10KSB/A

                    SECURITIES AND EXCHANGE COMMISSION
                         Washington, D.C.   20549

                               FORM 10-KSB/A      

                              AMENDMENT NO. 2     

[X]  ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
                 For the fiscal year ended June 30, 1998.

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

                        Commission File No. 0-16203

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

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




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

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

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

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

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

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

The issuer's revenues for the fiscal year ended June 30, 1998
total $2,211,955.

The aggregate market value as of September 23, 1998 of voting
stock held by non-affiliates of the registrant was $9,180,630.    
              
As of September 23, 1998, 5,513,858 shares of registrant's Common
Stock $.01 par value were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: DEFINITIVE PROXY MATERIALS
FOR THE 1998 ANNUAL MEETING OF SHAREHOLDERS - PART III, ITEMS 9,
10, 11, AND 12.


                 The Index to Exhibits appears at Page 35. 


                            TABLE OF CONTENTS

                                 PART I

                                                            PAGE

ITEM 1.   DESCRIPTION OF BUSINESS                           1
ITEM 2.   DESCRIPTION OF PROPERTY                           7
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                              33
ITEM 8.   CHANGES IN AND DISAGREEMENTS WITH 
               ACCOUNTANTS ON ACCOUNTING
               AND FINANCIAL DISCLOSURE                     33
     
                                 PART III

ITEM 9.   DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
               AND CONTROL PERSONS; COMPLIANCE
               WITH SECTION 16(a) OF THE 
               EXCHANGE ACT                                 33
ITEM 10.  EXECUTIVE COMPENSATION                            33
ITEM 11.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
               OWNERS AND MANAGEMENT                        33
ITEM 12.  CERTAIN RELATIONSHIPS AND RELATED
                TRANSACTIONS                                33
ITEM 13.  EXHIBITS AND REPORTS ON FORM 8-K                  33
     

                                  PART I


ITEM 1.   DESCRIPTION OF BUSINESS

     (a)  Business Development.

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

          The Company is engaged in the acquisition, exploration,
development and production of oil and gas properties.  As of June
30, 1998, the Company had varying interests in 96 gross (18.57
net) productive wells located in six states.  The Company has
undeveloped properties in five states, and interests in four
federal units and one lease offshore California near Santa
Barbara.  The Company operates 24 of the wells and the remaining
wells are operated by independent operators.  All wells are
operated under contracts that are standard in the industry.  At
June 30, 1998, the Company estimated proved reserves attributable
to its onshore properties to be approximately 147,000 Bbls of oil
and 9.44 Bcf of gas, of which approximately 22,000 Bbls of oil
and 3.91 Bcf of gas were proved developed reserves.  At June 30,
1998, the Company estimated proved undeveloped reserves
attributable to its offshore California properties to be
approximately 69,200,000 Bbls of oil and 74.6 Bcf of gas.  There
are uncertainties as to the timing of the development of the
offshore properties.  (See "Description of Property;" Item 2
herein.)

          At June 30, 1998, Delta 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 5,513,858 shares of common
stock were issued and outstanding.  Delta has outstanding
warrants and options to purchase 889,500 shares of common stock
at prices ranging from $1.25 per share to $8.50 per share at June
30, 1998.  Additionally, Delta has outstanding options which were
granted to officers, employees and directors under the
Company's 1993 Incentive Plan to purchase up to 1,162,977 shares
of common stock at prices ranging from $1.25 to $9.75 per share
at June 30, 1998. 

          At June 30, 1998, the Company owned 4,277,977 shares of
common stock of Amber Resources Company ("Amber"), representing
91.68% of the outstanding common stock of Amber. Amber is a
public company (registered under the Securities Exchange Act of
1934) whose activities include oil and gas exploration,
development, and production operations. Amber owns interests in
producing oil and gas properties in Oklahoma and non-producing
oil and gas properties offshore California near Santa Barbara.
The Company and Amber entered into an agreement effective March
31, 1993 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, 1998, Delta was engaged
in only one industry, namely the acquisition, exploration,
development, and production of oil and gas properties and related
business activities.  The Company's oil and gas operations have
been comprised primarily of production of oil and gas, drilling
exploratory and development wells and related operations and
acquiring and selling oil and gas properties. The Company,
directly and through Amber, currently has producing oil and gas
interests, undeveloped leasehold interests and related assets in
south Texas; interests in proven but undeveloped offshore Federal
leases and units near Santa Barbara, California; producing and
non-producing interests in the Denver-Julesburg and Piceance
Basins of Colorado; the Sacramento Basin of California, the Wind
River Basin of Wyoming, the Anadarko Basin in Oklahoma and in the
Arkoma Basin in western Arkansas.  The Company intends to
continue its emphasis on the drilling of exploratory and
development wells primarily in Colorado, California, Texas,
Wyoming and Oklahoma.

          The Company intends to drill on some of its 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 the Company are crude oil and
natural gas.  The products are generally sold at the wellhead to
purchasers in the immediate area where the product is produced. 
The principal markets for oil and gas are refineries and
transmission companies which have facilities near the Company's
producing properties.

          (2)  Distribution Methods of the Products or Services. 
Oil and natural gas produced from the Company's wells are
normally sold to the purchasers referenced in (6) below.  Oil is
picked up and transported by the purchaser from the wellhead.  In
some instances the Company is charged a fee for the cost of
transporting the oil, which fee is deducted from or 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.  The Company has not made a public announcement of, and
no information has otherwise become public about, a new product
or industry segment requiring the investment of a material amount
of the Company's total assets.

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

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

          (6)  Dependence on One or a Few Major Customers.  Delta
has one major customer for the sale of oil and gas as of the date
of this report, namely, Tristar Gas Marketing.  The loss of this
customer would not have a material adverse effect on Delta's
business.

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

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

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

               General.

     Delta's 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 Delta's business.  In view of
the many uncertainties with respect to current and future laws
and regulations, including their applicability to Delta, the
Company cannot predict the overall effect of such laws and
regulations on its future operations. 

     Delta believes that its 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 the Company's 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 it
operates, the Company's 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 the Company's
operations. The duration and success of obtaining such approvals
are contingent upon many variables, many of which are not within
the Company's control.  To the extent such approvals are required
and not obtained, operations may be delayed or curtailed, or the
Company may be prohibited from proceeding with planned
exploration or operation of facilities.

     Environmental laws and regulations are expected to have an
increasing impact on the Company's operations, although it is
impossible to predict accurately the effect of future
developments in such laws and regulations on the Company's future
earnings and operations.  Some risk of environmental costs and
liabilities is inherent in particular operations and products of
the Company, 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, the Company does not
currently expect any material adverse effect upon its 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 the 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 the
Company to incur substantial environmental liabilities or costs.
 
     Hazardous Substances and Waste Disposal.

     Delta currently owns or leases 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 the Company.  In addition, some of
these properties have been operated by third parties over whom
the Company 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 the Company's operations impose clean-up liability
regarding petroleum and petroleum related products.  In addition,
although RCRA currently classifies certain exploration and
production wastes as "nonhazardous," such wastes could be
reclassified as hazardous wastes thereby making such wastes
subject to more stringent handling and disposal requirements.  If
such a change in legislation were to be enacted, it could have a
significant impact on the Company's operating costs, as well as
the gas and oil industry in general.
 
     Oil Spills.

     Under the Federal Oil Pollution Act of 1990, as amended
("OPA"), (i) owners and operators of onshore facilities and
pipelines, (ii) lessees or permittees of an area in which an
offshore facility is located and (iii) owners and operators of
tank vessels ("Responsible Parties") are strictly liable on a
joint and several basis for removal costs and damages that result
from a discharge of oil into the navigable waters of the United
States.  These damages include, for example, natural resource
damages, real and personal property damages and economic losses. 
OPA limits the strict liability of Responsible Parties for
removal costs and damages that result from a discharge of oil to
$350 million in the case of onshore facilities, $75 million plus
removal costs in the case of offshore facilities, and in the case
of tank vessels, an amount based on gross tonnage of the vessel.
However, these limits do not apply if the discharge was caused by
gross negligence or wilful misconduct, or by the violation of an
applicable Federal safety, construction or operating regulation
by the Responsible Party, its agent or subcontractor or in
certain other circumstances.
 
     In addition, with respect to certain offshore facilities,
OPA requires evidence of financial responsibility in an amount of
up to $150 million.  Tank vessels must provide such evidence in
an amount based on the gross tonnage of the vessel.  Failure to
comply with these requirements or failure to cooperate during a
spill event may subject a Responsible Party to civil or criminal
enforcement actions and penalties.
 
     Offshore Production.

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

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

          (12) Employees.  The Company has five full time
employees.

ITEM  2.  DESCRIPTION OF PROPERTY

     (a)  Office Facilities.

          Delta's offices are located at 555 Seventeenth Street,
Suite 3310, Denver, Colorado 80202.  Delta leases approximately
4,837 square feet of office space for $7,125 per month and the
lease will expire in April of 2002.  Currently, Delta subleases
approximately 1,500 square feet to Bion Environmental
Technologies, Inc. for $2,500 per month.  

     (b)  Oil and Gas Properties.

          The Company owns interests in oil and gas properties
located in California, Colorado, Oklahoma, Texas, Wyoming and
elsewhere. Most wells from which the Company receives revenues
are owned only partially by the Company. For information
concerning the Company's 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. The
Company 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, 1998, 1997
and 1996.

          Principal Properties.

          The following is a brief description of Delta's
principal properties:

          Onshore:

          California: Sacramento Basin Area
               
          The Company is participating 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%.  The Company sold its interest in a fourth such survey in
the area in March of 1998.  These programs are operated by
Slawson Exploration Company, Inc.  The program areas contain
approximately 90 square miles in the aggregate upon which the
Company has participated in the costs of collecting and
processing 3-D seismic data, acquiring leases and drilling wells
upon these leases.  As of September 23, 1998 leases or options to
lease have been acquired within the program areas totaling
approximately 22,000 gross acres.  Seismic information has been
gathered, processed and interpreted on all three surveys. 
Processing and interpretation of the 90 square miles of seismic
information which has already been run in these areas has
revealed approximately  41 drillable prospects.  Wells
are being drilled on these prospects to test the Forbes, Starkey
and Winters gas formations at depths ranging from 3,000 to 8,000
feet and are expected to cost about $450,000 per well to drill
and complete.  The Company has the right to participate with a
12% to 15% working interest in the wells to be drilled on the
prospects revealed by the 3-D seismic evaluations.  As of
September 23, 1998, 11 wells have been drilled and casing has
been run on six of these.  The Company expects to participate in
the drilling of an additional nine wells during the remainder of
fiscal 1999 assuming the Company has adequate funds.  The area
appears to have adequate markets for the volumes of natural gas
that are projected from the drilling activity in the area.
  
          Colorado.

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

          Piceance Basin.  The Company owns working interests in
13 gas wells (10.3 net), and oil and gas leases covering 14,328
net acres in the Piceance Basin in Mesa and Rio Blanco counties,
Colorado.  The Company is evaluating the possibility of
recompleting additional zones in many of its other wells.  The
acreage is located in and around the Plateau Field.  

          Oklahoma.

          The Company directly (21 wells) and through Amber (36
wells) owns non-operating working interests in 57 natural gas
wells in Oklahoma. The wells range in depth from 4,500 to 20,000
feet and produce from the Red Fork, Atoka, Morrow and Springer
formations.  Most of the Company's reserves are in the Red
Fork/Atoka formation.  The working interests range from less than
1% to 40% and average about 8% per well.  Many of the wells have
remaining productive lives of 20 to 30 years.  

          Wyoming.  

          Moneta Hills.  In 1997 the Company 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.  The second well was scheduled to be
drilled prior to the end of calendar 1997, but has been delayed
indefinitely.  Delta will evaluate the results of these first two
wells in addition to other factors in making its decisions to
participate for its 20% working interest in any subsequent wells. 

          Texas.

     Austin Chalk Trend.  The Company owns leasehold interests in
approximately 1,558 gross acres (393 net acres) and owns
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.  The Company is evaluating the
possibility of re-entering one or more of these wells and
drilling additional horizontal bores in other untapped zones.  

          Offshore:

          Offshore Federal Waters: Santa Barbara, California Area 

          Delta Petroleum Corporation, directly and through its
subsidiary, Amber Resources Company, owns interests in four
proved 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 814
million Bbls of oil and 756 billion cubic feet of gas have been
produced and sold.  During 1998, POCS production has been
approximately 160,000 Bbls of oil and 200 million cubic feet of
gas per day according to the Minerals Management Service of the
Department of the Interior ("MMS").

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

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

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

          The first three miles seaward of the coastline are
administered by each state and are known as "State Tidelands" in
California.  Within the State Tidelands off Santa Barbara County,
the State of California, through the State Lands Commission,
regulates oil and gas leases and the installation of permanent
and temporary producing facilities.  Because the 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 the production will be
transported to an on-shore facility through the state waters, the
Company's pipelines (or other transportation facilities) will be
subject to California state regulations.  Construction and
operation of the pipelines will require permits from the state.  
Additionally, all development plans must be consistent with the
Federal Coastal Zone Management Act ("CZM").   In California the
decision of CZM consistency is made by the California Coastal
Commission.

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

          The Company's Offshore California proved undeveloped
reserves are attributable to its interests in four federal units
(plus one additional lease) located offshore California near
Santa Barbara.  While these interests represent ownership of
substantial oil and gas reserves classified as proved
undeveloped, the cost to develop the reserves will be
substantial.  The estimated cost, which will be incurred over the
life of the properties (assumed to be 38 years), for the complete
development of all of the properties in which Delta owns an
interest, including delineation wells, environmental mitigation,
development wells, fixed platforms, fixed platform facilities,
pipelines and power cables, onshore facilities and platform
removal is currently estimated to be slightly in excess of
approximately $3 billion. The Company's share of such
costs is estimated to be $216,000,000.  Operating expenses for
the same properties over the same period of time, including
platform operating costs, well maintenance and repair costs, oil,
gas and water treating costs, lifting costs and pipeline
transportation costs are expected to be approximately
$3,325,000,000 with the Company's share estimated to be
$285,000,000.  

          Each working interest owner will be required to pay its
proportionate share of these costs based upon the amount of the
interest that it owns.  The size of Delta's working interest in
the units varies from 2.492% to 15.60%.  The Company may be
required to farm out all or a portion of its interests in these
properties to a third party if it cannot fund its share of the
development costs.  There can be no assurance that the Company
can farm out its interests on acceptable terms.  If the Company
were to farm out its interests in these properties, its share of
the proved reserves attributable to the properties would be
decreased substantially.  The Company may also incur substantial
dilution of its interests in the properties if it elects to use
other methods of financing the development costs. Net revenues
over the same time period, to be shared by all of the working
interest owners in proportion to the size of their respective
working interests, are estimated to be approximately
$2,924,000,000 after the payment of all of the above
expenses and amounts due to owners of royalty interests with
Delta's share estimated to be $228,000,000.
   
          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.  The Company does not
have a controlling interest in and does not act as the operator
of any of the offshore California properties and consequently
will not generally control the timing of either the development of the
properties or the expenditures for development unless Delta chooses 
to unilaterally propose the drilling of wells under the relevant
operating agreements.  Management and its independent engineering
consultant have considered these factors relating to timing of the
development of the reserves in the preparation of the reserve information
relating to these properties.  It is anticipated that, based upon discussions
with appropriate governmental agencies, development of the subject
leases will require from three to five years for permitting. 
Because of the substantial reserves contained in the
projects, it is generally accepted that they will be developed;
however, the time required to complete development may be from
five to ten years.  As additional information becomes available
in the future, the Company's estimates of the proved undeveloped
reserves attributable to these properties could materially
change.
    
          The MMS initiated the California Offshore Oil and Gas
Energy Resources (COOGER) study at the request of the local
regulatory agencies of the three counties (Ventura, Santa Barbara
and San Luis Obispo) affected by offshore oil and gas
development.  A private consulting firm is currently conducting
the study under a contract with the MMS.  The COOGER study seeks
to present a long-term regional perspective of potential onshore
constraints that should be considered when developing existing
undeveloped offshore leases.  COOGER will project the
economically recoverable oil and gas production from offshore
leases which have not yet been developed.  These projections will
be utilized to assist in identifying a potential range of
scenarios for developing these leases.  These scenarios will then
be compared to the projected infrastructural, environmental and
socioeconomic baselines between 1995 and 2015.  

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

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

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

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

               Scenario 4     Development of existing leases
               after decommissioning and removal of some or all
               existing onshore facilities.  This scenario
               includes new facilities, and perhaps new sites,
               to handle anticipated potential future production.
               There is currently insufficient information
               available to assess the impact of this scenario on
               Delta, but it would appear likely that Delta would
               incur increased costs and that revenues would be
               received more quickly.
 
               The Company has also evaluated its position with
     regard to the scenarios currently being studied with respect
     to properties located in the northern subregion (which
     includes the Lion Rock Unit and the Point Sal Unit), the
     results of which are as follows:

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

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

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

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

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

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

          Current Status.  On November 5, 1996, the MMS issued a
Directed Suspension of Operations for the POCS Non-Producing
Leases and Units, pursuant to CFR 250.10(b)(4), extending the
existing Suspension of Operations ("SOO") from January 1, 1997
until December 31, 1998.  This action permitted unit owners to
cease paying lease payments to the Federal government and
suspended the requirements relating to development of the leases
during this period.  The Directive cited the fact that the MMS
had requested in 1992 that the lease owners participate in what
became known as the COOGER (California Offshore Oil and Gas
Energy Resources) Study and during the term of the Study that the
leases would be held under a SOO.
   
          The MMS issued a second letter on December 24, 1996
with the intent to notify all lease owners of the course of
action to be followed by the lease and unit operators prior to
the expiration of the SOO.   In another letter, on September 17,
1998, the MMS informed all owners and operators that due to
delays in the COOGER Study, the SOO's on the units would be
extended through the first quarter of 1999 and revised the dates
for actions required by the previous letters.  During 1998 each
operator is to meet with the MMS to discuss conceptual plans that
will lead to the timely development of the leases.  By January 15, 1999,
each operator has been directed to submit what the MMS has termed
"Schedule of Events" for a specific lease or unit that it operates
and also a request for a Suspension of Production time period to execute the
Schedule of Events.  The lease and unit Schedule of Events, when
approved by the MMS, will go into effect on April 1, 1999.
    
          In order to carry out the requirements of the December
24, 1996 and September 17, 1998 MMS letters, all operators of the
units in which the Company owns non-operating interests
(described below) are currently engaged in studies to develop a
conceptual framework and general timetable for continued
delineation and development of the leases.  For delineation, the
operators will outline the mobile drilling unit well activities,
including number and location.  For development, the operators'
reports will cover the total number of facilities involved,
including platforms, pipelines, onshore processing facilities,
transportation systems and marketing plans.  The Company is
participating with the operators in meeting the MMS schedules
through meetings, and consultations and is sharing in the costs
as invoiced by the operators. 

          Based on prices of $9.11 per Bbl and $1.41 per Mcf and
applicable regulatory parameters, the Company's aggregate working
interests in these properties had a pre-tax present value
(discounted at 10%) of approximately $7,185,000 as of July 1,
1998 according to a reserve report issued by Forrest A. Garb &
Associates ("Garb"), an independent petroleum engineering firm in
Dallas, Texas.  According to Garb's report, Delta's Offshore
California reserves from these units totaled approximately
69,201,000 Bbls of oil and 74.6 Bcf of gas for an aggregate
equivalent of 81,638,000 BOE. 

     Cost to Develop Offshore California Properties.  The cost to
develop all of the offshore California properties in which Delta
owns an interest, including delineation wells, environmental
mitigation, development wells, fixed platforms, fixed platform
facilities, pipelines and power cables, onshore facilities and
platform removal over the life of the properties (assumed to be
38 years), is estimated to be slightly in excess of $3 billion. 
The Company's share of such costs over the life of the properties
is estimated to be $216,000,000.  Although the revenues that are
forecasted to be generated by production from the properties are
generally expected to exceed expenses and should therefore be
available to pay development costs, Delta anticipates (based upon
current costs and petroleum prices) that during approximately the
first seven years of development, its share of expenses will
exceed revenues by an estimated aggregate of nearly $120 million. 

     Not all of this nearly $120 million, however, will be
required to be expended by Delta at any one time.  Instead, these
costs will be incurred over a significant period of time after
development has commenced and while production is being
established.  Based upon current costs and petroleum prices,
Delta presently anticipates that expenses will exceed revenues by
approximately $1 million during the first year of development, $4
million during the second year, $17 million during the third
year, $22 million during the fourth year, $45 million during the
fifth year, $23 million during the sixth year and $7 million
during the seventh year.  After the seventh year, it is currently
anticipated that production revenues generated from the
properties (net of operating expenses) will be sufficient to
cover all of the remaining development costs.

     To the extent that Delta does not have sufficient cash
available to pay its share of these expenses when they become
payable under the respective operating agreements, it will be
necessary for Delta to seek funding from outside sources.  Likely
potential sources for such funding are currently anticipated to
include (a) public and private sales of Delta 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 Delta's interests in the properties whereby the recipient of
the farm-out would pay the full amount of Delta's share of
expenses and Delta would retain a carried ownership interest
(which would result in a substantial diminution of Delta's
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
Delta's interests in the properties.

     It is unlikely that any one potential source of funding
would be utilized exclusively.  Rather, it is more likely that
Delta 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 Delta's small size in relation to the
magnitude of the capital requirements that will be associated
with the development of the subject properties, Delta 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 Delta's assets
(including its offshore California properties), reduce its
ownership interest in the properties through sales of interests
in the property or as the result of farm-outs, industry financing
arrangements or other partnership or joint venture relationships,
or to enter into transactions which will result in some
combination of the foregoing.  In the event that Delta is not
able to pay its share of expenses as a working interest owner as
required by the respective operating agreements, it is possible
that Delta might lose some portion of its ownership interest in
the properties under some circumstances, or that Delta might be
subject to penalties which would result in the forfeiture of
substantial revenues from the properties.

     While the cost to develop the offshore California properties
in which Delta owns an interest will be substantial in relation to
Delta's small size, management believes that the opportunities for
Delta to increase its asset base and ultimately improve its cash
flow are also substantial in relation to its size.  Although there
are several factors to be considered in connection with Delta's
plans to obtain funding from outside sources as necessary
to pay its proportionate share of the costs associated with
developing its offshore properties (not the least of which is the
possibility that prices for petroleum products could continue
to decline in the future to a point at which development of
the properties is no longer economically feasible), management
believes 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 decline further
from their current near historic lows, it is likely that development
efforts will proceed at a slower pace to the end that costs will be
incurred over a more extended period of time.  In the event that
petroleum prices increase, however, management believes that
development efforts will intensify.  Delta's ability to successfully
negotiate financing to pay its 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. The Company holds 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 announced the completion and
test of the Samedan  P-0460 #2 which yielded a test flow rate of
5,500 Bbls of oil per day from the Monterey Formation between
5,000 and 6,800 feet of drill depth. The Monterey Formation is a
highly fractured shale formation. The Monterey (which ranges from
500' to 2,900' in thickness) is the main productive and target
zone in many offshore California oil fields (including the
Company's federal leases and/or units).  As of July 1, 1998, Garb
issued a report stating that Gato Canyon contains proved
recoverable reserves estimated to be 119.8 million
Bbls of oil and 167.8 Bcf of natural gas, representing 15.58
million Bbls of oil and 21.81 Bcf of natural gas net to the
Company's 15.60% working interest at July 1, 1998.  The oil has
an estimated average gravity of 16 degrees API.  (See Item 7.
Financial Statements: Footnote 9, "Information Regarding Proved Oil and Gas
Reserves".) 

          The Gato Canyon field is located in the Santa Barbara
Channel approximately three to five miles offshore (see Map). 
Water depths range from 280 feet to 600 feet in the area of the
field.  Oil and gas produced from the field will be processed
onshore at the existing Las Flores Canyon facility (see Map). 
Las Flores Canyon has been designated a "consolidated site" by
Santa Barbara County and is available for use by offshore
operators.  The processed oil is expected to be transported out
of Santa Barbara County in the All American Pipeline (see Map). 
Offshore pipeline distances to access the Las Flores site is
approximately six miles.  Delta Petroleum's share of estimated
capital costs to develop the Gato Canyon field are approximately
$45,000,000.
   
          The Gato Canyon Unit leases are currently held under a
Suspension of Operations until March 31, 1999.  Thereafter, the
Unit operator will carry out a Schedule of Events under a
Suspension of Production.  The Schedule of Events will include
the preparation of an updated Exploration Plan, which 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.  The reserve report prepared by the Company's
independent petroleum engineer as of July 1, 1998 assumes that 
production will commence in 2002.
    
          Point Sal Unit.  The Company holds a 6.83% working
interest in the Point Sal Unit.  This 22,772 acre unit is
operated by Aera Energy LLC, a limited liability company jointly
owned by Shell Oil Company and Mobil Oil Company.  Four test
wells were drilled within this unit.  These test wells were
drilled as follows: two wells were drilled by Sun Oil (now Oryx
Energy), one in 1984 and one in 1985; and the other two wells
were drilled by Reading & Bates, both in 1984.  All four wells
drilled on this unit have indicated the presence of oil and gas
in the Monterey Formation.  The largest of these, the Sun P-0422
#1, yielded a combined test flow rate of 3,750 Bbls of oil per
day from the Monterey. The oil in the upper block has an average
estimated gravity of 10 degrees API and the oil in the subthrust
block has an average estimated gravity of 15 degrees API.  Based on a
report prepared by Garb as of July 1, 1998, Point Sal Unit contains
proved undeveloped recoverable reserves of 258.5 million Bbls of
oil and 289.5 Bcf of natural gas, equivalent to 14.71 million
Bbls of oil and 16.48 Bcf of natural gas net to the Company's
6.83% interest at July 1, 1998.  (See Item 7. Financial
Statements: Footnote 9, "Information Regarding Proved Oil and Gas
Reserves".)

          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.  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).  The processed oil will be transported
out of Santa Barbara County in either the All American Pipeline
or the Tosco-Unocap Pipeline (see Map).  Offshore pipeline
distance is approximately six to eight miles depending on the
final choice of the point of landfall.  Delta Petroleum's share
of estimated capital costs to develop the Point Sal unit are
approximately $38,000,000.
   
          The Point Sal Unit leases are currently held under a
Suspension of Operations until March 31, 1999.  Thereafter, the
Unit operator will carry out a Unit Schedule of Events under a
Suspension of Production.  The Schedule of Events will include
preparation of an updated Exploration Plan which is expected to
include plans to drill an additional delineation well prior to
preparing the Development Plan.  The reserve report prepared by
the Company's independent petroleum engineer as of July 1, 1998
assumes that production will commence in 2003.
    
          Lion Rock Unit and Federal OCS Lease P-0409. The
Company holds 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.   Based on a report prepared by Garb as of July 1, 1998,
the Lion Rock Unit (including lease P-0409) contains proved
undeveloped recoverable reserves of 516.2 million Bbls of oil and
464.5 Bcf of natural gas, equivalent to 34.06 million Bbls of oil
and 30.66 Bcf of natural gas net to the Company's interest at
July 1, 1998.  The oil has an average estimated gravity of 10.7
degrees API. (See Item 7. Financial Statements: Footnote 9, "Information
Regarding Proved Oil and Gas Reserves".)  The Garb evaluation
includes the Lion Rock Unit and Federal OCS Lease P-0409 which
are both included in the San Miguel Field.  This lease is not
currently part of the Lion Rock Unit, but prior to development
the Lion Rock Unit is expected to be expanded to include P-0409.  

     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.  The oil and gas produced at Lion Rock and P-
0409 will be processed at a new facility in the onshore Santa
Maria Basin or at the existing Lompoc facility (see Map).  The
oil will be transported out of Santa Barbara County in the All
American Pipeline or the Tosco-Unocap Pipeline (see Map). 
Offshore pipeline distance will be eight to ten miles depending
on the point of landfill.  Delta's share of the estimated capital
costs to develop the Lion Rock/San Miguel field is approximately
$113,000,000.
   
          The Lion Rock Unit and Lease P-0409 are currently held
under a Suspension of Operations until March 31, 1999. 
Thereafter, the Unit operator will carry out a Schedule of Events
under a Suspension of Production.  The Schedule of Events will
include interpretation of the 3D seismic survey and the
preparation of an updated Plan of Development leading to
production.  Additional delineation wells may or may not be
drilled depending on the outcome of the interpretation of the 3D
survey.  The reserve report prepared by the Company's independent
petroleum engineer as of July 1, 1998 assumes that production
will commence in 2002.
    
          Sword Unit. The Company holds 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.
Based on a July 1, 1998 report prepared by Garb, the Sword Unit
contains proved undeveloped recoverable reserves of 158.1 million
Bbls of oil and 189.8 Bcf of natural gas representing reserves of
3.28 million Bbls of oil and 3.94 Bcf of natural gas net to the
Company's interest at July 1, 1998.   (See Item 7. Financial
Statements: Footnote 9, "Information Regarding Proved Oil and Gas
Reserves".) 

          The Sword field is located in the western Santa Barbara
Channel ten miles west of Point Conception and five miles south
of Point Arguello's field Platform Hermosa (see Map).  Water
depths range from 1000 feet to 1800 feet in the area of the
field.  The oil and gas produced from the Sword Field will likely
be processed at the existing Gaviota consolidated facility and
the oil transported out of Santa Barbara County in the All
American Pipeline (see Map).  Access to the Gaviota plant is
through Platform Hermosa and the existing Point Arguello Pipeline
system.  A pipeline laid from a platform located in the northern
area of the Sword field to Platform Hermosa will be approximately
five miles in length.  Delta's share of the estimated capital
costs to develop the Sword field is approximately $19,300,000.
   
          The Sword Unit leases are currently held under a
Suspension of Operations until March 31, 1999.  Thereafter, the
Unit operator will carry out a Schedule of Events under a
Suspension of Production.  Included in the Schedule of Events
will be preparation of an updated Exploration Plan which is expected
to include plans to drill an additional delineation well. 
The reserve report prepared by the Company's independent petroleum
engineer as of July 1, 1998 assumes that production will commence in 2004.
    
                         MAP INSERT HERE

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

     (c)  Production.

          The Company is not obligated to provide a fixed and
determined quantity of oil and gas in the future under existing
contracts or agreements.   During the years ended June 30, 1998,
1997 and 1996, the Company has not had, nor does it now have, any
long-term supply or similar agreements with governments or
authorities pursuant to which the Company acted as 
producer. The following table sets forth the Company's average
sales prices and average production costs during the periods
indicated:

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

Average sales price:                             
   Oil (per barrel)          $16.46         22.36          17.74  
   Natural Gas (per Mcf)      $2.26          2.41           1.71  
 
Production costs
 (per Mcf equivalent)          $.67           .85            .78  
 

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

    (d)   Productive Wells and Acreage.

          The table below shows, as of June 30, 1998, the
approximate number of gross and net producing oil and gas wells
by state and their related developed acres owned by the Company.
Calculations include 100% of wells and acreage owned by Delta and
by Amber. Productive wells are producing wells capable of
production, including shut-in wells. Developed acreage consists
of acres spaced or assignable to productive wells.

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

Texas          4    1.82          0        .0            1,558       393
Colorado       8     .8          13      10.3            2,560     2,127
Oklahoma       1     .1          58       3.68          24,793     1,857
California     0     .0           6        .67             800       100
Wyoming        0     .0           6       1.2              960       192
              13    2.72         83      15.85          30,671     4,669

(1)  All of the wells classified as "oil" wells are also
productive of 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, 1998, the Company held undeveloped acreage
by state as set forth below:

                                     Undeveloped Acres (1) (2)
     
             Location                       Gross           Net 
     
     California, offshore(3)                50,805        4,244
     California, onshore                    21,760        2,837
     Colorado                               17,018       14,375
     Wyoming                                 9,696        1,939
     Oklahoma                                3,360          271
                           Total           102,639       23,666
     
(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 periods indicated, the Company drilled or
participated in the drilling of the following productive and
nonproductive Exploratory and Development Wells:


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

Exploratory Wells(1):
Productive:
  Oil. . . . . . . . .   0    .0        0    .0        0    .0
  Gas. . . . . . . . .   5    .545      0    .0        0    .0
Nonproductive. . . . .   1    .113      1   1.0        0    .0
Total. . . . . . . . .   6    .658      1   1.0        0    .0

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

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

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

    (g)  Present Drilling Activity

         Between July 1, 1998 and September 23, 1998, the
Company participated in the drilling of six new wells on its
properties in the Sacramento Basin.  Two of the six wells are
successful and will be selling gas within a few weeks.  The
Company plans to participate in the drilling of at least
four additional wells on these properties during the
next 90 days assuming the Company has sufficient capital. 

ITEM 3.  LEGAL PROCEEDINGS

         The Company is not engaged in any material pending legal
proceedings to which the Company or its subsidiaries are a party
or to which any of its property is subject.


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

         Not applicable.

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.
                                                            
                                                              Period of
      Name               Age       Positions                   Service
   

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

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

Terry D. Enright          49      Director                 November 1987
                                                             to Present

Jerrie F. Eckelberger     54      Director                September 1996
                                                             to Present
                   
     The following is biographical information as to the
business experience of each current officer and director of the
Company.

     Aleron H. Larson, Jr., age 53, has operated as an
independent in the oil and gas industry individually and through
public and private ventures since 1978.  From July of 1990
through March 31, 1993,  Mr. Larson served as the Chairman,
Secretary, C.E.O. and a Director of Underwriters Financial Group,
Inc. ("UFG") (formerly Chippewa Resources Corporation), a public
company then listed on the American Stock Exchange which
presently owns approximately 16.67% of the outstanding equity
securities of Delta.  Subsequent to a change of control, Mr.
Larson resigned from all positions with UFG effective March 31,
1993.  Mr. Larson serves as Chairman, CEO, Secretary, Treasurer
and Director of 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 36, served as the President, a
Director and Chief Operating Officer of Underwriters Financial
Group from July of 1990 through March 31, 1993.  Mr. Parker
resigned from all positions with UFG effective March 31, 1993. 
Mr. Parker also serves as President, Chief Operating Officer and
Director of 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 49, 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 54, is an investor, real
estate developer and attorney who has practiced law in the State
of Colorado for 26 years.  He graduated from Northwestern
University with a Bachelor of Arts degree in 1966 and received
his Juris Doctor degree in 1971 from the University of Colorado
School of Law.  From 1972 to 1975, Mr. Eckelberger was a staff
attorney with the eighteenth Judicial District Attorney's Office
in Colorado.   From 1982 to 1992 Mr. Eckelberger was the senior
partner of Eckelberger & Feldman, a law firm with offices in
Englewood, Colorado.  In 1992, Mr. Eckelberger founded
Eckelberger & Associates of which he is still the principal
member.  Mr. Eckelberger previously served as an officer,
director and corporate counsel for Roxborough Development
Corporation.  Since March, 1996, Mr. Eckelberger has acted as
President and Chief Executive Officer of 1998,
Ltd., a Colorado corporation actively engaged in
the development of real estate in Colorado.  He is the Managing
Member of The Francis Companies, L.L.C., a Colorado limited
liability company, which actively invests in real estate and
has been since June, 1996.  Additionally, since November, 1997,
Mr. Eckelberger has served as the Managing Member of the Woods
at Pole Creek, a Colorado limited liability company specializing
in real estate development.


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

     Messrs. Enright and Eckelberger serve as the audit
committee and as the compensation committee.  Messrs. Enright and
Eckelberger also constitute the Incentive Plan Committee for the
Delta 1993 Incentive Plan for the Company.  

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

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

     There is no employee who is not a designated officer or
director who is expected to make any significant contribution to
the business 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, 1996              7.63           4.88    
         December 31, 1996               6.75           4.25    
         March 31, 1997                  6.63           3.88
         June 30, 1997                   4.38           3.25    
         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    
    
         On September  23, 1998, the closing price of the Common
Stock was $2.50.

         (b)  Approximate Number of Holders of Common Stock.

              The number of holders of record of the Company's
Common Stock at August 22, 1998 was approximately 979 which does
not include an estimated 2,930 additional holders whose stock is
held in "street name".

         (c)  Dividends.

              The Company has not paid dividends on its stock and
does not expect to do so in the foreseeable future.

         (d)  Recent Sales of Unregistered Securities.

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

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

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

              On August 18, 1995, the Company sold an aggregate
of 276,000 shares of common stock in a private transaction to a
private company for $750,000 ($650,000 net of fees).  

              During the years ended June 30, 1997 and 1996, the
Company 100,117 and 42,527 shares of its 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.  

              Within the last three fiscal years unregistered
securities were sold under Regulation S to non-U.S. persons in
the following private offshore transactions.

              On March 7, 1996 the Company sold 115,000 shares of
its restricted and legended common stock to C.A. Oportunidad S.A.
of San Jose, Costa Rica for $550,000.

              On May 17, 1996, the Company sold 80 shares of
restricted and legended Series C Convertible Preferred stock to
C.A. Oportunidad, S.A. of San Jose, Costa Rica for $800,000.  The
Company paid the Bruce R. Knox Corporation an investment banking
fee equal to 10% of the proceeds.   The 80 shares of Series C
Convertible Preferred stock were later converted to 183,738
shares of common stock.

              On July 6, 1996, the Company sold 80 shares of
restricted and legended Series C Convertible Preferred stock to
Fondo de Adquisciones E Inverseones Internacionales XL, S.A. of
San Jose, Costa Rica for $800,000.  The Company paid the Bruce R.
Knox Corporation an investment banking a fee equal to 10% of the
proceeds.  The 80 shares of Series C Convertible Preferred stock
were later converted to 212,863 shares of common stock.


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

    Liquidity and Capital Resources. 

         At June 30, 1998, the Company had a working capital
deficit of $465,854 compared to a working capital deficit of
$411,403 at June 30, 1997. 

         The Company's current liabilities include royalties
payable of $264,320 at June 30, 1998 which represent the
Company's estimate of royalties payable on production
attributable to Amber's interest in certain wells in Oklahoma,
including production prior to the acquisition of Amber. The
Company believes that the operators of the affected wells have
paid some of the royalties on behalf of the Company and have
withheld such amounts from revenues attributable to the Company's
interest in the wells.  The Company has contacted the operators
of the wells in an attempt to determine what amounts the
operators have paid on behalf of the Company over
the past five years, which amounts would reduce the amounts owed
by the Company.  To date the Company has not received information
adequate to allow it to determine the amounts paid by the
operators.  The Company has been informed by its legal counsel
that the applicable statue of limitations period for actions on
written contracts arising in the state of Oklahoma is five years. 
The statute of limitation has expired for royalty owners to make
a claim for a portion of the estimated royalties that had
previously been accrued.  Accordingly, these amounts have been
written off and recorded as other income in 1998 and 1997.

         The Company believes that it is unlikely that all claims
that might be made for payment of royalties payable in suspense
or for recoupment royalties payable would be made at one time. 
Further, Amber, rather than Delta, would be directly liable for
payment of any such claims.  The Company believes, although there
can be no assurance, that it may ultimately be able to settle
with potential claimants for less than the amounts recorded for
royalties payable. 

         The Company estimates its capital expenditures for
onshore properties to be approximately $1,000,000 for the year
ended June 30, 1999.  However, the Company is not obligated to
participate in future drilling programs and will not enter into
future commitments to do so unless management believes the
Company has the ability to fund such projects.

         The Company's working interest share of the future
estimated development costs relating to its offshore California
proved undeveloped properties approximates $217 million.  No
significant amounts are expected to be incurred during fiscal
1999 and $1.0 and $4.2 million are expected to be incurred during
fiscal 2000 and 2001, respectively.  The amounts required for
development of these proved undeveloped reserves are so
substantial relative to the Company's present financial
resources, the Company may ultimately determine to farmout all or
a portion of its interest.  If it were to farmout its interests,
the Company's share of proved reserves would be decreased
substantially.  Alternatively, the Company may pursue other
methods of financing, including selling equity or debt
securities.  There can be no assurance that the
Company can obtain any such financing.  If the Company were to
sell additional equity securities to finance the development of
the properties, the existing common shareholders' interest would
be diluted significantly. 

         On May 23, 1997 Delta, UFG and SOCO entered into a
settlement agreement under which SOCO released its lien on the
Amber shares.  In connection with the agreement, Delta reissued
92,117 shares of common stock to UFG.  These shares had
originally been returned to Delta and cancelled pursuant to an
agreement dated February 22, 1995.  The fair value of the 92,117
shares of common stock reissued to UFG of $322,410 was recorded
as an increase in stockholders' equity for the value of shares
issued.  

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

         In a series of transactions during the year ended June
30, 1997, 160 shares Series C Convertible Preferred stock were
converted into 396,601 shares of the Company's common stock.

         The Company received the proceeds from the exercise of
options to purchase shares of its common stock of $203,536 and
$760,844 during the years ended June 30, 1998 and 1997,
respectively. 

          On August 20, 1998, the Company entered into a loan
agreement with Labyrinth Enterprises, L.L.C.,  an unrelated
entity, for $400,000.  The loan bears interest at the annual
rate of 10%, is due November 20, 1998 and is collateralized by
all producing oil and gas properties owned by the Company.  In
addition to the principal and interest payment required, the
Company will also pay this entity $50,000 cash or assign to it
interests in various wells currently owned by Delta that have a
present value of $50,000.  The Company's officers have personally
guaranteed this loan.

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

         After evaluation of the considerations described above,
the Company believes that its existing cash balances, cash flow
from its existing producing properties, proceeds from the sale of
producing properties, and other sources of funds will be adequate
to fund its operating expenses, pay off the $400,000 loan made
subsequent to year end, and satisfy its 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, 1998 was $962,003 compared to the net loss of
$2,457,007 for the year ended June 30, 1997.  The losses for the
years ended June 30, 1998 and 1997 included $350,000, of minimum
royalty payments to a related party as part of the acquisition of
three proved undeveloped offshore California federal oil and gas
units.  The losses for the years ended June 30, 1998 and 1997
also included $128,993 and $364,019, respectively, for abandoned
and impaired properties.  

         Revenue.  Total revenue for the year ended June 30, 1998
was $2,211,955 compared to $1,812,456 for the year ended June 30,
1997.  Oil and gas sales for the year ended June 30, 1998 were
$1,225,115 compared to  $1,554,134 for the year ended June 30,
1997. The decrease in oil and gas sales during the year ended
June 30, 1998 resulted from the sale of certain properties and
the decrease in oil and gas prices during fiscal 1998.

         Production volumes and average prices received for the
years ended June 30, 1998 and 1997 are as follows:
                                                                  
                             1998                     1997   
Production:        
    Oil (barrels)           11,632                    7,755  
    Gas (Mcf)              457,758                  644,256  

Average Price:        
    Oil (per barrel)       $ 16.46                   $22.36  
    Gas (per Mcf)           $ 2.26                   $ 2.14  
                   
         Lease Operating Expenses.  Lease operating expenses for
the year ended June 30, 1998 were $349,551 compared to $587,251
for the year ended June 30, 1997.  On an Mcf equivalent basis,
production expenses and taxes were $.67 per Mcf equivalent during
the year ended June 30, 1998 compared to $.85 per Mcf equivalent
for the year ended June 30, 1997.  The decrease in lease
operating costs on an equivalent basis compared to 1997 resulted
primarily from the relatively lower operating costs on its newly
drilled Sacramento Basin wells.

         Depreciation and Depletion Expense.  Depreciation and
depletion expense for the year ended June 30, 1998 was $303,563
compared to $320,292 for the year ended June 30, 1997.  On a Mcf
equivalent basis, the depletion rate was $.58 per Mcf equivalent
during the year ended June 30, 1998 compared to $.46 per Mcf
equivalent for the year ended June 30, 1997.  The decrease in
depreciation and depletion expense is a result of the sale of
certain oil and gas properties during fiscal 1998 which had a
higher than average depletion rate per Mcf.

         Exploration Expenses.  Exploration expenses consist of
geological and geophysical costs and lease rentals.  Exploration
expenses were $515,383 for the year ended June 30, 1998 compared
to $607,431 for the year ended June 30, 1997.  The exploration
expenses during fiscal 1998 and 1997 primarily represent costs
associated with the Company s participation in the shooting of
3-D seismic on prospects in the Sacramento Basin of Northern
California.

         Abandonment and Impairment of Oil and Gas Properties. 
The Company recorded an expense for the abandonment and
impairment of oil and gas properties for the year ended June 30,
1998 of $128,993 compared to $364,019 in 1997.  The Company's
proved properties were assessed for impairment on an individual
field basis and the Company recorded impairment provisions
attributable to certain producing properties of $128,993 and
$77,168 for the years ended June 30, 1998 and 1997, respectively. 
The expense in 1997 also includes a provision for impairment of
the costs associated with the North Park Basin in Colorado of
$286,851 as the Company made a geological determination based on
new information that it may not be economical to explore these
properties.  

         General and Administrative Expenses.  General and
administrative expenses for the year ended June 30, 1998 were
$1,433,461 compared to $1,808,701 for the year ended June 30,
1997.  General and administrative expenses decreased from 1997 to
1998 primarily as a result of a decrease in investor and
shareholder relation costs.

         Stock Option Expense.  Stock option expense has been
recorded for the years ended June 30, 1998 and 1997 of $46,402
and $40,469, respectively, for options granted to certain
officers, directors, employees and consultants at option prices
below the market price at the date of grant.

         Minimum Royalty to Related Party.   The minimum royalty
to related party represents the minimum royalty paid in 1998 and
in 1997 pursuant to the terms of the agreement with Ogle to
acquire interests in three proved undeveloped offshore Santa
Barbara, California federal oil and gas units.  The purchase
price of $8,000,000 is represented by a minimum royalty payment
reserved in the documents of Assignment and Conveyance and is
payable out of three percent (3%) of the oil and gas production
from the working interests with a requirement for a minimum
annual payment.  Delta paid Ogle $350,000 in 1998 and 1997 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.  As of June 30, 1998, the Company has paid a total of
$1,200,000 in minimum royalty payments.
                  
         Year 2000

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

    Recent Accounting Standards and Pronouncements

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

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

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

ITEM 7.  FINANCIAL STATEMENTS 

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


ITEM 8.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
         ACCOUNTING AND FINANCIAL DISCLOSURE
              
         Not applicable.

                                 PART III

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

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K

         (a)  Exhibits.

              The Exhibits listed in the Index to Exhibits
appearing at Page 35 filed as part of this report.

         (b)  Reports on Form 8-K.

              Form 8-K dated April 9, 1998; Items 5, 7, and 9. 
     

                                SIGNATURES


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

(Registrant)                    DELTA PETROLEUM CORPORATION


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


By (Signature and Title)        s/Kevin K. Nanke                  
                                Kevin K. Nanke, Controller and
                                Principal Accounting Officer

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


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

Date                                      02/10/99             


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

Date                                       02/10/99            


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

Date                                        02/10/99           
    

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

Date                                        02/10/99           


                             INDEX TO EXHIBITS

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

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

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

(9)  Voting Trust Agreement.  Not applicable.

(10) Material Contracts.  

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

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

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

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

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

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

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

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

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

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

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

10.12    Copies of Aleron H. Larson, Jr. and Roger A. Parker
Employment Agreements, filed previously on Form 10-KSB for the
fiscal year ended June 30, 1998.
                 
10.13    Letter agreement (without exhibits) with Slawson
Exploration Company, Inc. dated September 30, 1996 for an
interest in the West Orion prospect.  Incorporated by reference
from Exhibit 99.3 to the Company's Form 8-K dated October 10,
1996.

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

10.15    Financial consulting agreement with BC Capital Corp. 
Incorporated by reference from Exhibit 99.1 to the Company's
Form 8-K dated January 7, 1997.

10.16    Purchase and sale agreement between Snyder Oil
Corporation and Delta Petroleum Corporation.  Incorporated by
reference from Exhibit 99.2 to the Company's Form 8-K dated
January 7, 1997.

10.17    Employment agreement with David Castaneda.  Incorporated
by reference from Exhibit 99.3 to the Company's Form 8-K dated
January 7, 1997.

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

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

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

10.21    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.

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

10.23    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.

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

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

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

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

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

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

(19)     Previously Unfiled Documents.  Not applicable.

(21)     Subsidiaries of the Registrant. Not applicable.

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

(23)     Consent of Experts and Counsel. 

         23.1 Consent of KPMG LLP, filed herewith
              electronically.

(24)     Power of Attorney.  Not applicable.

(27)     Financial Data Schedule.  Filed previously on Form 10-KSB
for the fiscal year ended June 30, 1998.

(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, 1998 and 1997 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, 1998 and 1997 and the results of their operations and their
cash flows for the years then ended, in conformity with generally
accepted accounting principles. 

                                               s/KPMG Peat Marwick LLP
                                                 KPMG Peat Marwick LLP 





Denver, Colorado 
September 18, 1998 

    
    DELTA PETROLEUM CORPORATION
    AND SUBSIDIARY
    CONSOLIDATED BALANCE SHEETS
    June 30, 1998 and 1997                                       
    
    
  
                                                1998               1997
                                                                 
    ASSETS
    
Current Assets:
  Cash                                              $17,135      393,048
  Trade accounts receivable,  net of            
    allowance for doubtful accounts
    of  $50,000 in 1998 and 1997                    224,285      333,535
  Accounts receivable - related parties             127,415      119,419
  Other current assets                               10,100       10,100
    
    Total current assets                            378,935      856,102
                                                                 
    
Property and Equipment:
  Oil and gas properties, at cost (using
        the successful efforts method
        of accounting) (Note 9):
    Undeveloped offshore California
             properties                           6,959,830   6,959,830
    Undeveloped onshore domestic properties         726,127     714,605
    Developed onshore domestic properties         3,369,881   3,383,523
  Office furniture and equipment                     80,446      80,446
                                                 11,136,284  11,138,404
    
  Less accumulated depreciation and depletion    (2,234,525) (2,059,461)
    
    Net property and equipment                    8,901,759   9,078,943
    
Investment in Bion Environmental 
  Technologies, Inc. (Bion) (Note 2)              1,069,149     503,328
    
    
                                                $10,349,843  10,438,373

    
                                                    1998         1997
                                                                 
LIABILITIES AND STOCKHOLDERS' EQUITY          
    
    
Current  Liabilities:
  Accounts payable trade                           $570,469     776,702
  Other accrued liabilities                          10,000      21,835
  Royalties payable                                 264,320     468,968
    
    Total current liabilities                       844,789   1,267,505
    
    
Stockholders' Equity (Note 4):
  Preferred stock, $.10 par value; 
    authorized 3,000,000 shares, none issued         -           -
  Common stock, $.01 par value; 
    authorized 300,000,000 shares,
    issued 5,513,858
    shares in 1998 and 5,230,631 shares in 1997      55,139        52,306
  Additional paid-in capital                     25,571,921    24,950,128
  Cumulative unrealized gain (loss) (Note 2)        457,594      (213,969)
  Accumulated deficit                           (16,579,600)  (15,617,597)
    
    Total stockholders' equity                    9,505,054     9,170,868
    
Commitments (Note 8)                            
                                                $10,349,843    10,438,373
                                                    
    
    DELTA PETROLEUM CORPORATION
    AND SUBSIDIARY
    CONSOLIDATED STATEMENTS OF OPERATIONS
    Years Ended June 30, 1998 and 1997                            
   
    
    
    
  
                                                   1998            1997
    
Revenue:
  Oil and gas sales                               $1,225,115    1,554,134
  Gain on sale of oil and gas properties             650,417        2,524
  Gain on sale of securities available for sale       48,340          -
  Other revenue                                      288,083      255,798
    
        Total revenue                              2,211,955    1,812,456
    
    
Expenses:
  Lease operating expenses                           349,551      587,251
  Depreciation and depletion                         303,563      320,292
  Exploration expenses                               515,383      607,431
  Abandoned and impaired properties                  128,993      364,019
  Dry hole costs                                      46,605      191,300
  Minimum royalty to related party (Note 7)          350,000      350,000
  General and administrative                       1,433,461    1,808,701
  Stock option expense                                46,402       40,469
    
        Total expenses                             3,173,958    4,269,463
    
        Net loss                                   ($962,003)  (2,457,007)
    
    
    Basic loss per common share                       ($0.18)      (0.49)
    
    Weighted average number of common
           shares outstanding                      5,361,900   5,029,009
    
     
    DELTA PETROLEUM CORPORATION
    AND SUBSIDIARY
    Consolidated Statement of Stockholders' Equity
    Year ended June 30, 1998 and 1997


    
    
                                                                                                                    
Additional
                                                  Preferred Stock               Common Stock              
            paid-in
                                                     Shares         Amount         Shares           
Amount            capital
    
                                                                                        
                
Balance, July 1, 1996                                     160            $16        4,488,283           
44,882        21,299,784
    
Unrealized gain on equity securities                   -              -               -                 -    
            -
Stock options granted as compensation                  -              -               -                 - 
                40,469
Preferred stock converted into common stock              (160)           (16)         396,601     
       3,966            (3,950)
Shares issued for cash upon exercise of options        -              -               186,700         
   1,867           758,977
Shares issued for undeveloped oil and gas properti     -              -                63,000         
     630           172,620
Shares issued for developed oil and gas properties     -              -                   500          
      5             1,604
Shares issued for services                             -              -                 7,500               
75            29,925
Amortization of consulting expense                     -              -               -                 -  
              -
Shares reacquired and retired                          -              -                (4,070)             
(40)          (18,022)
UFG settlement                                         -              -                92,117              
921         2,668,721
Net loss                                               -              -               -                 -          
      -
    
Balance, June 30, 1997                                 -              -             5,230,631           
52,306        24,950,128
    
Unrealized gain on equity securities                   -              -               -                 -    
            -
Stock options granted as compensation                  -              -               -                 - 
                46,402
Shares issued for cash upon exercise of options        -              -               114,100         
   1,141           202,395
Shares issued for cash                                 -              -               156,950            
1,570           348,430
Shares issued for services                             -              -                22,500              
225            64,463
Shares reacquired and retired                          -              -               (10,323)            
(103)          (39,897)
Net loss                                               -              -               -                 -          
      -
    
Balance, June 30, 1998                                 -             $              5,513,858           
55,139        25,571,921



    
                                                                  Cumulative
                                                  Unamortized     unrealized
                                                   consulting       gain         Accumulated
                                                    expense         (loss)         deficit            Total
    
                                                                                        

Balance, July 1, 1996                                (105,000)      (255,184)     (13,160,590)       
7,823,908
    
Unrealized gain on equity securities                   -              41,215          -                 
41,215
Stock options granted as compensation                  -              -               -                 
40,469
Preferred stock converted into common stock            -              -               -                
- -
Shares issued for cash upon exercise of options        -              -               -                
760,844
Shares issued for undeveloped oil and gas properti     -              -               -                
173,250
Shares issued for developed oil and gas properties     -              -               -                  
1,609
Shares issued for services                             -              -               -                 
30,000
Amortization of consulting expense                    105,000         -               -                
105,000
Shares reacquired and retired                          -              -               -                
(18,062)
UFG settlement                                         -              -               -              
2,669,642
Net loss                                               -              -            (2,457,007)      
(2,457,007)

Balance, June 30, 1997                                 -            (213,969)     (15,617,597)       
9,170,868
    
Unrealized gain on equity securities                   -             671,563          -                
671,563
Stock options granted as compensation                  -              -               -                 
46,402
Shares issued for cash upon exercise of options        -              -               -                
203,536
Shares issued for cash                                 -              -               -                
350,000
Shares issued for services                             -              -               -                 
64,688
Shares reacquired and retired                          -              -               -                
(40,000)
Net loss                                               -              -              (962,003)        
(962,003)
    
Balance, June 30, 1998                                 -             457,594      (16,579,600)       
9,505,054

 
    
     
    DELTA PETROLEUM CORPORATION
    AND SUBSIDIARY
    CONSOLIDATED STATEMENTS OF CASH FLOWS
    Years Ended June 30, 1998 and 1997                                
    
    
    
                                                      1998             1997
                                                        
Cash flows operating activities:                                  
 Net loss                                        ($962,003)      (2,457,007)
 Adjustments to reconcile net loss
    to cash used in
    operating activities:
   Gain on sale of oil and gas properties         (650,417)          (2,524)
   Write-off royalties payable                    (204,648)        (180,867)
   Gain on sale of securities available
    for sale                                       (48,340)         -
   Depreciation and depletion                      303,563          320,292
   Abandoned and impaired properties               128,993          364,019
   Common stock issued for services                 64,688           30,000
   Stock option expense                             46,402           40,469
   Bad debt expense                                 29,754           60,604
   Amortization of consulting expense              -                105,000
 Net changes in current assets and                 
        and current liabilities:
   Decrease (increase) in trade accounts
        receivable                                  36,566           (8,183)
   Decrease in other current assets                -                  2,000
   (Decrease) increase in accounts payable trade  (206,233)         472,652
   Decrease in other accrued liabilities           (11,835)         (46,462)
    
Net cash used in operating activities           (1,473,510)      (1,300,007)
         
Cash flows from investing activities:
   Additions to property and equipment            (628,387)      (1,068,167)
   Proceeds from sale of securities
         available for                             197,012          -
   Proceeds from sale of oil and gas
         properties                              1,023,432          450,720
Net cash provided by (used in) investing
         activities                                592,057         (617,447)
         
Cash flows from financing activities:
   Stock issued for cash upon exercise
         of options                                163,536          742,782
   Issuance of common stock for cash               350,000          -
   Increase in accounts receivable from
         related parties                            (7,996)         (62,018)
Net cash provided by financing activities          505,540          680,764
         
Net decrease in cash                              (375,913)      (1,236,690)
    
Cash at beginning of year                          393,048        1,629,738
    
Cash at end of year                                 17,135          393,048
    
Supplemental cash flow information - 
    
Non-cash financing activities:
Common stock issued for properties               $    -             174,859
   
   

DELTA PETROLEUM CORPORATION
AND SUBSIDIARY

Notes to Consolidated Financial Statements
June 30, 1998 and 1997 
                                                                  

(1) Summary of Significant Accounting Policies

    Organization and Principles of Consolidation

    Delta Petroleum Corporation ("Delta") was organized December
21, 1984 and is principally engaged in acquiring, exploring,
developing and producing oil and gas properties.  The Company
owns interests in undeveloped oil and gas properties in federal
units offshore California, near Santa Barbara, and developed and
undeveloped oil and gas properties in the continental United
States.
    
    At June 30, 1998, 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. 
    
    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 original maturities of three months or
less to be cash equivalents.
      
    Property and Equipment

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

     Upon the sale or retirement of oil and gas properties, the
cost thereof and the accumulated depreciation and depletion are
removed from the accounts and any gain or loss is credited or
charged to operations.
 
     Depreciation and depletion of capitalized acquisition,
exploration and development costs is computed on the
units-of-production method by individual fields as the related
proved reserves are produced.  Capitalized costs of unproved
properties are assessed periodically and a provision for
impairment is recorded, if necessary, through a charge to
operations.

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

     Impairment of Long-Lived Assets

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

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

     The Company's proved properties were assessed for impairment
on an individual field basis and the Company recorded impairment
provisions attributable to certain producing properties of
$128,993 and $77,168 for the years ended June 30, 1998 and 1997,
respectively.

     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, 1998, the Company had produced and recognized
as revenue approximately 20,000 Mcf more than its entitled share
of production.  The undiscounted value of this imbalance is
approximately $40,000 using the lower of the price received for
the natural gas, the current market price or the contract price,
as applicable.   
     
     Royalties Payable 

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

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

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

     Income Taxes

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

     Earnings (Loss) per Share

     In February 1997, the Financial Accounting Standards Board
issued Statement of Financial Accounting Standards No. 128,
Earnings per Share (Statement No. 128) effective for periods
ending after December 15, 1997.  Statement No. 128 changes the
computation, presentation and disclosure requirements for
earnings per share for entities with publicly held common stock
or potential common stock.  Under such requirements the Company
is required to present both basic earnings per share and diluted
earnings per share.  Basic earnings (loss) per share is computed
by dividing net earnings (loss) attributes to common stock by the
weighted average number of common shares outstanding during each
period, excluding treasury shares.
     
     Diluted earnings (loss) per share is computed by adjusting
the average number of common share outstanding for the dilative
effect, if any, of convertible preferred stock, stock options and
warrant.  The effect of potentially dilative securities is based
on earnings (loss) before extraordinary items.

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

     Use of Estimates

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

     Certain amounts in the 1997 financial statements have been
reclassified to conform to the 1998 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 a separate
component of stockholders' equity.  During fiscal 1998, the
Company received an additional 40,747 shares of Bion's common
stock for rent and other services provided by the Company. 
During fiscal 1998, the Company realized a gain on the sale of
securities available for $48,340.  The 161,381 shares of Bion's
common stock owned by the Company represents less than 2% of the
outstanding shares of Bion at June 30, 1998.  

     The cost and estimated market value of the Company's
investment in Bion at June 30, 1998 and 1997 are as follows:

                                                     Estimated
                               Unrealized              Market 
                    Cost       Gain/(Loss)             Value  

      1998        $611,555       457,594             1,069,149
      
      1997        $717,297      (213,969)              503,328
                                           
    As of September 14, 1998, the estimated market value of the
Company's investment in Bion, based on the quoted bid price of
Bion's common stock, was approximately $685,000.             

(3) Note Payable by UFG

    Prior to fiscal 1997, Delta had recorded a note payable ("Note")
to Snyder Oil Corporation ( SOCO ) by Underwriters
Financial Group, Inc., ( UFG ), the Company's former parent.  The
Company recorded a liability for the note upon the transfer by
UFG (subject to the Note) of the common stock of Amber to the
Company in 1992.   Although the Note was an obligation of UFG,
the Company recorded a liability for the Note since
a portion of the common shares of Amber owned by the Company were
pledged to secure the Note and because of the uncertainties
regarding UFG's ability to fulfill its obligations under the
Note.

    On May 23, 1997 Delta, UFG and SOCO entered into a settlement
agreement under which SOCO released its lien on the Amber shares. 
In connection with the agreement, Delta reissued 92,117 shares of
common stock to UFG.  These shares had originally been returned
to Delta and cancelled pursuant to an agreement dated February
22, 1995.  This agreement was rescinded in connection with the
settlement agreement.  

    As a result of the settlement agreement, the liability for
the Note was eliminated with a corresponding increase in Delta's
stockholders' equity.  The fair value of the common shares issued
to UFG of $322,410 was recorded as an increase in stockholders'
equity, for the value of shares issued, and as a reduction of the
adjustment recorded to stockholder's equity for the elimination
of the liability for the Note.  

(4)  Stockholders  Equity

     Preferred Stock

     The Company has 3,000,000 shares of preferred stock
authorized, par value $.10 per share, issuable from time to time
in one or more series.

     In a series of transactions, during the year ended June 30,
1997, 160 share of Series C Convertible Preferred stock were
converted into 396,601 shares of the Company's common stock.

     Common Stock

     On December 23, 1997, the Company completed a sale of
156,950 shares of the Company's Common stock to another oil
company for net proceeds to the Company of $350,000.
   
     During the year ended June 30, 1998, the Company issued
22,500 shares of the Company's common stock to a former employee
as a part of a severance package.  This transaction was recorded
at its estimated fair market value of the common stock issued,
which was based on the quoted market price of the stock at the
time of issuance. The Company also agreed to forgive
approximately $20,000 in debt owed to the Company by
the former employee.

   The Company received proceeds from the exercise of options to
purchase shares of its common stock of $203,536 during the year
ended June 30, 1998 and $760,844 during the year ended June 30,
1997.      

   During the years ended June 30, 1998 and 1997, the Company
issued shares of its 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.

   Non-Qualified Stock Options
   
   The Company's 1993 Incentive Plan (the "Incentive Plan") was
adopted by the Board of Directors on May 24, 1993 and ratified
and adopted by the shareholders on October 5, 1993.  The
Incentive Plan was amended effective November 1, 1996.  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, 1998 and 1997 are as
follows:
       
                            1998                        1997        
               
                               Weighted-Average            Weighted-Average
                                   Exercise                    Exercise
                      Options       Price        Options      Price
       
Outstanding
- -beginning 
 of year            1,262,077      $3.25        902,350       $3.85
   
Granted                15,000       1.88        546,000        5.39 
Exercised            (114,100)      1.78       (186,700)       4.06 
Returned                  -          -          (21,573)       3.75 
 
Repriced            1,621,054       2.47        918,027        3.64
Returned
for repricing      (1,621,054)      3.27       (918,027)       5.58 
                                                           
Outstanding-end
 of year            1,162,977      $2.25      1,262,077       $3.25 
                                                             
Exercisable at
 end of year        1,132,977      $2.27      1,185,077       $3.20 
       

   Exercise prices for options outstanding under the plan as of
June 30, 1998 ranged from $1.25 to $9.75 per share.  The
weighted-average remaining contractual life of those options is
7.6 years.  A summary of the outstanding and exercisable options
at June 30, 1998, 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   
                              
$1.25 - $3.25      1,022,977    $1.64        7.7        992,977      $1.64
$3.25 - $9.75        140,000     6.74        7.5        140,000       6.74
                   1,162,977    $2.25        7.6      1,132,977      $2.27  

     
    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, 1998
and 1997, respectively, risk-free interest rate of 6.0% and 6.5%,
dividend yields of 0% and 0%, volatility factors of the expected
market price of the Company's common stock of 44.35% and 43.72%,
and a weighted-average expected life of the options of 6.0 and
6.87 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,
1998 and 1997, would have been $1,333,745 and $4,191,673, and
basic loss per common share would have been $.25 and $.83 per
share, respectively.

    During the year ended, June 30, 1998, the Company s president
exercised options to purchase 32,000 shares of the Company's
common stock.  Payment for the shares of common stock purchased
upon exercise of the option was made in shares of the Company's
common stock previously owned by the Company s president, valued
at the market price on the date of exercise.  The Company
recorded the 10,323 shares of the Company's common stock
reacquired at cost, which shares were subsequently retired.
    
    During the year ended June 30, 1997, the Company's president
exercised options to purchase 14,450 shares of the Company's
common stock.  Payment for the shares of common stock purchased
upon exercise of the option was made in shares of the Company's
common stock previously owned by the Company's president, valued
at the market price of the stock on the date of exercise.  The
Company recorded the 4,070 shares of the Company's common stock
reacquired at cost, which shares were subsequently retired.

    Stock Options and Warrants
 
    In addition to options outstanding under the Company's
Incentive Plan, the following options and warrants were
outstanding at June 30, 1998:
                                  
     Number               Exercise            Expiration  
   Outstanding             Price                 Date     

      7,000              $ 1.250                   -   (1)
     20,000                3.500               6/09/03    
     50,000                6.000                   -   (2)
     50,000                6.000                   -   (3)
     62,500                6.125              11/06/00    
    100,000                8.000               8/31/99    
    100,000                8.500               8/03/98    
    500,000              2.50-6.00             3/31/99    

         (1)  The 7,000 options granted at $1.25 expire thirty
days 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 one year after      
registration of the underlying shares.
         
         (3)  The 50,000 options granted at $6.00 expire on the
later of the original expiration date or thirty days after
registration of the underlying shares.

(5)      Employee Benefits

   During 1997 the Company began sponsoring 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, 1998 and 1997, the Company
contributed $22,304 and $4,491 under the Plan.

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

                                            1998         1997   
      Deferred tax assets:                                      
         Net operating loss
           carryforwards               $7,999,000     7,168,000 
         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   2,206,000     1,685,000 
         Gross deferred tax assets     10,224,000     8,872,000 

         Less valuation allowance     (10,224,000)   (8,872,000)
         
      Net deferred tax asset       $        -              -      


         No income tax benefit has been recorded for the years
ended June 30, 1998 and 1997 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, 1998, the Company had net operating loss
carryforwards for regular and alternative minimum tax purposes of
approximately $21,000,000 and $20,305,000, respectively.  If not
utilized, the tax net operating loss carryforwards will expire
during the period from 1998 through 2013.  Net operating loss
carryforwards attributable to Amber prior to 1993 of
approximately $3,360,000, included in the above amounts are
available only to offset future taxable income of Amber and are
further limited to approximately $475,000 per year, determined on
a cumulative basis.

(7)      Related Party Transactions

         Transactions with Officer

         On January 7, 1997, the Company's President returned
21,573 options to purchase shares of common stock at $3.75 to the
Company.  At that time the market price of the Company's common
stock was $6.50 per share.   On the same date, the Company wrote
off a receivable in the amount of $59,326 from Apex Operating
Company, Inc., a company affiliated with the Company's President
by reason of his position as its president and his ownership of
100% of its common stock.  The return of the 21,573 options was
voluntary and was done as an attempt to restore an approximately
equivalent value to the Company.

         Accounts Receivable Related Parties

         At June 30, 1998, the Company had $127,415 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

         The Company has an agreement to grant, on an annual
basis, to each non-employee director options to purchase, 7,500
shares of the Company's common stock for services performed
during the previous 12 months.  The options are granted at an
exercise price equal to 50% of the average market prices for the
year in which the services are performed.

         Transactions with Other Stockholders

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

         Effective February 24, 1994, Ogle granted the Company an
option to acquire working interests in three proved undeveloped
offshore Santa Barbara, California, federal oil and gas units. 
In August 1994, the Company issued a warrant to Ogle to purchase
100,000 shares of the Company's common stock for five years at a
price of $8 per share in consideration of the agreement by Ogle
to extend the expiration date of the option to January 3, 1995. 
On January 3, 1995, the Company exercised the option from Ogle to
acquire the working interests in three proved undeveloped
offshore Santa Barbara, California, federal oil and gas units. 
The purchase price of $8,000,000 is represented by a production
payment reserved in the documents of Assignment and Conveyance
and will be paid out of three percent (3%) of the oil and gas
production from the working interests with a requirement for
minimum annual payments.  Delta paid Ogle $350,000 in 1998
and 1997 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.  As of June 30, 1998, the Company has paid a
total of $1,200,000 in minimum royalty payments.  Under the terms
of the agreement, the Company may reassign the working interests
to Ogle upon notice of not more than 14 months nor less than 12
months, thereby releasing the Company of any further obligations
to Ogle after the reassignment.

         Until such time as the property has been developed and
placed into production, the Company is recording the minimum
annual payments under the agreement as an expense,
similar to the accounting treatment afforded a delay rental.  If
and when the property is placed on production, the Company
intends to account for the royalty interest retained by
the seller in a manner similar to the treatment afforded a
royalty interest retained by a landowner.  

(8)      Commitments
         
         The Company rents an office in Denver under an operating
lease which expires in April 2002.  Rent expense, net of sublease
rental income, for the years ended June 30, 1998 and 1997 was
approximately $42,000 and $44,000, respectively.  Future minimum
payments under noncancelable operating leases are as follows:
         
         
            1999                        $  120,666   
            2000                           107,958   
            2001                           103,638   
            2002                            82,336   

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

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

                                       June 30,        June 30, 
                                         1998            1997   
         Undeveloped offshore
           California properties     $6,959,830       6,959,830 
         Undeveloped onshore
           domestic properties          726,127         714,605 
         Developed onshore domestic
           properties                 3,369,881       3,383,523 
                                     11,055,838      11,057,958 
         Accumulated depreciation
           and depletion             (1,311,719)     (1,990,954)

                                     $9,744,119       9,067,004 

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

                                          1998           1997  
         Unproved property
          acquisition costs             $156,681         505,457
         Proved property 
          acquisition costs               40,876         182,559
         Development costs               430,830         567,492
         Exploration costs               515,383         607,431
                                      $1,143,770       1,862,939


         Statement of Financial Accounting Standards 131
"Disclosures about segments of an enterprises and Related
Information" (SFAS 131), was issued by the Financial Accounting
Standards Board in June, 1997.  SFAS 131 establishes standards
for reporting information about operating segments in annual and
interim financial statements.  SFAS 131 also establishes
standards for related disclosures about products and services,
geographic areas and major customers.  This statement is
effective for fiscal years beginning after December 15, 1997.

         The Company'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, 1998 and 1997 were:
                                                              
                               1998                     1997      
              
            A                   42%                      42%      
            B                    9%                      14%      
            C                    -%                      13%      
              
                
(10)     Information Regarding Proved Oil and Gas Reserves
(Unaudited)

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

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

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

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

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

         Offshore Properties.  The Company s Offshore California
proved undeveloped reserves are attributable to its interests in
four federal units (plus one additional lease) located   
offshore California near Santa Barbara.  While these interests
represent ownership of substantial oil and gas reserves
classified as proved undeveloped, the cost to develop the       
reserves will be very substantial.  The Company may be required
to farm out all or a portion of its interests in these properties
if it cannot fund its share of the development costs.  There can
be no assurance that the Company can farm out its interests on    
acceptable terms.  If the Company were to farm out its interests
in these properties, its share of the proved reserves
attributable to the properties would be decreased     
substantially.  The Company may also incur substantial dilution
of its interests in the properties if it elects to use other
methods of financing the development costs.
         
         These units have been formally approved and are
regulated by the Minerals Management Service of the Federal
Government.  However, due to a history of opposition to offshore
drilling and production in California by some individuals and
groups, the process of obtaining all of the necessary permits and
authorizations to develop the properties will be lengthy.  While
the Federal Government has recently attempted to expedite this
process, there can be no assurance that it will be successful in
doing so.  The Company does not have a controlling interest in
and does not act as the operator of any of the offshore      
California properties and consequently will not control the
timing of either the development of the properties or the
expenditures for development.  Management and its      
independent engineering consultant have considered these factors
relating to timing of the development of the reserves in the
preparation of the reserve information relating to these       
properties.  As  additional information becomes available in the
future, the Company's estimates of the proved undeveloped
reserves attributable to these properties could change, and such
changes could be substantial.

         The standardized measure of discounted future net cash
flows relating to proved oil and gas reserves and the changes in
standardized measure of discounted future net cash flows      
relating to proved oil and gas reserves were prepared in
accordance with the provisions of Statement of Financial
Accounting Standards No. 69.  Future cash inflows were       
computed by applying current prices at year-end to estimated
future production.  Future production and development costs are
computed by estimating the expenditures to be incurred in
developing and producing the proved oil and gas reserves at
year-end, based on year-end costs and assuming continuation of
existing economic conditions.  Future income tax expenses are
calculated by applying appropriate year-end tax rates to future
pre-tax net cash flows relating to proved oil and gas reserves,
less the tax basis of properties involved and tax credits and
loss carryforwards relating to oil and gas producing activities. 
Future net cash flows are discounted at a rate of 10% annually to
derive the standardized measure of discounted future net cash
flows.  This calculation procedure does not necessarily result in
an estimate of the fair market value or the present value of the
Company's oil and gas properties.
    



    
    DELTA PETROLEUM CORPORATION
    AND SUBSIDIARY
    Notes to Consolidated Financial Statements
                                                                
    
(10) Information Regarding Proved Oil and Gas Reserves (Unaudited) - Continued

    

    
A summary of changes in estimated quantities of proved reserves, net of
recoupment gas, for the years ended June 30, 1998 and 1997 are as follows:
    
    
                                                 Onshore                          Offshore
                                                   GAS              OIL              GAS               OIL
                                                  (MCF)           (BBLS)            (MCF)           
(BBLS)
    
                                                                                    

Balance at July 1, 1996                       5,270,945         144,192        62,440,251       
57,988,720
    
     Purchases of reserves in place             659,515          -              3,140,745        
2,616,072
     Redetermination of working interest        -                -              9,288,371        
8,359,569
     Extension and discoveries                  141,127           1,473           -                 -
     Revisions of quantity estimates          1,338,004          50,982         2,809,079        
3,363,139
     Sales of properties                     (1,348,132)        (26,080)          -                 -
     Production                                (644,256)         (7,755)          -                 -
    
Balance at June 30, 1997                      5,417,203         162,812        77,678,446       
72,327,500
    
     Purchases of reserves in place             -                -                -                 -
     Extension and discoveries                3,995,565          -                -                 -
     Revisions of quantity estimates          1,285,573          (2,364)       (3,054,652)      
(3,126,362)
     Sales of properties                       (807,472)         (1,375)          -                 -
     Production                                (457,758)        (11,632)          -                 -
    
Balance at June 30, 1998                      9,433,111         147,441        74,623,794       
69,201,138
    
Proved developed reserves:
   June 30, 1996                              3,146,357          47,021           -                 -
   June 30, 1997                              3,419,077          34,176           -                 -
   June 30, 1998                              3,905,228          22,273           -                 -

    
       
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
      
Notes to Consolidated Financial Statements, Continued
      
      
(10) Information Regarding Proved Oil and Gas Reserves (Unaudited) -Continued
      
Future net cash flows presented below are computed using year-end prices
and costs. Future corporate overhead expenses and interest expense have not
been included.
      
      
      
                                                   Offshore
                                   Onshore        California        Total
      
      
   June 30, 1997
      
   Future cash inflows           $13,409,182     999,632,181   1,013,041,363
   Future costs:
      Production                   4,699,867     308,000,540     312,700,407
      Development                  1,824,318     217,307,046     219,131,364
      Income taxes                   -           173,914,122     173,914,122
      
   Future net cash flows           6,884,997     300,410,473     307,295,470
      
    10% discount factor            2,565,471     256,324,479     258,889,950
      
   Standardized measure of
      discounted future
      net cash flows              $4,319,526      44,085,994      48,405,520
      
      
   June 30, 1998
      
   Future cash inflows           $21,864,136     728,472,541     750,336,677
   Future costs:
      Production                   6,341,210     284,884,479     291,225,689
      Development                  3,058,005     215,528,324     218,586,329
      Income taxes                   -            77,582,676      77,582,676
      
   Future net cash flows          12,464,921     150,477,062     162,941,983
      
    10% discount factor            5,902,279     148,080,891     153,983,170
      
   Standardized measure of
       discounted future
       net cash flows             $6,562,642       2,396,171       8,958,813
      
      
The principal sources of changes in the standardized measure of discounted
net cash flows during the years ended June 30, 1998 and 1997 are as follows:
      
      
                                                      1998            1997
      
 Beginning of year                              $48,405,520      61,344,297
      
 Sales of oil and gas produced during the
   period, net of production costs                 (875,564)       (966,883)
  Net change in prices and production costs     (14,528,906)    (15,964,408)
  Changes in estimated future development costs     172,879      (1,304,543)
  Purchase of reserves in place                     -             2,762,518
  Redetermination of working interest               -             7,929,906
  Extensions, discoveries and improved recovery   2,661,463         122,389
  Revisions of previous quantity estimates,
   estimated timing of development and other     (8,677,965)     (8,530,750)
  Net change in income taxes                    (22,195,961)     (2,426,782)
  Sales of reserves in place                       (843,205)       (694,654)
  Accretion of discount                           4,840,552       6,134,430
      
  End of year                                    $8,958,813      48,405,520
    
    
(11)     Subsequent Event

         On August 20, 1998, the Company entered into a loan
agreement with an unrelated entity for $400,000.  The loan bears
interest at the annual rate of 10%, is due November 20,
1998 and is collateralized by all producing oil and gas
properties owned by the Company. In addition to the principal and
interest payment required, the Company will also pay this
entity $50,000 cash or assign to it interests in various wells
currently owned by Delta that have a present value of $50,000. 
The Company's officers have personally guaranteed this loan.

EX-23.1

                     Consent of Independent Auditors



The Board of Directors
Delta Petroleum Corporation:


We consent to the incorporation by reference in the registration
statement No. 33-87106 on Form S-8 of Delta Petroleum Corporation
of our report dated September 18, 1998 relating to the consolidated
balance sheets of Delta Petroleum Corporation and subsidiary as of
June 30, 1998 and 1997, and the related consolidated statements of
operations, stockholders  equity, and cash flows for the years then
ended which report appears in the June 30, 1998 Annual Report on
Form 10-KSB/A of Delta Petroleum Corporation.

                                              s/KPMG LLP
                                              KPMG LLP


Denver, Colorado
February 12, 1999