
forward-looking events and circumstances discussed in this
document may not occur and actual results could differ materially
from those anticipated or implied in the forward-looking
statements.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, we have caused this report to be
signed on our behalf by the undersigned, who are authorized to
do so.

(Registrant) DELTA PETROLEUM CORPORATION

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

Aleron H. Larson, Jr., Secretary,
Chairman of the Board, Treasurer
and Principal Financial Officer

By (Signature and Title) s/Kevin K. Nanke

Kevin K. Nanke, Controller and
Principal Accounting Officer

Pursuant to the requirements of the Securities Exchange Act
of 1934, this report has been signed below by the following
persons on our behalf and in the capacities and on the dates
indicated.

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

Date 09/27/99

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

Date 09/27/99

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

Date 09/27/99

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

Date 09/27/99

INDEX TO EXHIBITS

2. Plans of Acquisition, Reorganization, Arrangement,
Liquidation, or Succession.
Not applicable.

3. Articles of Incorporation and By-laws. The Articles of
Incorporation and Articles of Amendment to Articles of
Incorporation and By-laws of the Registrant were filed
as Exhibits 3.1, 3.2, and 3.3, respectively, to the
Registrant's Form 10 Registration Statement under the
Securities and Exchange Act of 1934, filed September 9,
1987, with the Securities and Exchange Commission and
are incorporated herein by reference.

4. Instruments Defining the Rights of Security Holders.
Statement of Designation and Determination of
Preferences of Series A Convertible Preferred Stock of
Delta Petroleum Corporation is incorporated by Reference
to Exhibit 28.3 of the Current Report on Form 8-K dated
June 15, 1988. Statement of Designation and Determination
of Preferences of Series B Convertible Preferred Stock of
Delta Petroleum Corporation is incorporated by reference
to Exhibit 28.1 of the Current Report on Form 8-K dated
August 9, 1989. Statement of Designation and
Determination of Preferences of Series C Convertible
Preferred Stock of Delta Petroleum Corporation is
incorporated by reference to Exhibit 4.1 of the current
report on Form 8-K dated June 27, 1996.

9. Voting Trust Agreement. Not applicable.

10. Material Contracts.

10.1 Agreement effective October 28, 1992 between Delta
Petroleum Corporation, Burdette A. Ogle and Ron Heck.
Incorporated by reference from Exhibit 28.2 to the
Company's Form 8-K dated December 4, 1992.

10.2 Option Amendment Agreement effective March 30, 1993.
Incorporated by reference from Exhibit 28.2 to the
Company's Form 8-K dated April 14, 1993.

10.3 Agreement between Delta Petroleum Corporation and
Burdette A. Ogle dated February 24, 1994 for offshore
Santa Barbara California Federal oil and gas units.
Incorporated by reference from Exhibit 28.1 to the
Company's Form 8-K dated February 25, 1994.

10.4 Addendum to agreement dated February 24, 1994 between
Delta Petroleum Corporation and Burdette A. Ogle for offshore
Santa Barbara California Federal oil and gas units. Incorporated
by reference from Exhibit 28.1 to the Company's Form 8-K dated
May 24, 1994.

10.5 Addendum #2 to agreement dated February 24, 1994 between
Delta Petroleum Corporation and Burdette A. Ogle for offshore
Santa Barbara California Federal oil and gas units. Incorporated
by reference from Exhibit 28.2 to the Company's Form 8-K dated
July 15, 1994.

10.6 Addendum #3 to agreement dated February 24, 1994 between
Delta Petroleum Corporation and Burdette A. Ogle. Incorporated by
reference from Exhibit 28.3 to the Company's Form 8-K dated
August 9, 1994.

10.7 Addendum #4 to agreement dated February 24, 1994 between
Delta Petroleum Corporation and Burdette A. Ogle for offshore
Santa Barbara California Federal oil and gas units. Incorporated
by reference from Exhibit 28.1 to the Company's Form 8-K dated
August 31, 1993.

10.8 Burdette A. Ogle "Assignment, Conveyance and Bill of
Sale of Federal Oil and Gas Leases Reserving a Production
Payment", "Lease Interests Purchase Option Agreement" and
"Purchase and Sale Agreement". Incorporated by reference from
Exhibit 28.1 to the Company's Form 8-K dated January 3, 1995.

10.9 Agreement with Bion Environmental Technologies, Inc.
dated June 26, 1995 including an agreement to convert a portion
of a promissory note to common stock and a stock voting agreement
in favor of the Company's President and Chairman.
Incorporated by reference to Exhibit 99.3 to the Company's
Form 8-K dated August 18, 1995.

10.10 Agreement with Howard Jenkins dated July 20, 1995 for
purchase of warrant. Incorporated by reference to Exhibit 99.6
to the Company's Form 8-K dated August 18, 1995.

10.11 Agreement with LoTayLingKyur, Inc. dated June 29, 1995
relating to note extension and option grant. Incorporated by
reference to Exhibit 99.9 to the Company's Form 8-K dated
August 18, 1995.

10.12 Copies of Aleron H. Larson, Jr. and Roger A. Parker
Employment Agreements, previously filed on Form 10-KSB for the
fiscal year ended June 30, 1998.

10.13 Letter agreement (without exhibits) with Slawson
Exploration Company, Inc. dated September 30, 1996 for an
interest in the West Orion prospect. Incorporated by reference
from Exhibit 99.3 to the Company's Form 8-K dated October 10,
1996.

10.14 Delta Petroleum Corporation 1993 Incentive Plan, as
amended. Incorporated by reference from Exhibit 99.1 to the
Company's Form 8-K dated November 1, 1996.

10.15 Letter agreement (without exhibits) with Slawson
Exploration Company, Inc. dated February 10, 1997 for an interest
in the Bali prospect. Incorporated by reference from Exhibit
99.1 to the Company's Form 8-K dated March 3, 1997.

10.16 Letter agreement (without exhibits) with Slawson
Exploration Company, Inc. dated February 12, 1997 for an interest
in the Fiji prospect. Incorporated by reference from Exhibit
99.2 to the Company's Form 8-K dated March 3, 1997.

10.17 Letter agreement (without exhibits) with KCS Resources,
Inc., a subsidiary of KCS Energy and doing business as KCS
Mountain Resources, Inc. Incorporated by reference from Exhibit
99.1 to the Company's Form 8-K dated April 24, 1997.

10.18 Agreement among Eva H. Posman, as Chapter 11 Trustee of
Underwriters Financial Group, Inc., Snyder Oil Corporation and
Delta Petroleum Corporation. Incorporated by reference from
Exhibit 99.1 to the Company's Form 8-K dated May 23, 1997.

10.19 Option and First Right of Refusal between Evergreen
Resources, Inc., and Delta Petroleum Corporation dated December
23, 1997, previously filed on Form 10-KSB for the fiscal year
ended June 30, 1998.

10.20 Professional Services Agreement with GlobeMedia AG and
Investment Representation Agreements with GlobeMedia AG,
incorporated by reference from Exhibits 99.2 and 99.3 to the
Company's Form 8-K dated April 9, 1998.

10.21 Delta Petroleum Corporation 1993 Incentive Plan, as
amended June 30, 1999. Incorporated by reference to the
Company's Notice of Annual Meeting and Proxy Statement dated June
1, 1999.

10.22 Agreement between Evergreen Resources, Inc., and Delta
Petroleum Corporation effective January 1, 1999. Incorporated
by reference from Exhibit 99.1 to the Company's Form 10-QSB
for the quarterly period ended December 31, 1998.

10.23 Agreement between Burdette A. Ogle and Delta Petroleum
Corporation effective December 17, 1998. Incorporated by
reference from Exhibit 99.2 to the Company's Form 10-QSB for
the quarterly period ended December 31, 1998.

10.24 Agreement between Anadarko Minerals, Inc., and Delta
Petroleum Corporation dated October 29, 1998. Incorporated by
reference from Exhibit 99.1 to the Company's Form 8-K dated
November 23, 1998.

10.25 Agreement between Delta Petroleum Corporation and Ambir
Properties, Inc., dated October 12, 1998. Incorporated by
reference from Exhibit 99.1 to the Company's Form 8-K dated
October 16, 1998.

10.26 Agreement between Whiting Petroleum corporation and
Delta Petroleum Corporation (including amendment) dated June 8,
1999. Incorporated by reference from Exhibit 99.1 to the
Company's Form 8-K dated June 9, 1999.

10.27 Promissory Note dated May 24, 1999. Incorporated by
reference from Exhibit 99.2 to the Company's Form 8-K dated June
9, 1999.

10.28 Promissory Note dated July 30, 1999. Incorporated by
reference from Exhibit 99.1 to the Company's Form 8-K dated
August 25, 1999.

10.29 Guarantee of Payment and Performance of Roger A. Parker
dated August 1, 1999. Incorporated by reference from Exhibit
99.2 to the Company's Form 8-K dated August 25, 1999.

10.30 Guarantee of Payment and Performance of Aleron H.
Larson, Jr. dated August 1, 1999. Incorporated by reference from
Exhibit 99.3 to the Company's Form 8-K dated August 25, 1999.

10.31 Agreement between Delta Petroleum Corporation and Roger
A. Parker and Aleron H. Larson, Jr. dated July 30, 1999.
Incorporated by reference from Exhibit 99.4 to the Company's
Form 8-K dated August 25, 1999.

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 Principles. 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.

23.1 Consent of KPMG LLP, filed herewith electronically.

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
Delta Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of
Delta Petroleum Corporation (the Company) and subsidiary as of
June 30, 1999 and 1998 and the related consolidated statements of
operations, stockholders' equity, 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 consolidated financial statements referred to
above present fairly, in all material respects, the financial
position of Delta Petroleum Corporation and subsidiary as of June
30, 1999 and 1998 and the results of their operations and their
cash flows for the years then ended, in conformity with generally
accepted accounting principles.

s/KPMG LLP
KPMG LLP

Denver, Colorado
September 21, 1999

DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
June 30, 1999 and 1998

1999 1998

ASSETS

Current Assets:
Cash $ 99,545 17,135
Trade accounts receivable, net of
allowance for doubtful accounts
of $50,000 in 1999 and 1998 113,841 224,285
Accounts receivable - related parties 116,855 127,415
Other current assets 10,100 10,100

Total current assets 340,341 378,935

Property and Equipment:
Oil and gas properties, at cost (using
the successful efforts method
of accounting) (Note 7 and 9):
Undeveloped offshore California properties 7,369,830 6,959,830
Undeveloped onshore domestic properties 506,363 726,127
Undeveloped foreign properties 623,920 -
Developed onshore domestic properties 2,231,187 3,369,881
Office furniture and equipment 82,489 80,446
10,813,789 11,136,284

Less accumulated depreciation and depletion (1,650,228) (2,234,525)

Net property and equipment 9,163,561 8,901,759

Investment in Bion Environmental 257,180 1,069,149

Deposit on purchase of oil and gas properties 1,616,050 -

$11,377,132 10,349,843

1999 1998

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities:
Accounts payable trade $ 393,542 570,469
Other accrued liabilities 10,000 10,000
Royalties payable 127,166 264,320
Note payable to related party-current (Note 3) 105,268 -

Total current liabilities 635,976 844,789

Note payable to related party (Note 3) 894,732 -

Stockholders' Equity (Note 4):
Preferred stock, $.10 par value;
authorized 3,000,000 shares, none issued - -
Common stock, $.01 par value;
authorized 300,000,000 shares, issued 6,390,302
shares in 1999 and 5,513,858 shares in 1998 63,903 55,139
Additional paid-in capital 29,476,275 25,571,921
Accumulated other comprehensive
income (loss) (Note 2) (115,395) 457,594
Accumulated deficit (19,578,359) (16,579,600)

Total stockholders' equity 9,846,424 9,505,054

Commitments (Note 8)
$11,377,132 10,349,843

DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended June 30, 1999 and 1998

1999 1998

Revenue:
Oil and gas sales $ 557,503 1,225,115
Gain on sale of oil and gas properties 957,147 650,417
Other revenue 203,001 288,083

Total revenue 1,717,651 2,163,615

Operating expenses:
Lease operating expenses 209,438 349,551
Depreciation and depletion 229,292 303,563
Exploration expenses 74,670 515,383
Abandoned and impaired properties 273,041 128,993
Dry hole costs 226,084 46,605
Royalty to related party (Note 7) - 350,000
General and administrative 1,506,683 1,433,461
Stock option expense 2,080,923 46,402

Total operating expenses 4,600,131 3,173,958

Loss from operations (2,882,480) (1,010,343)

Other income and expenses:
Interest expense (19,726) -
Gain/(loss) on sale of securities available
for sale (96,553) 48,340

Total other income and expenses (116,279) 48,340

Net loss $(2,998,759) (962,003)

Basic and diluted loss per common share $ (0.51) (0.18)

Weighted average number of common
shares outstanding 5,854,758 5,361,900

DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Consolidated Statement of Stockholders' Equity
Years ended June 30, 1999 and 1998

<TABLE>
Additional
Common Stock paid-in
Shares Amount capital

<S> <C> <C> <C>
Balance, July 1, 1997 5,230,631 $ 52,306 24,950,128

Comprehensive income:
Net loss - - -
Other comprehensive income, net of tax
Unrealized gain on equity securities - - -
Less: Reclassification adjustment for gains included
in net loss - - -
Comprehensive income - - -
Stock options granted as compensation - - 46,402
Shares issued for cash upon exercise of options 114,100 1,141 202,395
Shares issued for cash 156,950 1,570 348,430
Shares issued for services 22,500 225 64,463
Shares reacquired and retired (10,323) (103) (39,897)

Balance, June 30, 1998 5,513,858 55,139 25,571,921

Comprehensive income:
Net loss - - -
Other comprehensive income, net of tax
Unrealized loss on equity securities - - -
Less: Reclassification adjustment for losses included
in net loss - - -
Comprehensive income - - -
Stock options granted as compensation - - 2,081,423
Shares issued for cash upon exercise of options 120,000 1,200 158,800
Shares issued for cash 196,444 1,964 354,011
Shares issued for services 10,000 100 15,650
Shares issued for oil and gas properies 250,000 2,500 621,420
Shares issued for deposit on oil and gas properies 300,000 3,000 613,050
Fair value of warrant extended and repriced - - 60,000

Balance, June 30, 1999 6,390,302 $ 63,903 29,476,275

</TABLE>

<TABLE>
Accumulated
other
comprehensive
income Comprehensive Accumulated
(loss) Income deficit Total

<S> <C> <C> <C> <C>
Balance, July 1, 1997 (213,969) (15,617,597) 9,170,868

Comprehensive income: (962,003) (962,003) (962,003)
Net loss
Other comprehensive income, net of tax
Unrealized gain on equity securities 719,903
Less: Reclassification adjustment for gains included
in net loss (48,340) 671,563 671,563
Comprehensive income (290,440)
Stock options granted as compensation - - 46,402
Shares issued for cash upon exercise of options - - 203,536
Shares issued for cash - - 350,000
Shares issued for services - - 64,688
Shares reacquired and retired - - (40,000)

Balance, June 30, 1998 457,594 (16,579,600) 9,505,054

Comprehensive income:
Net loss (2,998,759) (2,998,759) (2,998,759)
Other comprehensive income, net of tax
Unrealized loss on equity securities (669,542) -
Less: Reclassification adjustment for losses included
in net loss 96,553 (572,989) (572,989)
Comprehensive income (3,571,748)
Stock options granted as compensation - - 2,081,423
Shares issued for cash upon exercise of options - - 160,000
Shares issued for cash - - 355,975
Shares issued for services - - 15,750
Shares issued for oil and gas properies - - 623,920
Shares issued for deposit on oil and gas properies - - 616,050
Fair value of warrant extended and repriced - - 60,000

Balance, June 30, 1999 (115,395) (19,578,359) 9,846,424

DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended June 30, 1999 and 1998

1999 1998

Cash flows operating activities:
Net loss $(2,998,759) (962,003)
Adjustments to reconcile net loss to cash used in
operating activities:
Gain on sale of oil and gas properties (957,147) (650,417)
Write-off royalties payable (137,154) (204,648)
(Gain) Loss on sale of securities available for
sale 96,553 (48,340)
Depreciation and depletion 229,292 303,563
Abandoned and impaired properties 273,041 128,993
Common stock issued for services 15,750 64,688
Stock option expense 2,080,923 46,402
Bad debt expense - 29,754
Net changes in operating assets and
and operating liabilities:
Decrease in trade accounts receivable 84,432 36,566
Decrease in other current assets - -
Decrease in accounts payable trade (176,927) (206,233)
Decrease in other accrued liabilities - (11,835)

Net cash used in operating activities (1,489,996) (1,473,510)

Cash flows from investing activities:
Additions to property and equipment (507,068) (628,387)
Deposit on purchase of oil and gas properties (1,000,000) - -
Proceeds from sale of securities available for
sale 174,602 197,012
Proceeds from sale of oil and gas properties 1,384,000 1,023,432
Net cash provided by investing activities 51,534 592,057

Cash flows from financing activities:
Stock issued for cash upon exercise of options 160,000 163,536
Issuance of common stock for cash 356,475 350,000
Borrowings from related parties 1,000,000 -
Increase in borrowing 400,000 -
Payment of borrowing (400,000) -
Decrease (increase) in accounts receivable from
related parties 4,397 (7,996)
Net cash provided by financing activities 1,520,872 505,540

Net increase (decrease) in cash 82,410 (375,913)

Cash at beginning of year 17,135 393,048

Cash at end of year $ 99,545 17,135

Supplemental cash flow information -
Cash paid for interest $ 19,726 -

Non-cash financing activities:
Common stock and options issued for oil and
gas properties $ 683,920 -
Common stock issued for deposit on purchase
of oil and gas properties $ 616,050 -

See accompanying notes to consolidated financial statements.

DELTA PETROLEUM CORPORATION
AND SUBSIDIARY

Notes to Consolidated Financial Statements
June 30, 1999 and 1998

(1) Summary of Significant Accounting Policies

Organization and Principles of Consolidation

Delta Petroleum Corporation ("Delta") was organized December
21, 1984 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 and undeveloped oil and gas properties in the
continental United States. In addition, the Company owns
interests in undeveloped properties in Kazakhstan.

At June 30, 1999, the Company owned 4,277,977 shares of the
common stock of Amber Resources Company ("Amber"),
representing 91.68% of the outstanding common stock of Amber.
Amber is a public company also engaged in acquiring,
exploring, developing and producing oil and gas properties.

The consolidated financial statements include the accounts of
Delta and Amber (collectively, the Company). All
intercompany balances and transactions have been eliminated
in consolidation.

Liquidity

The Company has incurred losses from operations over the past
several years coupled with significant deficiencies in cash
flow from operations for the same period. As of June 30,
1999, the Company had a working capital deficit of $295,635.
These factors among others may indicate that without
increased cash flow from operations, sale of oil and gas
properties or additional financing the Company may not be
able to meet its obligation in a timely manner.

One aspect of the Company's business activities has been the
buying and selling of oil and gas properties. In the past
the Company has sold properties to fund its working capital
deficits and/or its funding needs. Recently, the Company has
taken steps to reduce losses and generate cash flow from
operations through the pending acquisition of producing oil
and gas properties (see Note 11) which management believes
will generate sufficient cash flow to meet its obligations in
a timely manner. Should the Company be unable to achieve its
projected cash flow from operations additional financing or
sale of oil and gas properties could be necessary. The
Company believes that it could sell oil and gas properties or
obtain additional financing, however, there can be no
assurance that such financing would be available on a timely
basis or acceptable terms.

Cash Equivalents

Cash equivalents consist of money market funds. For purposes
of the statements of cash flows, the Company considers all
highly liquid investments with maturities at date of
acquisition of three months or less to be cash equivalents.

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.

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. Capitalized costs of
unproved properties are assessed periodically and a
provision for impairment is recorded, if necessary, through
a charge to operations.

Furniture and equipment are depreciated using the straight-
line method over estimated lives ranging from three to five
years.

Impairment of Long-Lived Assets

Statement of Financial Accounting Standards 121 "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of" (SFAS 121) 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.

Impairment of Long-Lived Assets

Estimates of expected future cash flows 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
impairment provisions attributable to certain producing
properties of $103,230 and $128,993 for the years ended June
30, 1999 and 1998, respectively.

The Company's undeveloped properties were assessed for
impairment on an individual field basis and the Company
recorded impairment provisions attributed to certain
undeveloped onshore properties of $169,811 for the year
ended June 30, 1999.

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 the related estimated remaining
reserves. Thereafter, additional amounts received are
recorded as a liability.

As of June 30, 1999, the Company had produced and recognized
as revenue approximately 19,000 Mcf more than its entitled
share of production. The undiscounted value of this
imbalance is approximately $43,000 using the lower of the
price received for the natural gas, the current market price
or the contract price, as applicable.

Royalties Payable

Recoupment gas royalties, included in royalties payable,
represent estimated royalties due on recoupment gas produced
and delivered to the gas purchaser pursuant to the terms of
a recoupment agreement. 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 has 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 amounts
have been written off and recorded as other income in 1999
and 1998.

Comprehensive Income

Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 130, Reporting
Comprehensive Income establishes standards for reporting and
display of comprehensive income and its components in a full
set of general-purpose financial statements. The Company
adopted Statement No. 130 effective July 1, 1998 and,
accordingly, has reported accumulated other comprehensive
income (loss) as a separate line item in the stockholders'
equity section of its consolidated balance sheets.

Stock Option Plans

The Company accounts for its stock option plans in
accordance with the provisions of Accounting Principles
Board ("APB") Opinion No. 25, Accounting for Stock Issued
to Employees, and related interpretations. As such,
compensation expense was recorded on the date of grant only
if the current market price of the underlying stock exceeded
the exercise price. The Company adopted the disclosure requirement of
SFAS No. 123, Accounting for Stock-Based Compensation and provides pro
forma net income (loss) and pro forma earnings (loss) per
share disclosures for employee stock option grants made in
1995 and future years as if the fair-value based method
defined in SFAS No. 123 had been applied.

Income Taxes

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

Earnings (Loss) per Share

Basic earnings (loss) per share is computed by dividing net
earnings (loss) attributes to common stock by the weighted
average number of common shares outstanding during each
period, excluding treasury shares. Diluted earnings (loss)
per share is computed by adjusting the average number of
common share outstanding for the dilative effect, if any, of
convertible preferred stock, stock options and warrant. The
effect of potentially dilative securities outstanding were
antidilutive in 1999 and 1998.

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 revenues
and expenses during the reporting period. Actual results
could differ from these estimates.

Recently Issued Accounting Standards and Pronouncements

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, 2000. The Company has not assessed the impact, if any,
that SFAS 133 will have on its financial statements.

Reclassifications

Certain amounts in the 1998 financial statements have been
reclassified to conform to the 1999 financial statement
presentation.

(2) Investment

The Company's investment in Bion Environmental Technologies,
Inc. ("Bion") is classified as an available for sale
security and reported at its fair market value, with
unrealized gains and losses excluded from earnings and
reported as accumulated comprehensive income (loss), a
separate component of stockholders' equity. During fiscal
1999 and 1998 the Company received an additional 10,249 and
40,747 shares, respectively, of Bion's common stock for rent
and other services provided by the Company. The Company
realized a loss of $96,553 for the year ended June 30, 1999
and gain of $48,340 for the year ended June 30, 1998 on the
sale of securities available for sale.

The cost and estimated market value of the Company's
investment in Bion at June 30, 1999 and 1998 are as follows:

Estimated
Unrealized Market
Cost Gain/(Loss) Value

1999 $372,575 (115,395) 257,180

1998 611,555 457,594 1,069,149

As of September 15, 1999, the estimated market value of the
Company's investment in Bion, based on the quoted bid price
of Bion's common stock, was approximately $250,000.

(3) Note Payable to Related Party

On May 24, 1999, the Company borrowed $1,000,000 at 18% per
annum from the Company's officers maturing on June 1, 2001.
The Company agreed to make monthly payments of interest only
for the first six months and then monthly principal and
interest payments of $29,375 through June 1, 2001 with the
remaining principal amount payable at the maturity date.

(4) Stockholders Equity

Preferred Stock

The Company has 3,000,000 shares of preferred stock
authorized, par value $.10 per share, issuable from time to
time in one or more series, as of June 30, 1999 and 1998, no
preferred stock was issued.

Common Stock

On December 23, 1997 and again on January 1, 1999, the
Company completed a sale of 156,950 and 194,444 shares,
respectively, of the Company s Common stock to another oil
company for net proceeds for each issuance to the Company of
$350,000.

On July 8, 1998, the Company completed a sale of 2,000 shares
of the Company's common stock to an unrelated individual for
net proceeds to the Company of $6,475.

During the year ended June 30, 1998, the Company issued
22,500 shares of the Company's common stock to a former
employee as a part of a severance package. This transaction
was recorded at its estimated fair market value of the common
stock issued of approximately $65,000, which was based on the
quoted market price of the stock at the time of issuance. The
Company also agreed to forgive approximately $20,000 in debt
owed to the Company by the former employee.

On October 12, 1998, the Company issued 250,000 shares of the
Company's common stock and 500,000 options to purchase the
Company's common stock at various prices ranging from $3.50
to $5.00 per share to the shareholders of an unrelated entity
in exchange for two licenses for exploration with the
government of Kazakhstan.

During fiscal 1999, the Company issued 300,000 shares of the
Company's common stock to an unrelated entity, along with a
$1,000,000 refundable deposit to acquire a portion of an
interest in the offshore California Point Arguello Unit, its
three platforms (Hidalgo, Harvest, and Hermosa), along with
an interest in the adjacent undeveloped Rocky Point Unit.

The Company received proceeds from the exercise of options to
purchase shares of its common stock of $160,000 during the
year ended June 30, 1999 and $163,536 during the year ended
June 30, 1998.

In addition during the years ended June 30, 1999 and 1998,
the Company issued shares of its common stock in exchange for
oil and gas properties and for services. These transactions
were recorded at the estimated fair value of the common stock
issued, which was based on the quoted market price of the
stock at the time of issuance.

Non-Qualified Stock Options

Under its 1993 Incentive Plan (the "Incentive Plan") the
Company has reserved the greater of 500,000 shares of common
stock or 20% of the issued and outstanding shares of common
stock of the Company on a fully diluted basis. Incentive
awards under the Incentive Plan may include non-qualified or
incentive stock options, limited appreciation rights, tandem
stock appreciation rights, phantom stock, stock bonuses or
cash bonuses. Options issued to date have been non-qualified
stock options as defined in the Incentive Plan.

A summary of the Plan's stock option activity and related
information for the years ended June 30, 1999 and 1998 are as
follows:

1999 1998

Weighted- Weighted-
Average Average
Exercise Exercise
Options Price Options Price

Outstanding-beginning
of year 1,162,977 $2.25 1,262,077 $3.25

Granted 477,186 1.43 15,000 1.88

Exercised - - (114,100) 1.78

Repriced 2,110,954 .68 1,621,054 2.47

Returned for
repricing (2,110,954) (1.47) (1,621,054) (3.27)

Outstanding-end
of year 1,640,163 $1.05 1,162,977 $2.25

Exercisable at
end of year 1,385,163 $2.32 1,132,977 $2.27

Exercise prices for options outstanding under the plan as of
June 30, 1999 ranged from $0.05 to $9.75 per share. The
weighted-average remaining contractual life of those options
is 8.95 years. A summary of the outstanding and exercisable
options at June 30, 1999, segregated by exercise price
ranges, is as follows:

Weighted-
Average
Weighted- Remaining Weighted-
Exercise Average Contractual Average
Price Options Exercise Life Exercisable Exercise
Range Outstanding Price (in years) Options Price

$0.05 - $3.25 1,500,163 $0.52 9.07 1,385,163 $0.38

$3.26 - $9.75 140,000 6.74 7.31 - -

1,640,163 $1.05 8.95 1,385,163 $0.38

Proforma information regarding net income (loss) and earnings
(loss) per share is required by Statement of Financial
Accounting Standards 123 which requires that the information
be determined as if the Company has accounted for its employee
stock options granted under the fair value method of that
statement. The fair value for these options was estimated at
the date of grant using a Black-Scholes option pricing model
with the following weighted-average assumptions for the years
ended June 30, 1999 and 1998, respectively, risk-free interest
rate of 5.5% and 6.0%, dividend yields of 0% and 0%,
volatility factors of the expected market price of the
Company's common stock of 56.07% and 44.35%, and a weighted-
average expected life of the options of 6.6 and 6.0 years.

The Company applies APB Opinion 25 and related Interpretations
in accounting for its plans. Accordingly, no compensation
cost is recognized for options granted at a price equal or
greater to the fair market value of the common stock. Had
compensation cost for the Company's stock-based compensation
plan been determined using the fair value of the options at
the grant date, the Company's net loss for the years ended
June 30, 1999 and 1998, would have been $2,242,511 and
$1,333,745, and basic loss per common share would have been
$.38 and $.25 per share, respectively.

During the year ended, June 30, 1998, the Company s president
exercised options to purchase 32,000 shares of the Company's
common stock. Payment for the shares of common stock
purchased upon exercise of the option was made in shares of
the Company s common stock previously owned by the Company s
president, valued at the market price on the date of exercise.
The Company recorded the 10,323 shares of the Company s common
stock reacquired at cost, which shares were subsequently
retired.

Stock Options and Warrants

In addition to options outstanding under the Company's
Incentive Plan, the following options and warrants were
outstanding at June 30, 1999:

Number Exercise Expiration
Outstanding Price Date

7,000 $ 1.25 05/20/00
20,000 3.50 06/09/03
25,000 2.13 02/11/01
50,000 6.00 - (1)
50,000 6.00 - (2)
62,500 6.13 11/06/00
100,000 3.00 08/31/04
380,000 1.25-5.50 12/31/99
500,000 3.50-5.00 10/09/03

(1) The 50,000 options granted at $6.00 expire on the
later of the original expiration date or one year after
registration of the underlying shares.

(2) The 50,000 options granted at $6.00 expire on the
later of the original expiration date or thirty days after
registration of the underlying shares.

(5) Employee Benefits

The Company sponsors a qualified tax deferred savings plan in
the form of a Savings Incentive Match Plan for Employees
("SIMPLE") IRA plan (the "Plan") available to companies with
fewer than 100 employees. Under the Plan, the Company's
employees may make annual salary reduction contributions of up
to 3% of an employee's base salary up to a maximum of $6,000
(adjusted for inflation) on a pre-tax basis. The Company will
make matching contributions on behalf of employees who meet
certain eligibility requirements. During the fiscal years
ended June 30, 1999 and 1998, the Company contributed $16,631
and $24,304 under the Plan.

(6) Income Taxes

At June 30, 1999 and 1998, the Company s significant deferred
tax assets and liabilities are summarized as follows:

1999 1998
Deferred tax assets:
Net operating loss
carryforwards $8,163,000 7,999,000
Allowance for doubtful
accounts not deductible
for tax purposes 19,000 19,000
Oil and gas properties,
principally due to
differences in basis and
depreciation and depletion 1,058,000 2,206,000
Gross deferred tax assets 9,240,000 10,224,000

Less valuation allowance ( 9,240,000) (10,224,000)

Net deferred tax asset $ - -

No income tax benefit has been recorded for the years
ended June 30, 1999 and 1998 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, 1999, the Company had net operating loss
carryforwards for regular and alternative minimum tax
purposes of approximately $22,952,000 and $21,552,000. If
not utilized, the tax net operating loss carryforwards
will expire during the period from 2000 through 2019. If
not utilized, approximately $2.4 million of net operating
losses will expire over the next five years. Net
operating loss carryforwards
attributable to Amber prior to 1993 of approximately
$2,676,000, included in the above amounts are available
only to offset future taxable income of Amber and are
further limited to approximately $475,000 per year,
determined on a cumulative basis.

(7) Related Party Transactions

Transactions with Officers

On May 20, 1999, the Company Incentive Plan Committee
granted options to purchase 89,686 shares of the
Company's common stock and repriced 980,477 options to
purchase shares of the Company's common stock for the
two officers of the Company at a price of $.05 per share
under the Incentive Plan. Stock option expense of
$1,780,166 has been recorded based on the
difference between the option price and the quoted
market price on the date of grant and repricing of the
options.

On January 6, 1999, the Company's Compensation Committee
authorized the officers of the Company to purchase the
Company's securities available for sale at the market
closing price on that date not to exceed $105,000 per
officer. The Company's Chief Executive Officer
purchased 29,900 shares of the Company's securities
available for sale for a cost of $89,032. Because the
market price per share was below the
Company's cost basis the Company recorded a loss on this
transaction of $67,382.

Accounts Receivable Related Parties

At June 30, 1999, the Company had $116,855 of
receivables from related parties (including affiliated
companies) primarily for drilling costs, and lease
operating expense on wells owned by the related parties
and operated by the Company. The amounts
are due on open account and are non-interest bearing.

Transaction with Directors

Under the Company's 1993 Incentive Plan, as amended, the
Company grants on an annual basis, to each nonemployee
director, at the nonemployee director's election,
either: 1) an option for 10,000 shares of common stock;
or 2) 5,000 shares of the Company's common stock. The
options are granted at an exercise price equal to 50% of
the average market price for the year in which the
services are performed. The Company
recognized stock option expense of $23,911 and $23,846
for the years ended June 30, 1999 and 1998,
respectively.

Transactions with Other Stockholders

The Company entered into a consulting agreement with
Messrs. Burdette A. Ogle and Ronald Heck (collectively
"Ogle") effective December 1, 1992 which provides for a
monthly fee of $10,000 for a period of five years. The
Company has agreed to extend the term of the consulting
agreement through December 1, 1999.

Effective February 24, 1994, Ogle granted the Company an
option to acquire working interests in three proved
undeveloped offshore Santa Barbara, California, federal
oil and gas units. In August 1994, the Company issued a
warrant to Ogle to purchase 100,000 shares of the
Company's common stock for five years at a price of $8
per share in consideration of the agreement by Ogle to
extend the expiration date of the option to January 3,
1995. On January 3, 1995, the Company exercised the
option from Ogle to acquire the working interests in
three proved undeveloped offshore
Santa Barbara, California, federal oil and gas units.
The purchase price of $8,000,000 is represented by a
production payment reserved in the documents of
Assignment and Conveyance and will be paid out of three
percent (3%) of the oil and gas production from the
working interests with a requirement for
minimum annual payments. Delta paid Ogle $1,200,000
through fiscal 1998 and is to pay a minimum of $350,000
annually until the earlier of: 1) when the production
payments accumulate to the $8,000,000 purchase price;
2) when 80% of the ultimate reserves of any lease have
been produced; or 3) 30 years from the date of the
conveyance. Under the terms of the agreement,
the Company may reassign the working interests to Ogle
upon notice of not more than 14 months nor less than 12
months, thereby releasing the Company of any further
obligations to Ogle after the reassignment.

On December 17, 1998, the Company amended its Purchase
and Sale Agreement with Ogle dated January 3, 1995. As
a result of this amended agreement, at the time of each
minimum annual payment the Company will be assigned an
interest in three undeveloped offshore Santa Barbara,
California, federal oil and gas units proportionate to
the total $8,000,000 production
payment. Accordingly, the annual $350,000 minimum
payment has been recorded as an addition to undeveloped
offshore California properties. In addition, pursuant
to this agreement, the Company extended and repriced a
previously issued warrant to purchase 100,000 shares of
the Company's common stock. The $60,000 fair value
placed on the extension and repricing of this warrant
was recorded as an addition to undeveloped offshore
California properties. Prior to fiscal
1999, the minimum royalty payment was expensed in
accordance with the purchase and sale agreement with
Ogle dated January 3, 1995. As of June 30, 1999, the
Company has paid a total of $1,550,000 in minimum
royalty payments.

(8) Commitments

The Company rents an office in Denver under an operating
lease which expires in April 2002. Rent expense, net of
sublease rental income, for the years ended June 30,
1999 and 1998 was approximately $53,000 and $42,000,
respectively. Future minimum payments under
noncancelable operating leases are as follows:

2000 120,462
2001 116,142
2002 94,840
2003 12,504
2004 8,336

(9) Disclosures About Capitalized Costs, Cost Incurred and
Major Customers

Capitalized costs related to oil and gas producing
activities are as follows:

June 30, June 30,
1999 1998
Undeveloped offshore
California properties $7,369,830 6,959,830
Undeveloped onshore
domestic properties 506,363 726,127
Undeveloped foreign properties 623,920 -
Developed onshore domestic
properties 2,231,187 3,369,881
10,731,300 11,055,838
Accumulated depreciation
and depletion (1,571,705) (1,311,719)

$9,159,595 9,744,119

Cost incurred in oil and gas producing activities for
the years ended June 30,1999 and 1998 are as follows:

1999 1998

Unproved property
acquisition costs $1,033,920 156,681
Proved property
acquisition costs 16,518 40,876
Development costs 140,550 430,830
Exploration costs 74,670 515,383

$1,265,658 1,143,770

A summary of the results of operations for oil and gas
producing activities for the years ended June 30, 1999 and
1998 is as follows:

1999 1998

Revenue:
Oil and gas sales $ 557,503 1,225,115

Expenses:
Lease operating 209,438 349,551
Depletion 229,292 303,563
Exploration 74,670 515,383
Abandoned and impaired
properties 273,041 128,993
Dry hole costs 226,084 46,605
Minimum royalty to related party - 350,000

Results of operations of
oil and gas producing activities ($455,022) (468,980)

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

The Company's sales of oil and gas to individual
customers which exceeded 10% of the Company's total oil and gas
sales for the years ended June 30, 1999 and 1998 were:

1999 1998

A 38% 4%
B 17% 42%

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

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

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

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

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

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

A summary of changes in estimated quantities of proved reserves for the
years ended June 30, 1999 and 1998 are as follows:

GAS OIL
(MCF) (BBLS)

Balance at July 1, 1997 5,417,203 162,812

Extension and discoveries 3,995,565 -
Revisions of quantity estimates 1,285,573 (2,364)
Sales of properties (807,472) (1,375)
Production (457,758) (11,632)

Balance at June 30, 1998 9,433,111 147,441

Revisions of quantity estimates (3,751,139) 5,360
Sales of properties (1,600,440) (4,316)
Production (254,291) (5,574)

Balance at June 30, 1999 3,827,241 142,911

Proved developed reserves:
June 30, 1997 3,419,077 34,176
June 30, 1998 3,905,228 22,273
June 30, 1999 2,289,024 13,140

Future net cash flows presented below are computed using year-end prices
and costs. Future corporate overhead expenses and interest expense
have not been included.

June 30, 1998

Future cash inflows $21,864,136
Future costs:
Production 6,341,210
Development 3,058,005
Income taxes -

Future net cash flows 12,464,921

10% discount factor 5,902,279

Standardized measure of discounted future
net cash flows $6,562,642

June 30, 1999

Future cash inflows $10,147,136
Future costs:
Production 3,353,561
Development 1,287,211
Income taxes -

Future net cash flows 5,506,364

10% discount factor 2,154,142

Standardized measure of discounted future
net cash flows $3,352,222

The principal sources of changes in the standardized measure of
discounted net cash flows during the years ended June 30, 1999
and 1998 are as follows:

1999 1998

Beginning of year $6,562,642 4,319,526

Sales of oil and gas produced during the
period, net of production costs (348,065) (875,564)
Net change in prices and production costs (376,526) (134,318)
Changes in estimated future development costs 891,498 628,160
Extensions, discoveries and improved recovery - 2,661,463
Revisions of previous quantity estimates,
estimated timing of development
and other (2,558,107) 374,627
Sales of reserves in place (1,475,484) (843,205)
Accretion of discount 656,264 431,953

End of year $3,352,222 6,562,642

(11) Subsequent Events

During the year ended June 30, 1999, the Company entered
into an agreement to acquire a 6.07% working interest in the
Point Arguello Unit, its three platforms (Hidalgo, Harvest and
Hermosa), along with a 100% interest in two of the three
leases within the adjacent undeveloped Rocky Point Unit. The
unrelated entity will retain its proportionate share of future
abandonment liability associated with both the onshore and
offshore facilities of the Point Arguello Unit. The agreement
called for an initial issuance of 300,000 shares of restricted
common stock and a $1,000,000 deposit which the Company
completed in the current fiscal year. In addition, the
agreement called for $2,000,000 to be paid by August 2, 1999
and the final payment of $3,000,000, net of operating expenses
and permitted capital expenditures of the working interest
from April 1, 1999, to be paid on or before December 1, 1999.
On August 2, 1999, as required by the agreement, the Company
paid an additional $2,000,000.

Under the agreement, if Delta does not make the final
payment of approximately $3,000,000 Delta would, upon closing,
acquire an approximate 3.035% net operating interest in the Point
Arguello Unit and one half of the sellers working interest in
the undeveloped Rocky Point Unit. In addition, the agreement
provides that if development and operating expenses are not
covered by production revenues then, at Delta's election,
until December 21. 2000, the seller will invest up to
$2,000,000 in Delta through the purchase of Delta Preferred
Stock to cover such costs.

The funds used to make the above payment were borrowed
at 18% per annum from an unrelated entity which was personally
guaranteed by the officers of the Company. The Company agreed
to make monthly payments of interest only for the first six
months and thereafter, make principle and interest payments of
$58,750 until August 1, 2000 at which time the remaining
principle and interest is due and payable.

As consideration for the guarantee of the Company
indebtedness, the Company entered into an agreement with its
officers, under which a 1% overriding royalty interest
(proportionately reduced to the interest in each property
acquired) will be assigned to each of the officers. This
agreement also granted the two officers the right, under
certain circumstances and at their election, to cause the
Company to sell these properties to pay the Company's loans
and eliminate the officer's personal liability if the
$2,000,000 loan is not repaid.

</TABLE>

Consent of Independent Auditors

The Board of Directors
Delta Petroleum Corporation:

We consent to the incorporation by reference in the registration
statement No. 33-87106 on Form S-8 of Delta Petroleum Corporation
of our report dated September 21, 1999 relating to the consolidated
balance sheets of Delta Petroleum Corporation and subsidiary as of
June 30, 1999 and 1998, and the related consolidated statements of
operations, stockholders equity, and cash flows for the years then
ended which report appears in the June 30, 1999 Annual Report on
Form 10-KSB of Delta Petroleum Corporation.

s/KPMG LLP
KPMG LLP

Denver, Colorado
September 24, 1999

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<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> JUN-30-1999
<PERIOD-END> JUN-30-1999
<CASH> 99,545
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<RECEIVABLES> 230,696
<ALLOWANCES> 50,000
<INVENTORY> 0
<CURRENT-ASSETS> 340,341
<PP&E> 10,813,789
<DEPRECIATION> 1,650,228
<TOTAL-ASSETS> 11,377,132
<CURRENT-LIABILITIES> 635,976
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0
0
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<TOTAL-LIABILITY-AND-EQUITY> 11,377,132
<SALES> 557,503
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<CGS> 0
<TOTAL-COSTS> 4,600,131
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<LOSS-PROVISION> 96,553
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<INCOME-PRETAX> (2,998,759)
<INCOME-TAX> 0
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