DELTA PETROLEUM CORP/CO, 10KSB, 2000-08-17

DELTA PETROLEUM CORP/CO
10KSB, 2000-08-17
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, 2000.

[ ] 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 Identification No.)
incorporation or organization)

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, 2000
total $3,665,781.

The aggregate market value as of August 7, 2000 of voting stock
held by non-affiliates of the registrant was $53,292,569.

As of August 7, 2000, 8,989,125 shares of registrant's Common
Stock $.01 par value were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: DEFINITIVE PROXY MATERIALS
FOR THE 2000 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 23

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 34
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 34

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 35

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, 2000, we had varying interests in 112 gross (17.08 net)
productive wells located in six states. We have undeveloped
properties in six states, and interests in five federal units and
one lease offshore California near Santa Barbara. We operate 25
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, 2000, we estimated onshore
proved reserves to be approximately 250,000 Bbls of oil and 7.08
Bcf of gas, of which approximately 120,000 Bbls of oil and 5.67
Bcf of gas were proved developed reserves. At June 30, 2000, we
estimated offshore proved reserves to be approximately 1.58
million Bbls of oil, of which approximately 910,000 Bbls were
proved developed reserves. (See "Description of Property;" Item 2
herein.)

At August 7, 2000, 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 8,989,125 shares of common
stock were issued and outstanding. We have outstanding warrants
and options to purchase 2,347,500 shares of common stock at
prices ranging from $2.00 per share to $6.13 per share at August
7, 2000. 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 2,346,836 shares of
common stock at prices ranging from $0.05 to $9.75 per share at
August 7, 2000.

At June 30, 2000, 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 a portion of the interests
referenced above in the producing oil and gas properties in
Oklahoma and the 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, 2000, 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 own producing and non-producing oil and
gas interests, undeveloped leasehold interests and related assets
in Arkansas, Colorado, Oklahoma, New Mexico, North Dakota ,
Texas, and Wyoming; and interests in a producing Federal unit and
undeveloped offshore Federal leases near Santa Barbara,
California. We intend to continue our emphasis on the drilling
of exploratory and development wells primarily in Colorado,
California, Oklahoma, Texas, Wyoming and offshore 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
purchasers as 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 "non-hazardous,"
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 willful 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, 2001.

(12) Employees. We have five 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. We subleased approximately 2,500
square feet of our space to Bion Environmental Technologies, Inc.
for $3,575 per month until May 1, 2000.

(b) Oil and Gas Properties.

We own interests in oil and gas properties located
primarily in California, Colorado, Oklahoma, New Mexico, North
Dakota, Texas, Wyoming. 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, 2000 and 1999.

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%.
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. Interpretation of the 90
square miles of seismic information revealed approximately 25
drillable prospects. As of August 7, 2000, 20 wells have been
drilled of which ten are now producing and one is awaiting
completion. We expect to participate in the drilling of two
additional wells during the remainder of calendar 2000. 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 have 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 approximately
8,000 net acres in the Piceance Basin in Mesa and Rio Blanco
counties, Colorado. We are evaluating the economics and
feasibility 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 estimated remaining
productive lives of 20 to 30 years.

During fiscal 1999 we sold interests in 23 wells in
Oklahoma for 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% back-in after payout
interest in each of the two wells. The first well has been
drilled and is producing.

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 economics
and feasibility of re-entering one or more of these wells and
drilling additional horizontal bores in other untapped zones.

New Mexico.

East Carlsbad Field. We own interests in 11 producing
wells and associated acreage in New Mexico and Texas. Current
production net to the interests owned by Delta is approximately
738 Mcf per day and 30 Bbls of oil per day as of June 30, 2000.

North Dakota.

We are in the process of completing our acquisition of
a small working interest in Eland, Stadium, Subdivision and
Livestock fields in Stark County, North Dakota. There are a
total of 20 producing wells and 5 injection wells. Current
production net to the interests being acquired by Delta is
approximately 350 barrels of oil equivalent per day. Delta has
purchased two thirds of the interests and has an option to
purchase the remaining third on September 29, 2000.

Offshore:

Offshore Federal Waters: Santa Barbara, California Area

Undeveloped Properties:

Directly and through our subsidiary, Amber Resources
Company, we own interests in five 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 1999, 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, 11 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, other than the Rocky Point Unit, varies from 2.492% to
15.60%. Whiting Petroleum Corporation holds a working interest
for us as our nominee of approximately 70% in the Rocky Point
Unit. This interest is expected to be reduced if the Rocky Point
Unit is included in the Point Arguello Unit and developed from
existing Point Arguello platforms. 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
act as operator of any 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 completed the study under
a contract with the MMS. The COOGER presents a long-term
regional perspective of potential onshore constraints that should
be considered when developing existing undeveloped offshore
leases. COOGER projects the economically recoverable oil and gas
production from offshore leases which have not yet been
developed. These projections are utilized to assist in
identifying a potential range of scenarios for developing these
leases. These scenarios are 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. We have
attempted to evaluate the scenarios that were 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. It is likely that the
adoption of this scenario by 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. This scenario is currently
anticipated by our management to be the most
reasonable course of action although there is no
assurance that this scenario will be adopted.

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 future production. Under this
scenario we would incur increased costs but
revenues would be received more quickly.

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

Scenario 3 Development of existing leases,
using existing onshore facilities by constructing
additional capacity at existing sites to handle
expanded production. This scenario that is
currently anticipated by our management to be the
most reasonable course of action although there is
no assurance that this scenario will be adopted.

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 is similar to #3 above
but would entail increased costs for any new
facilities.

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. Under this scenario we would incur
increased costs but revenues would be received
more quickly.

The development plans for the various units (which have
been submitted to the MMS for review) 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." The development plans for the Rocky Point
Unit provide for the inclusion of the Rocky Point leases in the
Point Arguello Unit upon which the Rocky Point leases would be
drilled from existing Point Arguello platforms with extended
reach drilling technology.

Current Status. On October 15, 1992 the MMS directed a
Suspension of Operations (SOO), effective January 1, 1993, for
the POCS undeveloped leases and units, pursuant to 30 CFR
250.110. The SOO was directed for the purpose of preparing what
became known as the COOGER Study. Two-thirds of the cost of the
Study was funded by the participating companies in lieu of the
payment of rentals on the leases. Additionally, all operations
were suspended on the leases during this period. On November 12,
1999, as the COOGER Study drew to a conclusion, the MMS approved
requests made by the operating companies for a Suspension of
Production (SOP) status for the POCS leases and units. During the
period of a SOP the lease rentals resume and each operator is
required to perform exploration and development activities in
order to meet certain milestones set out by the MMS. Progress
toward the milestones is monitored by the operator in quarterly
reports submitted to the MMS. In February 2000 all operators
completed and timely submitted to the MMS a preliminary
"Description of the Proposed Project". This was the first
milestone required under the SOP. Quarterly reports were also
prepared and submitted for the last quarter of 1999, and the
first and second quarters of 2000.

In order to continue to carry out the requirements of
the MMS, all operators of the units in which we own non-operating
interests are currently engaged in studies and project planning
to meet the next milestone leading to development of the leases.
Where additional drilling is needed the operators will bring a
mobile drilling unit to the POCS to further delineate the
undeveloped oil and gas fields.

Cost to Develop Offshore California Properties. The
cost to develop four of the five undeveloped units (plus one
lease) located offshore California, 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 by the partners to be in
excess of $3 billion. Our share based on our current working
interest of such costs over the life of the properties is
estimated to be over $200 million. There will be additional
costs of a currently undetermined amount to develop the Rocky
Point Unit which is the fifth undeveloped unit in which we own an
interest.

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 our offshore
California properties), reduce our ownership interest in the
properties through sales of interests in the property or as the
result of farmouts, 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 costs 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 levels, it is likely that
development efforts will proceed at a slower pace such that costs
will be incurred over a more extended period of time. If
petroleum prices remain at current levels, 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 million.

The Gato Canyon Unit leases are currently held under
Suspension of Production status through May 1, 2003. An updated
Exploration Plan 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 ExxonMobil 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 million.

The Point Sal Unit leases are currently held under
Suspension of Production status through November 1, 2002. An
updated Exploration Plan 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 million.

The Lion Rock Unit and Lease P-0409 are currently held
under Suspension of Production status through November 1, 2002.
During this SOP there will be an 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 million.

The Sword Unit leases are currently held under a
Suspension of Production status through August 1, 2003. An
updated Exploration Plan is expected to include plans to drill an
additional delineation well.

Rocky Point Unit. Whiting Petroleum Corporation
("Whiting") holds, as nominee for Delta, an 11.11% interest in
OCS Block 451 (E/2) and 100% interest in OCS Block 452 and 453,
which leases comprise the undeveloped Rocky Point Unit. The
Rocky Point Unit is operated by Whiting. Six test wells have
been drilled on these leases from mobile drilling units. Five
were successful and one was a dry hole. OCS-P 0451 #1, drilled
in 1982, was the discovery well for the Rocky Point Field. Five
delineation wells were drilled on the Unit between 1982 and 1984.
Rates up to 1,500 Bbls of oil per day were tested from the
Monterey formation. Rates up to 3,500 Bbls of oil per day were
tested from the lower Sisquoc formation which overlies the
Monterey. Oil gravities at Rocky Point range from 24 to 31 API.

Development of the Rocky Point Unit will be
accomplished through extended-reach drilling from the platforms
located within the adjacent Point Arguello Unit (see below). In
1987 an extended-reach well was successfully drilled to the
southwestern edge of the Rocky Point field from Platform Hermosa
located in the Point Arguello Unit. Since that time the
technology of extended-reach drilling has dramatically advanced.
The entire Rocky Point field is now within drilling distance from
the Point Arguello Unit platforms.

The Rocky Point Unit leases are currently held under
Suspension of Production status through June 1, 2001. This Unit
operator has prepared and timely submitted a Project Description
for the development program to the MMS as the first milestone in
the Schedule of Activities for the Unit. The operator, under the
auspices of the MMS, has also made a presentation of the Project
to the affected Federal, State and local agencies.

Developed Properties:

Point Arugello Unit. Whiting holds, as our nominee,
the equivalent of a 6.07% working interest in the form of a
financial arrangement termed a "net operating interest" in the
Point Arguello Unit and related facilities. Within this unit are
three producing platforms (Hidalgo, Harvest and Hermosa) which
are operated by Arguello, Inc., a subsidiary of Plains Petroleum.
In an agreement between Whiting and Delta (see Form 8-K dated
June 9, 1999) Whiting agreed to retain all of the abandonment
costs associated with our interest in the Point Arguello Unit and
the related facilities.

We anticipate that we will redrill three wells during
the remainder of calendar 2000 and five redrills in calendar
2001. Each redrill will cost approximately $1.71 million
($105,000 to our interest). We anticipate the redrill costs to
be paid through current operations or additional financing.

MAP INSERT

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

Kazakhstan

Acquisition of Exploration Licenses in Kazakhstan.
During fiscal year 1999, we acquired Ambir Properties, Inc.
("Ambir") the only assets of which consisted of two licenses for
exploration of approximately 1.9 million acres in the Pavlodar
region of Eastern Kazakhstan. A work plan prepared by Delta was
approved by the Kazakhstan government which established minimum
work and spending commitments. The minimum required work and
spending commitment for fiscal year 2001 is $264,000. We intend
to transfer the licenses into the name of Delta and attempt to
extend 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 will seek other companies in the oil and gas
industry to participate in the implementation of the work plan.

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, 2000, 1999 and
1998, 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,
2000 1999 1998
Onshore Offshore Onshore Onshore

Average sales price:
Oil (per barrel) $25.95 11.54 10.24 16.46
Natural Gas (per Mcf) $2.62 - 1.97 2.26
Production costs
(per Bbl equivalent) $4.94 11.02 4.37 4.02

The profitability of our oil and gas production activities is
affected by the fluctuations in the sale prices of our oil and
gas production. We sold 25,000 barrels per month from December
1999 to May 2000 at $8.25 per barrel and we have committed to
sell 25,000 barrels per month from June 2000 to December 2000 at
$14.65 under fixed price contracts with production purchases.
(See "Management's Discussion and Analysis or Plan of
Operation.")

(d) Productive Wells and Acreage.

The table below shows, as of June 30, 2000, 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 .00 1,558 1,111
Colorado 8 .80 13 10.30 2,560 2,127
Oklahoma 0 .00 32 2.03 17,120 1,198
California:
Onshore 0 .00 11 1.25 1,200 132
Offshore 38 2.30 0 .00 19.740 1,197
Wyoming 0 .00 6 1.20 960 192
50 4.92 62 14.78 43,138 5,957

(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, 2000, we held undeveloped acreage by state
as set forth below:

Undeveloped Acres (1)(2)

Location Gross Net

California, offshore(3) 64,905 15,837
California, onshore 640 96
Colorado 10,560 7,937
Wyoming 9,696 1,939
Oklahoma 1,600 112
Total 87,401 25,921

(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, 2000 June 30, 1999 June 30, 1998
Gross Net Gross Net Gross Net

Exploratory Wells(1):
Productive:
Oil 0 .00 0 .00 0 .000
Gas 0 .00 4 .44 5 .545
Nonproductive 0 .00 7 .77 1 .113
Total 0 .00 11 1.21 6 .658

Development Wells(1):.
Productive:
Oil 3 .18 0 .00 0 .000
Gas 2 .25 0 .00 1 .042
Nonproductive 0 .00 0 .00 0 .000
Total 5 .43 0 .00 1 .042

Total Wells(1):
Productive:
Oil 3 .18 0 .00 0 .000
Gas 2 .25 4 .44 6 .587
Nonproductive 0 .00 7 .77 1 .113
Total Wells 5 .43 11 1.21 7 .700

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

(g) Present Drilling Activity

We plan on participating in the drilling of five new wells
before the end of calendar 2000.

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.

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

The 1999 Annual Meeting of the shareholders of the
Company was held on March 30, 2000.

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. 5,540,927 33,895
Roger A. Parker 5,540,927 33,895
Jerrie F. Eckelberger 5,541,046 33,776
Terry D. Enright 5,541,046 33,776

Also ratified, approved, and adopted was the
appointment of KPMG, LLP for our auditors for the year ended June
30, 2000 with 5,555,022 affirmative votes, 19,800 negative votes,
3,900 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. 55 Chairman of the Board, May 1987 to Present
Chief Executive Officer,
Secretary, Treasurer,
and a Director

Roger A. Parker 38 President and a Director May 1987 to Present

Terry D. Enright 51 Director November 1987
to Present
Jerrie F.
Eckelberger 56 Director September 1996
to Present

Kevin K. Nanke 35 Chief Financial Officer December 1999
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 55, 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 4.9% 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 38, 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 51, 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 56, is an investor, real estate
developer and attorney who has practiced law in the State of
Colorado for 29 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.

Kevin K. Nanke, age 35, appointed Chief Financial
Officer in December 1999, joined Delta in April 1995 as
Controller. Since 1989, he has been involved in public and
private accounting with the oil and gas industry. Mr. Nanke
received a Bachelor of Arts in Accounting from the University of
Northern Iowa in 1989. Prior to working with Delta, he was
employed by KPMG LLP. He is a member of the Colorado Society of
CPA=s and the Council of Petroleum Accounting Society.

There is no family relationship among or between any of the
Officers or 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
September 30, 1999 3.50 2.63
December 31, 1999 2.94 1.78
March 31, 2000 3.88 2.19
June 30, 2000 4.06 3.00

On August 7, 2000, the closing price of the Common
Stock was $6.25.

(b) Approximate Number of Holders of Common Stock.

The number of holders of record of the Company's
Common Stock at August 7, 2000 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 we do
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 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.)

On November 30, 1999, we completed a sale of
428,000 shares of the Company's common stock to Bank Leu AG, for
net proceeds to the Company of $750,000.

On January 4, 2000, we completed a sale of 175,000
shares of the Company=s common stock to Evergreen, another oil
and gas company, for net proceeds to the Company of $350,000.

On June 1, 2000, we issued 90,000 shares of the
Company's common stock valued at $273,375 to Whiting as a deposit
to acquire certain interest in producing properties in Stark
County, North Dakota.

During fiscal 2000, we issued 215,000 shares of
our common stock to an unrelated entity as a commission for their
involvement with the Point Arguello Unit and New Mexico
acquisitions completed in fiscal 2000.

On July 3, 2000, we completed a sale of 258,621
shares of the Company's common stock to Bank Leu AG, for net
proceeds to the Company of $674,000.

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

Liquidity and Capital Resources.

At June 30, 2000, we had a working capital deficit of
$1,985,141 compared to a working capital deficit of $295,635 at
June 30, 1999. Our current assets include accounts receivable
from related parties (including affiliated companies) of $142,582
at June 30, 2000 which is primarily for drilling costs, and lease
operating expense on wells owned by the related parties and
operated by us. The amounts are due on open account and are non-
interest bearing. Our current liabilities include current
portion of long-term debt of $1,831,469 at June 30, 2000. We
borrowed these funds to acquire certain oil and gas properties in
fiscal 2000.

Our working interest share of the future estimated
development costs based on estimates developed by the operating
partners relating to four of our five undeveloped offshore
California units is approximately $217 million. No significant
amounts are expected to be incurred during fiscal 2001 and $1.0
million and $4.2 million are expected to be incurred during
fiscal 2002 and 2003, respectively. There are additional, as yet
undetermined, costs that we expect in connection with the
development of the fifth undeveloped property in which we have an
interest (Rocky Point Unit). Because 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 our interest. If we
were to farmout our interests, our interest in the properties
would be decreased substantially. 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. 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.

We estimate our capital expenditures for onshore properties
to be approximately $1,000,000 for the year ended June 30, 2001.
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.

We received the proceeds from the exercise of options to
purchase shares of our common stock of $1,377,536 and $160,000
during the years ended June 30, 2000 and 1999, 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 18% per annum
from our officers under a promissory note maturing on June 1,
2001. This promissory note was identical in terms to the
promissory note under which these officers borrowed the money
from a private lender which they, in turn, loaned to us. On
December 1, 1999, we paid the loan in full.

On July 30, 1999, we borrowed $2,000,000 at 18% per annum
from an unrelated entity maturing on August 1, 2001 which was
personally guaranteed by two of our officers. The loan proceeds
were used as deposit funds for the Point Arguello acquisition.
We paid a 2% origination fee to the lender. In addition, as
consideration for the guarantee of our indebtedness, we entered
into an agreement with our officers, under which a 1% overriding
royalty interest in the properties acquired with the proceeds
form the loans (proportionately reduced to the interest in each
property acquired) will be assigned to each of the officers.
Each overriding royalty had a fair market value of approximately
$125,000 which was recorded as an adjustment to the purchase
price. At June 30, 2000 the principal balance was $740,462.
Subsequent to year-end, the balance was paid in full.

On November 1, 1999, we acquired interests in 11 oil and gas
producing properties located in New Mexico and Texas for a cost
of $2,879,850.

Also on November 1, 1999, we borrowed the funds for the
above mentioned acquisition at 18% per annum from an unrelated
entity maturing on January 31, 2000, which was personally
guaranteed by two of our officers. As consideration for the
guarantee of our indebtedness we agreed to assign a 1% overriding
royalty interest to each officer in the properties acquired with
the proceeds of the loan (proportionately reduced to the interest
acquired in each property). Each overriding royalty had a fair
market value of approximately $37,500 which was recorded as an
adjustment to the purchase price. We also paid a 1% origination
fee to the lender. On December 1, 1999, we paid the loan in
full.

On December 1, 1999, we acquired a 6.07% working interest in
the Point Arguello Unit, its three platforms (Hidalgo, Harvest,
and Hermosa), along with a 100% interest in two and an 11.11%
interest in one of the three leases within the adjacent Rocky
Point Unit for $5.6 million in cash consideration and the
issuance of 500,000 shares of the our common stock with an
estimated fair value of $1,133,550.

On December 1, 1999, we borrowed $8,000,000 at prime rate
plus 1-1/2% (11% at June 30, 2000) from an unrelated entity. The
loan agreement provides for a 4-1/2 year loan with additional
compensation to the lender if paid after September 1, 2000. The
proceeds from this loan were used to payoff existing debt and to
fund the balance of the Point Arguello Unit purchase. We are
required to make monthly payments equal to the greater of
$150,000 or 75% of net cash flows from the acquisitions completed
on November 1, 1999 and December 1, 1999. The loan is
collateralized by our oil and gas properties acquired with the
loan proceeds.

On January 1, 1999 and January 4, 2000, we completed the
sale of 194,444 and 175,000 shares, respectively, of our common
stock in a private transaction to an unrelated entity for net
proceeds for each issuance to us of $350,000.

On July 5, 2000, we completed the sale of 258,621 shares of
its restricted common stock to an unrelated entity for $750,000.
A fee of $75,000 was paid and options to purchase 100,000 shares
of our common stock at $2.50 per share and 100,000 shares at
$3.00 per share for one year were issued to an unrelated
individual and entity and as consideration for their efforts and
consultation related to the transaction.

On July 10, 2000, we paid $3,745,000 to acquire interests in
producing wells and acreage located in the Eland and Stadium
fields in Stark County, North Dakota. The July 10, 2000 payment
resulted in the acquisition by us of 67% of the ownership
interest in each property to be acquired. An optional payment of
$1,845,000, less net production revenues accrued from February 1,
2000, is due September 29, 2000 to purchase the remaining
ownership interest in each property. The $3,745,000 payment on
July 10, 2000 was financed through borrowings from an unrelated
entity and personally guaranteed by two of the our officers.

On July 21, 2000, we and an unrelated entity ("the entity")
entered into a definitive agreement entitled "Investment
Agreement" whereby the entity has given a firm commitment to
allow us to issue to the entity up to a total of $20,000,000 of
its common stock over three years from time to time as often as
monthly in amounts based upon certain market conditions and at
prices based upon market prices for our common stock at the time
of issuance. As consideration the entity has received a warrant
to purchase 500,000 shares of our common stock at $3.00 per share
for five years and may receive additional warrants to purchase
our common stock under the terms of the Investment Agreement. A
warrant to purchase 150,000 shares of the entity common stock at
$3.00 per share for five years was issued to an unrelated company
as consideration for its efforts and consultation related to
potential financing alternatives and this transaction. Proceeds
will be used for property acquisitions, debt reduction and
working capital.

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 proved undeveloped properties during the next twelve
months. 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
are currently trying to establish a credit facility with a
financial institution but 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 operations and our capital
requirements for development of our properties including
establishing a credit facility, sale of equity or debt securities
and sale of 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
presently believe that our 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, 2000 was $3,367,050 compared to the net loss
of $2,998,759 for the year ended June 30, 1999. The losses for
the years ended June 30, 2000 and 1999 were effected by the items
described in detail below.

Revenue. Total revenue for the year ended June 30,
2000 was $3,665,981 compared to $1,717,651 for the year ended
June 30, 1999. Oil and gas sales for the year ended June 30,
2000 were $3,355,783 compared to $557,507 for the year ended
June 30, 1999. The increase in oil and gas sales during the year
ended June 30, 2000 resulted from the acquisition of eleven
producing wells in New Mexico and Texas and the acquisition of an
interest in the offshore California Point Arguello Unit. The
increase in oil and gas sales were also impacted by the increase
in oil and gas prices.

Production volumes and average prices received for the
years ended June 30, 2000 and 1999 are as follows:

2000 1999
Onshore Offshore Onshore Offshore

Production:
Oil (barrels) 9,620 186,989 5,574 -
Gas (Mcf) 362,051 - 254,291 -
Average Price:
Oil (per barrel) $25.95 $11.54* $10.24 -
Gas (per Mcf) $2.62 - $1.97 -

*We sold 25,000 barrels per month from December 1999 to May
2000 at $8.25 per barrel and we have committed to sell 25,000
barrels per month from June 2000 to December 2000 at $14.65 per
barrel under fixed price contracts with production purchases.

Lease Operating Expenses. Lease operating expenses for
the year ended June 30, 2000 were $2,405,469 compared to $209,438
for the year ended June 30, 1999. On a per Bbl equivalent basis,
production expenses and taxes were $4.94 for onshore properties
and $11.02 for offshore properties during the year ended June
30, 2000 compared to $4.37 for onshore properties for the year
ended June 30, 1999. The increase in lease operating expense
compared to 1999 resulted from the acquisition of an interest in
eleven new properties onshore and an interest in the offshore
Point Arguello Unit near Santa Barbara, California. In general
the cost per Bbl for offshore operations are higher than onshore.
The offshore properties had approximately $175,000 in non
capitalized workover cost included in lease operating expense.

Depreciation and Depletion Expense. Depreciation and
depletion expense for the year ended June 30, 2000 was $887,802
compared to $229,292 for the year ended June 30, 1999. On a Bbl
equivalent basis, the depletion rate was $4.64 for onshore
properties and $3.00 for offshore properties during the year
ended June 30, 2000 compared to $4.78 for onshore properties for
the year ended June 30, 1999.

Exploration Expenses. Exploration expenses consist of
geological and geophysical costs and lease rentals. Exploration
expenses were $46,730 for the year ended June 30, 2000 compared
to $74,670 for the year ended June 30, 1999.

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.
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 for the
year ended June 30, 1999. 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 would not be
economical to develop certain prospects and as such we will not
proceed with these prospects. There was no impairment for oil
and gas properties in fiscal 2000.

General and Administrative Expenses. General and
administrative expenses for the year ended June 30, 2000 were
$1,777,579 compared to $1,506,683 for the year ended June 30,
1999. The increase in general and administrative expenses
compared to fiscal 1999, can be attributed to an increase in
shareholder relations and professional services relating to
Securities and Exchange related filings.

Stock Option Expense. Stock option expense has been
recorded for the years ended June 30, 2000 and 1999 of $537,708
and $2,080,923, respectively, for options granted to and/or re-
priced for certain officers, directors, employees and consultants
at option prices below the market price at the date of grant.
The stock option expense for fiscal 2000 can primarily be
attributed to repricing options to certain consultants that
provide shareholder relations to the Company. 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 re-pricing 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
re-priced 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 in fiscal 1999 of $1,985,414
was recorded based on the difference between the option price and
the quoted market price on the date of grant and re-pricing of the
options.

Recently Issued or Proposed Accounting Standards and
Pronouncements

In March 2000, the Financial Accounting Standards Board
("FASB") issued FASB Interpretation No. 44 "Accounting for
Certain Transactions involving Stock Compensation- and
interpretation of APB Opinion No. 25 ("FIN 44"). This opinion
provides guidance on the accounting for certain stock option
transactions and subsequent amendments to stock option
transactions. FIN 44 is effective July 1, 2000, but certain
conclusions cover specific events that occur after either
December 15, 1998 or January 12, 2000. To the extent that FIN
44 covers events occurring during the period from December 15,
1998 and January 12, 2000, but before July 1, 2000, the effects
of applying this interpretation are to be recognized on a
prospective basis. Repriced options mentioned above may impact
future periods. The Company has not yet assessed the impact, if
any, that FIN 44 might have on its financial position or results
of operations.

In December 1999, the SEC released Staff Accounting
Bulletin ("SAB") No. 101, "Revenue Recognition in Financial
Statements", which provides guidance on the recognition,
presentation and disclosure of revenue in financial statements
filed with the SEC. Subsequently, the SEC released SAB 101B,
which delayed the implementations date of SAB 101 for registrants
with fiscal years beginning between December 16, 1999 and March
15, 2000. The Company has not yet assessed the impact, if any,
that SAB 101 might have on its financial position or results of
operations.

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 was amended by SFAS 137 and 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.

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
"Directors, Executive Officers, Promoters and Control Persons;
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; November 1, 1999; Items 2 & 7
Form 8-K/A November 1, 1999; Item 7
Form 8-K; December 1, 1999; Items 2 & 5 & 7
Form 8-K/A; December 1, 1999; Item 7
Form 8-K; January 1, 2000; Items 5 & 7
Form 8-K; July 10, 2000; Items 2 & 5 & 7
Form 8-K; August 3, 2000; 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,
* government regulations, 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, Chief Financial 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 08/15/00

By (Signature and Title) s/Roger A. Parker
Roger A. Parker, Director
Date 08/15/00

By (Signature and Title) s/Terry D. Enright
Terry D. Enright, Director
Date 08/15/00

By (Signature and Title) s/Jerrie F. Eckelberger
Jerrie F. Eckelberger, Director
Date 08/15/00

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

10.10 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.

10.11 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.

10.12 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.

10.13 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.

10.14 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.

10.15 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.

10.16 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.

10.17 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.

10.18 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.

10.19 Purchase and Sale Agreement dated October 13, 1999
between Whiting Petroleum Corporation and Delta Petroleum
Corporation. Incorporated by reference from Exhibit 99.1 to the
Company's Form 8-K dated November 1, 1999.

10.20 Agreement between Delta Petroleum Corporation, Roger A.
Parker and Aleron H. Larson, Jr. dated November 1, 1999.
Incorporated by reference from Exhibit 99.3 to the Company's Form 8-
K dated November 1, 1999.

10.21 Conveyance and Assignment from Whiting Petroleum
Corporation dated December 1, 1999. Incorporated by reference from
Exhibit 10.1 to the Company's Form 8-K dated December 1, 1999.

10.22 Loan Agreement (without exhibits) between Kaiser-Francis
Oil Company and Petroleum Corporation dated December 1, 1999.
Incorporated by reference from Exhibit 10.2 to the Company's Form 8-
K dated December 1, 1999.

10.23 Promissory Note dated December 1, 1999. Incorporated by
reference from Exhibit 10.3 to the Company's Form 8-K dated
December 1, 1999.

10.24 July 29, 1999 Agreement between GlobeMedia AG and Delta
Petroleum Corporation with November 23, 1999 amendment.
Incorporated by reference from Exhibit 99.1 to the Company's Form 8-
K dated January 4, 2000.

10.25 Letter Agreement between GlobeMedia AG and Delta
Petroleum Corporation dated November 23, 1999. Incorporated by
reference from Exhibit 99.3 to the Company's Form 8-K dated January
4, 2000.

10.26 Agreement dated December 30, 1999 between Burdette A.
Ogle and Delta Petroleum Corporation. Incorporated by reference
from Exhibit 99.4 to the Company's Form 8-K dated January 4, 2000.

10.27 Investment Representation Agreement dated December 17,
1999 between Evergreen Resources, Inc. and Delta Petroleum
Corporation. Incorporated by reference from Exhibit 99.5 to the
Company's Form 8-K dated January 4, 2000.

10.28 Option Agreement between Evergreen Resources, Inc. and
Delta Petroleum Corporation dated December 17, 1999 (effective as
of January 4, 2000). Incorporated by reference from Exhibit 99.6
to the Company's Form 8-K dated January 4, 2000.

10.29 Purchase and Sale Agreement dated June 1, 2000 between
Whiting Petroleum Corporation and Delta Petroleum
Corporation. Incorporated by reference from Exhibit 10.1 to
the Company's Form 8-K dated July 10, 2000.

10.30 Documents and Agreements dated July 10, 2000 between
Delta Petroleum Corporation and Hexagon Investments, Inc.
and/or Sovereign Holdings, LLC related to financing
arrangements:
-Partial Assignment of Contract;
-Collateral Assignment of Purchase and Sale Agreement;
-Letter Agreement re: loan;
-Estoppel Certificate and Agreement;
-Promissory Note;
-Guarantee Agreement

Incorporated by reference from Exhibit 10.2 to the Company's
Form 8-K dated July 10, 2000.

10.31 Investment Agreement dated July 21, 2000 between Delta
Petroleum Corporation and Swartz Private Equity, LLC and
related agreements. Incorporated by reference from Exhibit
99.2 to the Company's Form 8-K dated July 10, 2000.

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 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, 2000 and 1999 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, 2000 and 1999 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
August 11, 2000

DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
June 30, 2000 and 1999

2000 1999

ASSETS

Current Assets:
Cash $ 302,414 99,545
Trade accounts receivable, net of
allowance for doubtful accounts of $50,000
in 2000 and 1999 613,527 113,841
Accounts receivable - related parties 142,582 116,855
Prepaid assets 373,334 10,000
Other current assets 198,427 100

Total current assets 1,630,284 340,341

Property and Equipment:
Oil and gas properties, at cost (using
the successful efforts method
of accounting):
Undeveloped offshore California properties 10,809,310 7,369,830
Undeveloped onshore domestic properties 451,795 506,363
Undeveloped foreign properties 623,920 623,920
Developed offshore California properties 3,285,867 -
Developed onshore domestic properties 5,154,295 2,231,187
Office furniture and equipment 89,019 82,489
20,414,206 10,813,789

Less accumulated depreciation and depletion (2,538,030) (1,650,228)

Net property and equipment 17,876,176 9,163,561

Long term assets:
Deferred financing costs 366,996 -
Investment in Bion Environmental 228,629 257,180
Partnership net assets 675,185 -
Deposit on purchase of oil and gas properties 280,002 1,616,050

Total long term assets 1,550,812 1,873,230

$21,057,272 $11,377,132

2000 1999

LIABILITIES AND STOCKHOLDERS' EQUITY

Current Liabilities:
Accounts payable 1,636,651 393,542
Other accrued liabilities 154,388 10,000
Royalties payable 58,733 127,166
Current portion of long-term debt:
Related party - 105,268
Other 1,765,653 -

Total current liabilities 3,615,425 635,976

Long-term debt:
Related party - 894,732
Other 6,479,115 -

Total long-term debt 6,479,115 894,732

Stockholders' Equity:
Preferred stock, $.10 par value;
authorized 3,000,000 shares, none issued - -
Common stock, $.01 par value;
authorized 300,000,000 shares,
issued 8,422,079
shares in 2000 and 7,913,379 in 1999 84,221 63,903
Additional paid-in capital 33,746,861 29,476,275
Accumulated other comprehensive income (loss) 77,059 (115,395)
Accumulated deficit (22,945,409) (19,578,359)

Total shareholders' equity 10,962,732 9,846,424

Commitments
$21,057,272 $11,377,132

DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
June 30, 2000 and 1999

2000 1999

Revenue:
Oil and gas sales $ 3,355,783 557,507
Gain on sale of oil and gas properties 75,000 957,147
Other revenue 235,198 203,001

Total revenue 3,665,981 1,717,655

Operating expenses:
Lease operating expenses 2,405,469 209,438
Depreciation and depletion 887,802 229,292
Exploration expenses 46,730 74,670
Abandoned and impaired properties - 273,041
Dry hole costs - 226,084
General and administrative 1,777,579 1,506,683
Stock option expense 537,708 2,080,923

Total operating expenses 5,655,288 4,600,131

Loss from operations (1,989,307) (2,882,476)

Other income and expenses:
Interest and financing costs (1,264,954) (19,726)
Loss on sale of securities available
for sale (112,789) (96,553)

Total other income and expenses (1,377,743) (116,279)

Net loss $ (3,367,050) $(2,998,755)

Net loss per common share-basic and diluted $(0.46) $(0.51)

Weighted average of common
Shares outstanding 7,271,336 5,854,758

DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Consolidated Statement of Stockholders' Equity and Comprehensive
Income (Loss)
Years Ended June 30, 2000 and 1999

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

<S> <C> <C> <C>
Balance, July 1, 1998 5,513,858 $ 55,139 25,571,921

Comprehensive loss:
Net loss - - -
Other comprehensive loss, net of tax
Unrealized loss on equity securities - - -
Less: Reclassification adjustment for losses included in net loss - - -
Comprehensive loss - - -
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 properties 250,000 2,500 621,420
Shares issued for deposit on oil and gas properties 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

Comprehensive loss:
Net loss - - -
Other comprehensive gain, net of tax
Unrealized gain on equity securities - - -
Less: Reclassification adjustment for losses included in net loss - - -
Comprehensive loss - - -
Stock options granted as compensation - - 500,208
Shares issued for cash 603,000 6,030 1,017,970
Shares issued for cash upon exercise of options 1,048,777 10,488 1,367,048
Shares and options issued with financing 75,000 750 565,472
Shares issued for oil and gas properties 215,000 2,150 547,413
Shares issued for deposit on oil and gas properties 90,000 900 272,475

Balance, June 30, 2000 8,422,079 $ 84,221 33,746,861

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

<S> <C> <C> <C> <C>
Balance, July 1, 1998 457,594 (16,579,600) 9,505,054

Comprehensive loss:
Net loss (2,998,759) (2,998,759) (2,998,759)
Other comprehensive loss, 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 loss (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 properties - - 623,920 #
Shares issued for deposit on oil and gas properties - - 616,050
Fair value of warrant extended and repriced - - 60,000

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

Comprehensive loss:
Net loss (3,367,050) ( 3,367,050) (3,367,050)
Other comprehensive gain, net of tax
Unrealized gain on equity securities 79,665 -
Less: Reclassification adjustment for
losses included in net loss 112,789 192,454 192,454
Comprehensive loss (3,174,596)
Stock options granted as compensation - - 500,208
Shares issued for cash - - 1,024,000
Shares issued for cash upon exercise of options - - 1,377,536
Shares and options issued with financing 566,222
Shares issued for oil and gas properties - - 549,563
Shares issued for deposit on oil and gas properties - - 273,375

Balance, June 30, 2000 77,059 (22,945,409) 10,962,732
</TABLE>

DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended June 30, 2000 and 1999

<TABLE>

2000 1999

<S> <C> <C>
Cash flows operating activities:
Net loss $ (3,367,050) (2,998,759)
Adjustments to reconcile net loss to cash used in
operating activities:
Gain on sale of oil and gas properties (75,000) (957,147)
Loss on sale of securities available for sale 112,789 96,553
Depreciation and depletion 887,802 229,292
Stock option expense 500,208 2,080,923
Amortization of financing costs 466,568 -
Abandoned and impaired properties - 273,041
Common stock issued for services - 15,750
Net changes in operating assets and
and operating liabilities:
(Increase) decrease in trade accounts receivable (533,074) 84,432
(Increase) decrease in accounts receivable from (19,564) 4,397
related parties
Increase in prepaid assets (373,334) -
(Increase) decrease in other current assets (62,500) -
Increase (decrease) in accounts payable trade 1,243,109 (176,927)
Increase (decrease) in other accrued liabilities 144,388 -
Royalties payable (68,433) (137,154)

Net cash used in operating activities (1,144,091) (1,485,599)

Cash flows from investing activities:
Additions to property and equipment (7,759,804) (507,068)
Deposit on purchase of oil and gas properties (6,627) (1,000,000)
Proceeds from sale of securities available for sale 135,441 174,602
Proceeds from sale of oil and gas properties 75,000 1,384,000
Increase in long term assets (675,185) -
Net cash provided by (used in) investing activities (8,231,175) 51,534

Cash flows from financing activities:
Stock issued for cash upon exercise of options 1,377,536 160,000
Issuance of common stock for cash 1,024,000 356,475
Borrowing from related parties - 1,000,000
Repayment of borrowings to related parties (1,000,000) -
Proceeds from borrowings 12,816,851 400,000
Repayment of borrowings and financing costs (4,640,252) (400,000)
Net cash provided by financing activities 9,578,135 1,516,475

Net increase in cash 202,869 82,410

Cash at beginning of period 99,545 17,135

Cash at end of period $ 302,414 $99,545

Supplemental cash flow information -
Cash paid for interest and financing costs $ 741,348 $19,726

Non-cash financing activities:
Common stock and options issued for the purchase
of oil and gas properties $ 549,563 $683,920

Common stock, options and overriding royalties
issued for services relating to debt financing $ 891,223 $ -

Common stock issued for deposit on purchase
of oil and gas properties $ 273,375 $616,050

</TABLE>

DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 2000 and 1999

(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 developed and 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 has a license to explore undeveloped properties
in Kazakhstan.

At June 30, 2000, 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, 2000, the Company had a working capital deficit of
$1,925,750. 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. In addition, during
fiscal 2000 and 1999, the Company has raised approximately
$2,401,536 and $515,975, respectively, through private
placements and option exercises. 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
undeveloped properties ($11,885,025 at June 30, 2000) are
assessed periodically on an individual field basis 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.

Certain of the Company's oil and gas activities are
conducted through partnerships and joint ventures, the
Company includes its proportionate share of assets,
liabilities, revenues and expenses in its consolidated
financial statements. Partnership net assets represents the
Company's share of net working capital in such entities.

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.

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 an
impairment provision attributable to certain producing
properties of $103,230 for the year ended June 30, 1999.

The Company's undeveloped properties were assessed for
impairment on an individual field basis and the Company
recorded an impairment provision attributed to certain
undeveloped onshore properties of $169,811 for the year
ended June 30, 1999 as management believed that the costs of
such properties would likely not be recovered.

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, 2000, the Company had produced and recognized
as revenue approximately 13,000 Mcf more than its entitled
share of production. The undiscounted value of this
imbalance is approximately $39,000 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, royalties payable
of $68,433 and $137,154 have been written off and recorded
as other income in fiscal 2000 and 1999, respectively.

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) attributed to common stock by the weighted
average number of common shares outstanding during each
period, excluding treasury shares. Diluted earnings (loss)
per share is computed by adjusting the average number of
common share outstanding for the dilutive effect, if any, of
convertible preferred stock, stock options and warrant. The
effect of potentially dilutive securities outstanding were
antidilutive in 2000 and 1999.

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

In March 2000, the Financial Accounting Standards Board
("FASB") issued FASB Interpretation No. 44 "Accounting for
Certain Transactions involving Stock Compensation- and
interpretation of APB Opinion No. 25 ("FIN 44"). This
opinion provides guidance on the accounting for certain
stock option transactions and subsequent amendments to stock
option transactions. FIN 44 is effective July 1, 2000, but
certain conclusions cover specific events that occur after
either December 15, 1998 or January 12, 2000. To the extent
that FIN 44 covers events occurring during the period from
December 15, 1998 and January 12, 2000, but before July 1,
2000, the effects of applying this interpretation are to be
recognized on a prospective basis. Repriced options
mentioned above may impact future periods. The Company has
not yet assessed the impact, if any, that FIN 44 might have
on its financial position or results of operations.

In December 1999, the SEC released Staff Accounting Bulletin
("SAB") No. 101, "Revenue Recognition in Financial
Statements", which provides guidance on the recognition,
presentation and disclosure of revenue in financial
statements filed with the SEC. Subsequently, the SEC
released SAB 101B, which delayed the implementations date of
SAB 101 for registrants with fiscal years beginning between
December 16,1 999 and March 15, 2000. The Company has not
yet assessed the impact, if any, that SAB 101 might have on
its financial position or results of operations.

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 was amended by SFAS 137 and 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.

Reclassification

Certain amounts in the 1999 financial statements have been
reclassified to conform to the 2000 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
2000 and 1999 the Company received an additional 16,808 and
10,249 shares, respectively, of Bion's common stock for rent
and other services provided by the Company. The Company
realized losses of $112,789 and $96,553 for the years ended
June 30, 2000 and 1999, respectively, on the sales of
securities available for sale.

The cost and estimated market value of the Company's
investment in Bion at June 30, 2000 and 1999 are as follows:

Estimated
Unrealized Market
Cost Gain/(Loss) Value

2000 $151,570 $ 77,059 $228,629
1999 $372,575 $(115,395) $257,180

As of August 1, 2000, the estimated market value of the
Company's investment in Bion, based on the quoted bid price
of Bion's common stock, was approximately $225,000.

(3) Oil and Gas Properties

On November 1, 1999, the Company acquired interests in 11
oil and gas producing properties located in New Mexico and
Texas for a cost of $2,879,850.

On December 1, 1999, the Company completed the acquisition
of the equivalent of a 6.07% working interest in the form of
a financial arrangement termed a "net operating interest" in
the Point Arguello Unit, and its three platforms (Hidalgo,
Harvest and Hermosa), along with a 100% interest in two and
an 11.11% interest in one of the three leases within the
adjacent undeveloped Rocky Point Unit from an unrelated
entity. The seller is unrelated and will retain its
proportionate share of future abandonment liability
associated with both the onshore and offshore facilities of
the Point Arguello Unit. The acquisition had a purchase price
of approximately $6,758,550 consisting of $5,625,000 in cash
and 500,000 shares of the Company's restricted common stock
with a fair market value of $1,133,500. As part of the
agreement, the Company committed to sell 25,000 barrels per
month from December 1999 to May 2000 at $8.25 per barrel and from
June 2000 to December 2000 at $14.65.

In addition, the agreement provides that if development and
operating expenses are greater than production revenues
then, at Delta's election, until December 31, 2000, the
seller will invest up to $1,000,000 in Delta through the
purchase of Delta Preferred Stock to cover excess expenses
incurred by Delta.

The following unaudited proforma consolidated statement of
operations information assumes that the November 1, 1999 and
December 1, 1999 acquisitions occurred as of July 1, 1998.

Years Ended
June 30,
2000 1999

Oil and gas sales $5,179,526 $4,414,289

Operating expense $7,284,217 $9,231,546

Net loss $(3,685,786) $(5,109,588)

Net loss per common
share-basic and diluted $(.51) $(.84)

(4) Long Term Debt

Other Related Party
2000 1999 2000 1999

A $7,504,306 - - -
B 740,462 - - -
C - - - 1,000,000
$8,244,768 - - 1,000,000

Current portion 1,765,653 - - 105,268

Long-term portion $6,479,115 $- $- $894,732

A. On December 1, 1999, the Company borrowed $8,000,000 at
prime plus 1-1/2% from an unrelated entity. The loan
agreement provides for a 4-1/2 year loan with additional
compensation to the lender if paid after September 1, 2000.
The proceeds from this loan were used to pay off existing
debt and the balance of the Point Arguello Unit purchase.
The Company is required to make minimum monthly payments
equal to the greater of $150,000 or 75% of net cash flows
from the acquisitions completed on November 1, 1999 and
December 1, 1999. The Company has assumed the minimum
payments of $150,000 per month for the determination of the
current portion of long term debt. The loan is
collateralized by the Company's oil and gas properties
acquired with the loan proceeds to date in the current
fiscal year.

B. On July 30, 1999, the Company borrowed $2,000,000 at
18% per annum from an unrelated entity which was personally
guaranteed by the officers of the Company. On December 1,
1999, the Company paid a portion of the principal and
accrued interest leaving a principal balance of $740,462.
The Company paid a 2% origination fee to the lender. As
consideration for the guarantee of the Company indebtedness,
the Company entered into an agreement with two of its
officers, under which a 1% overriding royalty interest in
the properties acquired with the proceeds of the loan
(proportionately reduced to the interest in each property)
will be assigned to each of the officers. The estimated
fair value of each overriding royalty interest of $125,000 was
recorded as a deferred financing cost. Subsequent to year end,
the Company paid off the loan.

C. On May 24, 1999, the Company borrowed $1,000,000 at 18%
per annum from the Company's officers maturing on June 1,
2001 upon the same terms under which they borrowed these
funds from an unrelated lender. 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. Loan was paid in full during
fiscal 1999.

D. On November 1, 1999, the Company borrowed approximately
$2,800,000 at 18% per annum from an unrelated entity
maturing on January 31, 2000, which was personally
guaranteed by two officers of the Company. The loan
proceeds were used to purchase the 11 producing wells and
associated acreage in New Mexico and Texas. On December 1,
1999, the Company paid the loan in full. The Company also
paid a 1% origination fee to the lender. As consideration
for the guarantee of the Company indebtedness, the Company
agreed to assign a 1% overriding royalty interest to each
officer in the properties acquired with the proceeds of the
loan (proportionately reduced to the interest acquired in each
property). The estimated fair value of each overriding royalty
interest of $37,500 was recorded as a deferred financing cost.
The Company also paid a 1% origination fee to the lender.

(5) 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, 2000 and 1999,
no preferred stock was issued.

Common Stock

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.

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.

On December 1, 1998, the Company issued 10,000 shares of the
Company's common stock to an unrelated entity for public
relation service.

On January 1, 1999 and again on January 4, 2000, the Company
completed a sale of 194,444 and 175,000 shares,
respectively, of the Company's Common stock to another oil
company for net proceeds for each issuance to the Company of
$350,000.

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.

On December 8, 1999, the Company completed the sale of
428,000 shares of the Company's common stock in a private
transaction for net proceeds to the Company of $674,000.

On June 1, 2000, the Company issued 90,000 shares of the
Company's restricted common stock valued at $273,375 to an
unrelated entity as a deposit to acquire certain interests
in producing properties in Stark County, North Dakota.

During fiscal 2000, the Company issued 215,000 shares of the
Company's common stock to an unrelated entity as a
commission for their involvement with the Point Arguello
Unit and New Mexico acquisitions completed during fiscal
2000.

The Company received proceeds from the exercise of options
to purchase shares of its common stock of $1,377,536 during
the year ended June 30, 2000 and $160,000 during the year
ended June 30, 1999.

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, 2000 and 1999 are
as follows:

2000 1999
Weighted-Average Weighted-Average
Exercise Exercise
Options Price Options Price
Outstanding-beginning
of year 1,640,163 $1.05 1,162,977 $2.25
Granted 387,500 1.60 477,186 1.43
Exercised (391,777) (.29) - -
Repriced - - 2,110,954 .68
Returned for repricing - - (2,110,954) (1.47)
Outstanding-end
of year 1,635,886 $1.36 1,640,163 $1.05
Exercisable at
end of year 1,510,886 $.95 1,385,163 $2.32

Exercise prices for options outstanding under the plan as of
June 30, 2000 ranged from $0.05 to $9.75 per share. The
weighted-average remaining contractual life of those options
is 8.14 years. A summary of the outstanding and exercisable
options at June 30, 2000, 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

$0.05 769,736 $0.05 8.25 769,736 $0.05
$1.13-$3.25 701,150 1.78 8.64 701,150 1.78
$3.26-$9.75 165,000 5.72 5.50 40,000 3.58
1,635,886 $1.36 8.14 1,510,886 $0.95

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 5.1% and 5.5%,
dividend yields of 0% and 0%, volatility factors of the
expected market price of the Company's common stock of
64.03% and 56.07%, and a weighted-average expected life of
the options of 6.15 and 6.6 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, 2000 and 1999, would have been
$3,499,820 and $2,242,507, and basic loss per common share
would have been $.45 and $.38 per share, respectively.

Non-Qualified Stock Options - Non-Employee

In addition to options outstanding under the Company's
Incentive Plan, the following options and warrants were
outstanding at June 30, 2000:

Number Exercise Expiration
Outstanding Price Date

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
140,000 2.00 01/03/02
165,000 2.50-4.00 04/01/01
200,000 2.50 04/10/02
250,000 2.00 12/01/04
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.

During fiscal 2000, the Company issued or repriced options
to non-employees at or below market. Accordingly, the
Company recorded stock option expense in the amount of
$475,378 to non-employees.

(6) 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, 2000 and 1999, the
Company contributed $17,565 and $16,631 under the Plan.

(7) Income Taxes

At June 30, 2000 and 1999, the Company's significant
deferred tax assets and liabilities are summarized as
follows:

2000 1999
Deferred tax assets:
Net operating loss
carryforwards $9,591,000 8,163,000
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 555,000 1,058,000
Gross deferred tax assets 10,165,000 9,240,000
Less valuation allowance ( 10,165,000) (9,240,000)
Net deferred tax asset $ - $-

No income tax benefit has been recorded for the years ended
June 30, 2000 and 1999 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, 2000, the Company had net operating loss
carryforwards for regular and alternative minimum tax
purposes of approximately $25,240,000 and $24,630,000. If
not utilized, the tax net operating loss carryforwards will
expire during the period from 2000 through 2020. If not
utilized, approximately $1.4 million of net operating losses
will expire over the next five years. Net operating loss
carryforwards attributable to Amber prior to 1993 of
approximately $2,342,000, 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.

(8) Related Party Transactions

Transactions with Officers

On January 3, 2000, 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. The Company's officers
purchased 47,250 shares of the Company's securities
available for sale for a cost of $237,668. Because the
market price per share was below the Company's cost basis
the Company recorded a loss on this transaction of $107,730.

On December 30, 1999, the Company's Incentive Plan Committee
granted the Chief Financial Officer 25,000 options to
purchase the Company's common stock at $.01 per share. Stock
option expense of $62,330 has been recorded based on the
difference between the option price and the quoted market
price on the date of grant.

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 two 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 $89,668. 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, 2000, the Company had $142,582 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 $29,521 and
$23,911 for the years ended June 30, 2000 and 1999,
respectively.

Transactions with Other Stockholders

The Company has a month to month consulting agreement with
Messrs. Burdette A. Ogle and Ronald Heck (collectively
"Ogle") which provides for a monthly fee of $10,000.

On December 17, 1998, the Company amended its Purchase and
Sale Agreement , to acquire working interests in three
proved undeveloped offshore Santa Barbara, California,
federal oil and gas units, 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, 2000, the Company has paid a total of $1,900,000 in
minimum royalty payments 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.

(9) 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, 2000
and 1999 was approximately $60,000 and $53,000,
respectively. Future minimum payments under noncancelable
operating leases are as follows:

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

(10)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,
2000 1999
Undeveloped offshore
California properties $10,809,310 7,369,830
Undeveloped onshore
domestic properties 451,795 506,363
Undeveloped foreign properties 623,920 623,920
Developed Offshore California
Properties 3,285,867 -
Developed onshore domestic
properties 5,154,295 2,231,187
20,325,187 10,731,300
Accumulated depreciation
and depletion (2,457,480) (1,571,705)
$17,867,707 $9,159,595

Cost incurred in oil and gas producing activities for the
years ended June 30, 2000 and 1999 are as follows:

2000 1999
Onshore Offshore Onshore Offshore

Unproved property
acquisition costs $ - 3,439,480 1,033,920 -
Proved property
acquisition costs 2,755,658 2,607,490 16,518 -
Development costs 112,882 678,377 140,550 -
Exploration costs 32,533 14,197 74,670 -
$2,901,073 $6,739,544 $1,265,658 $-

A summary of the results of operations for oil and gas
producing activities, excluding general and administrative
cost, for the years ended June 30, 2000 and 1999 is as
follows:

2000 1999
Onshore Offshore Onshore Offshore

Revenue:
Oil and gas sales 1,198,334 2,157,449 557,503 -

Expenses:
Lease operating 345,744 2,059,725 209,438 -
Depletion 324,849 560,926 229,292 -
Exploration 32,533 14,197 74,670 -
Abandonment and
impaired properties - - 273,041 -
Dry hole costs - - 226,084 -
Results of operations of
oil and gas producing
activities $495,208 $(477,399) $(455,022) $-

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, 2000 and 1999 were:

2000 1999
A 71% -%
B 13% -%
C 7% 38%
D -% 17%

(11) 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 developed oil and gas reserves are reserves that can
be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil
and gas expected to be obtained through the application of
fluid injection or other improved recovery techniques for
supplementing the natural forces and mechanisms of primary
recovery should be included as "proved developed reserves"
only after testing by a pilot project or after the operation
of an installed program has confirmed through production
response that increased recovery will be achieved.

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, 2000 and 1999 are as follows:
<TABLE>

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

<S> <C> <C> <C> <C>
Balance at July 1, 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 - -

Revisions of quantity estimates 448,290 9,890 - -
Purchase of properties 3,166,210 107,136 - 1,771,162
Production (362,051) (9,620) - (186,989)

Balance at June 30, 2000 7,079,690 250,317 - 1,584,173

Proved developed reserves:
June 30, 1998 3,905,228 22,273 - -
June 30, 1999 2,289,024 13,140 - -
June 30, 2000 5,672,425 119,849 - 908,379

</TABLE>

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

<TABLE>

Onshore Offshore Combined

<S> <C> <C> <C>
June 30, 1999

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

Future net cash flows 5,506,364 - 5,506,364

10% discount factor 2,154,142 - 2,154,142

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

June 30, 2000

Future cash inflows $ 30,760,012 36,820,392 67,580,404
Future costs:
Production 7,712,896 12,026,623 19,739,519
Development 1,584,211 3,308,693 4,892,904
Income taxes - - -

Future net cash flows 21,462,905 21,485,076 42,947,981

10% discount factor 10,426,754 5,394,473 15,821,227

Standardized measure of discounted
future net cash flows $ 11,036,151 $16,090,603 $27,126,754

</TABLE>

The principal sources of changes in the standardized measure of
discounted net cash flows during the years ended June 30, 2000
and 1999 are as follows:

2000 1999

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

Sales of oil and gas produced during the
period, net of production costs (950,314) (348,065)
Purchase of reserves in place 21,678,174 -
Net change in prices and production costs 2,079,837 (376,526)
Changes in estimated future development
costs 218,148 891,498
Extensions, discoveries and improved
recovery - -
Revisions of previous quantity estimates,
estimated timing of development and
other 413,465 (2,558,107)
Sales of reserves in place - (1,475,484)
Accretion of discount 335,222 656,264

End of year $ 27,126,754 $3,352,222

(12) Subsequent Events

On July 5, 2000, the Company completed the sale of 258,621
shares of its restricted common stock to an unrelated entity for
$750,000. A fee of $75,000 was paid and options to purchase
100,000 shares of the Company's common stock at $2.50 per share
and 100,000 shares at $3.00 per share for one year were issued to
an unrelated individual and entity and as consideration for their
efforts and consultation related to the transaction.

On July 10, 2000, the Company paid $3,745,000 to acquire
interests in producing wells and acreage located in the Eland and
Stadium fields in Stark County, North Dakota. The July 10, 2000
payment resulted in the acquisition by the Company of 67% of the
ownership interest in each property to be acquired. An optional
payment of $1,845,000, less net production revenues accrued from
February 1, 2000, is due September 29, 2000 to purchase the
remaining ownership interest in each property. The $3,745,000
payment on July 10, 2000 was financed through borrowings from an
unrelated entity and personally guaranteed by two of the
Company's officers.

On July 21, 2000, Delta and an unrelated entity ("the
entity") entered into a definitive agreement entitled "Investment
Agreement" whereby the entity has given a firm commitment to
allow the Company to issue to the entity up to a total of
$20,000,000 of its common stock over three years from time to
time as often as monthly in amounts based upon certain market
conditions and at prices based upon market prices for the Company
common stock at the time of issuance. As consideration the
entity has received a warrant to purchase 500,000 shares of the
Company common stock at $3.00 per share for five years and may
receive additional warrants to purchase the Company common stock
under the terms of the Investment Agreement. A warrant to
purchase 150,000 shares of the entity common stock at $3.00 per
share for five years was issued to an unrelated company as
consideration for its efforts and consultation related to
potential financing alternatives and this transaction. Proceeds
will be used for property acquisitions, debt reduction and
working capital.