SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB
[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 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 30.
TABLE OF CONTENTS
PART I
PAGE
ITEM 1. DESCRIPTION OF BUSINESS 1
ITEM 2. DESCRIPTION OF PROPERTY 4
ITEM 3. LEGAL PROCEEDINGS 18
ITEM 4. SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS 19
ITEM 4A. DIRECTORS AND EXECUTIVE OFFICERS 19
PART II
ITEM 5. MARKET FOR COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS 21
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS
OR PLAN OF OPERATION 23
ITEM 7. FINANCIAL STATEMENTS 27
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 28
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE
EXCHANGE ACT 28
ITEM 10. EXECUTIVE COMPENSATION 28
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT 28
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS 28
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K 28
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) Effect of Existing or Probable Governmental
Regulations on the Business. The oil and gas industry is
extensively regulated by federal, state and local authorities.
Legislation affecting the oil and gas industry is under constant
review for amendment or expansion. Numerous departments and
agencies, both federal and state, have issued rules and
regulations binding on the oil and gas industry and its
individual members, some of which carry substantial penalties for
the failure to comply. The regulatory burden on the oil and gas
industry increases its cost of doing business and consequently
affects its profitability. Inasmuch as such laws and regulations
are frequently amended or reinterpreted, the Company is unable to
predict the future cost or impact of complying with such
regulations.
(10) Research and Development. 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 totalling
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. However, due to a history of opposition to
offshore drilling and production in California by some
individuals and groups, the process of obtaining all of the
necessary permits and authorizations to develop the properties
will be lengthy. While the Federal Government has recently
attempted to expedite this process, there can be no assurance
that it will be successful in doing so. The Company does not
have a controlling interest in and does not act as the operator
of any of the offshore California properties and consequently
will not control the timing of either the development of the
properties or the expenditures for development. Management and
its independent engineering consultant have considered these
factors relating to timing of the development of the reserves in
the preparation of the reserve information relating to these
properties. It is anticipated that, based upon discussion with
appropriate governmental agencies, development of the subject
leases will require from three to five year 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 decisionmakers 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 decisionmakers and the
industry as the proper course of action for
development would result in lower than anticipated
costs, but would cause the subject properties to
be developed over a significantly extended period
of time.
Scenario 3 Development of existing leases,
using existing onshore facilities by constructing
additional capacity at existing sites to handle
expanded production. Although the details of this
scenario are not yet available because the study
has not been completed, it would appear that this
is approximately the same scenario that is
anticipated by the Company's reserve report.
Scenario 4 Development of existing leases
after decommissioning and removal of some or all
existing onshore facilities. This scenario
includes new facilities, and perhaps new sites,
to handle anticipated potential future production.
There is currently insufficient information
available to assess the impact of this scenario on
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 decisionmakers 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 decisionmakers and the
industry as the proper course of action for
development would result in lower than anticipated
costs, but would cause the subject properties to
be developed over a significantly extended period
of time.
Scenario 3 Development of existing leases,
using existing onshore facilities by constructing
additional capacity at existing sites to handle
expanded production. Although the details of this
scenario are not yet available because the study
has not been completed, it would appear that this
is approximately the same scenario that is
anticipated by the Company's reserve report.
Scenario 4 Development of existing 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 eventual development. By January 15, 1999, each
operator will 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 totalled approximately
69,201,000 Bbls of oil and 74.6 Bcf of gas for an aggregate
equivalent of 81,638,000 BOE.
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 will
ultimately lead to the drilling of one additional delineation
well. This well will be used to determine the final location of
the development platform. Following the platform decision, a
Development Plan will be prepared for submittal to the MMS and
the other involved agencies. Two to three years will likely be
required to process the Development Plan and receive the
necessary approvals.
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 leading to the
drilling of an additional delineation well prior to preparing the
Development Plan.
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.
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 leading to the
drilling of an additional delineation well.
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. After spending two years in the litigation
department of a Denver law firm, he founded Eckelberger &
Associates of which he is still the principal member. From 1982
to 1992 Mr. Eckelberger was the senior partner of Eckelberger &
Feldman, a law firm with offices in Englewood, Colorado. Mr.
Eckelberger previously served as an officer, director and
corporate counsel for Roxborough Development Corporation. He is
presently the President and Chief Executive Officer of 1998,
Ltd., a Colorado corporation actively engaged in
the development of real estate in Colorado. He is the Managing
Member of The Francis Companies, L.L.C., a Colorado limited
liability company, which actively invests in real estate.
Additionally, Mr. Eckelberger is the General Partner of 2003
Limited, a Colorado limited partnership 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 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 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 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 30 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 9/23/98
By (Signature and Title) s/Roger A. Parker
Roger A. Parker, Director
Date 9/23/98
By (Signature and Title) s/Terry D. Enright
Terry D. Enright, Director
Date 9/23/98
By (Signature and Title) s/Jerrie F. Eckelberger
Jerrie F. Eckelberger, Director
Date 9/23/98
INDEX TO EXHIBITS
(2) 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 herewith electronically.
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 herewith electronically.
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 Peat Marwick LLP, filed herewith
electronically.
(24) Power of Attorney. Not applicable.
(27) Financial Data Schedule. Filed herewith electronically.
(99) Additional Exhibits. Not applicable.
Independent Auditors' Report
The Board of Directors and Stockholders
Delta Petroleum Corporation:
We have audited the accompanying consolidated balance sheets of
Delta Petroleum Corporation (the Company) and subsidiary as of
June 30, 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
<TABLE>
<CAPTION>
Additional
Preferred Stock Common Stock paid-in
Shares Amount Shares Amount capital
<S> <C> <C> <C> <C> <C>
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 properties - - 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 (Note 3) - - 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
</TABLE>
<TABLE>
Cumulative
Unamortized unrealized
consulting gain Accumulated
expense (loss) deficit Total
<S> <C> <C> <C> <C>
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 properties - - - 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 (Note 3) - - - 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
</TABLE>
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 cashflow 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 Weighted
Average 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
$3.26 - $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 theform 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% ofan 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.
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C>
Balance at July 1, 1997 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 - -
</TABLE>
Future net cash flows presented below are computed using year-end prices
and costs. Future corporate overhead expenses and interest expense have not
been included.
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.
EMPLOYMENT AGREEMENT
This agreement is entered into as of April 10, 1998, by and
between Delta Petroleum Corporation ("Delta" or the "Company")
and Aleron H. Larson, Jr. ("Employee").
Employee has in the past and does at present act as an
officer and director by the Company.
The Company desires to retain the services of Employee as an
employee upon the conditions contained in this Agreement and
Employee desires to provide services to the Company under such
conditions.
NOW THEREFORE, in consideration of the mutual covenants and
conditions hereafter set forth, the Company and Employee agree as
follows:
1. Employment. The Company hereby agrees to engage
Employee, and Employee does hereby agree to be engaged by the
Company, upon the terms and conditions set forth in the following
paragraphs. This agreement replaces and supersedes all prior
employment agreements.
2. Employment Period. The Company hereby engages Employee
for the period commencing April 10, 1998 and ending on the fifth
anniversary of such date ("Employment Period") to continue to
serve in all present positions with the Company and to render
such other services in an executive capacity as the Company shall
reasonably require. Except as provided in Paragraph 10
(Termination Upon Change in Control hereof), Employee hereby
agrees to remain in the employ of the Company for the Employment
Period, provided that Employee may, by 90 days written notice to
the Company, terminate his employment with the Company; in which
case this Agreement shall terminate, except as to provisions
which survive termination of employment as provided herein,
without liability to the Company upon the date specified by
Employee.
3. Duties. Employee agrees that at all times during the
Employment Period, he will faithfully and diligently endeavor to
promote the business and business interests of the Company, and
that he will devote such time and attention to the affairs of the
Company as is necessary and appropriate to its proper management;
provided, however, that this Agreement shall not restrict
Employee from engaging, directly or indirectly, in any business,
investment or activity which is not inconsistent with the
performance by the Employee of his duties under this Agreement.
4. Salary and Benefits. Subject to the provisions of
Paragraph 8 below, during the Employment Period, Employee shall
be compensated as follows:
a) Employee shall earn a salary of $198,000 per annum,
payable in monthly installments, subject to the customary payroll
deductions for Federal, State and local taxes, and which salary
shall escalate each year by 10% beginning January 1, 1999;
b) the Board of Directors and/or the Compensation
Committee of the Board of Directors of the Company may review
Employee's salary from time to time with a view to making such
increases in Employee's salary or declaring such bonuses or other
benefits to Employee as merited and warranted in light of factors
considered pertinent;
c) Employee shall have the use of a Company automobile,
receive free of cost parking and servicing for his automobile and
health, hospitalization and life insurance with coverage
exceeding or equal to that now in force, plus such other benefits
as the Board shall vote; and
d) Employee shall be entitled to four weeks vacation per
year to be taken at such times as do not interfere with the
performance of his duties hereunder; and
5. Expenses. All reasonable and necessary expenses
incurred by Employee in the performance of his duties under this
Agreement, including but not limited to expenses for
entertainment, travel and similar items, will be paid or
reimbursed monthly by the Company. The Company will furnish
Employee with an office in its principal executive offices in
Denver and all secretarial, geological, engineering, legal,
accounting and other services necessary to properly support
Employee's performance of his duties at the Company's expenses.
6. Disability of Employee. In the event of the disability
(as defined herein) of Employee prior to the expiration of the
Employment Period, Employee shall nevertheless continue to be
compensated for a period of one year following the date of
disability at the annual rate and with such benefits provided for
in Paragraph 4 hereof. For purposes of this Agreement, Employee
shall be deemed to be disabled if, because of illness or other
physical or mental condition, he is unable to perform for two
successive months, or for short periods aggregating over two
months in any twelve successive calendar months, his duties under
this Agreement. Such benefit period shall run from the time
disability commenced until Employee's condition improves
sufficiently to permit him to work after which date he must be
available at the Company's option.
7. Termination Upon Death and Disability. The Employment
Period shall automatically terminate upon the death of Employee;
provided, however, that in the event of the Employee's death, all
compensation Employee is entitled to receive under this Agreement
at the time of his death shall be paid to his legal
representative in accordance with the provisions of Paragraph
(4)(a) hereof for the shorter of a period of one year following
the date of Employee's death or the remainder of the Employment
Period. The Employment Period shall automatically terminate upon
the payment for twelve consecutive months of disability benefits
to Employee (as defined in Paragraph 6 above).
8. Termination for Cause. Upon the occurrence of any of
the events listed below, the Company may terminate the Employee
without further obligation under this Agreement except as to
provisions which survive termination of employment or termination
of this agreement as provided herein:
a) Employee's conviction of any criminal act directly
related to Employee's duties hereunder including without
limitation misappropriation of funds or property of the Company
or a felony criminal act directly related to Employee's duties
hereunder.
b) Employee's misfeasance or malfeasance in office, which
the parties agree shall mean fraud, dishonesty, wilful misconduct
or gross neglect of duties.
c) Breach by Employee of any material provision of this
Agreement.
9. Termination without Cause. In the event Employee is
terminated by the Company for any reason except as set forth at
Paragraph 8 above, he shall continue to be compensated, funded
and reimbursed for the duration of the Employment Period in the
full amounts provided for in Paragraphs 4, 5, 6 and 7 hereof.
10. Termination Upon Change in Control. In the event that
a Change in Control (as defined in Delta's 1993 Incentive Plan,
as amended, or as now or later defined by rules and regulations
of the S.E.C.) of the Company or a sale of all or a majority of
the Company's assets shall occur at any time during the
Employment Period, as a result of which the Board of Directors
appoints a person other than Employee to serve in the capacity
for which Employee is employed hereunder, or as a result of which
Employee shall elect to resign his executive position hereunder,
Employee nevertheless shall be entitled to the benefits of and
subject to all of the terms and conditions set forth herein,
including, without limitation, the right to receive full
compensation, funding and reimbursement as provided in Paragraphs
4, 5, 6 and 7 hereof regardless of whether Employee continues to
perform any services for the Company. In addition, in the event
of any such Change in Control or sale, irrespective of any
resulting termination or resignation, the Company shall
immediately cause all of Employee's then outstanding unexercised
options or warrants, granted under the 1993 Incentive Plan, as
amended, or otherwise, to be exercised by the Company on behalf
of Employee with the Company paying, waiving or otherwise being
responsible for the exercise prices therefore and, in addition,
the Company shall thereupon pay to Employee an amount equal to
the Employee's estimated federal, state and local taxes
applicable to the exercise of said warrants or options. All
shares underlying said options or warrants shall be issued to
Employee immediately thereafter and all shares shall be covered
by and included in an effective S-8 or similar registration
statement filed with the S.E.C. These provisions under this
Paragraph 10 shall survive any termination of this agreement
under any other section hereunder.
11. Notice of Termination. Prior to termination, for any
reason (with or without cause), Employee will be given notice
thereof sufficient to allow Employee to exercise any and all
options granted to Employee under Delta's 1993 Incentive Plan, as
amended, or otherwise, but which notice in any event shall be
given not less than thirty (30) days prior to such termination.
The expiration date of any such options which have not been
exercised and which would expire prior to or within 90 days of
any such termination shall be extended by an additional six
months.
12. Parties in Interest. This Agreement shall be binding
upon, and shall inure to the benefit of the Company and its
successors and assigns and any person acquiring, whether by
merger, consolidation, liquidation, purchase of assets or
otherwise, all or substantially all of the Company's equity or
assets, and business.
13. Choice of Law. It is the intention of the parties
hereto that this Agreement and the performance hereunder and all
suits and special proceedings hereunder be construed in
accordance with and under the laws of the State of Colorado and
that in any action, special proceeding or other proceeding that
may be brought arising out of, in connection with, or by reason
of this Agreement, the laws of the State of Colorado shall be
applicable and shall govern to the exclusion of the law of any
other forum, without regard to the jurisdiction in which any
action or special proceeding may be instituted.
14. Severance of Invalid Provisions. In case any one or
more of the provisions, or portions thereof, of this Agreement
should be determined to be invalid, illegal or unenforceable in
any respect, the validity, legality and enforceability of the
remaining provisions contained herein shall not in any way be
affected or impaired thereby.
15. Integrated Agreement. This Agreement shall constitute
the entire agreement between the parties hereto relating to the
Engagement of Employee.
IN WITNESS WHEREOF, Employee has executed this Agreement and
the Company has caused this Agreement to be duly executed on its
behalf by its duly authorized officer, all as of the date first
above written.
DELTA PETROLEUM CORPORATION
By: s/Roger A. Parker
Authorized Officer
EMPLOYEE:
s/Aleron H. Larson, Jr.
Aleron H. Larson, Jr.
RATIFIED AND APPROVED BY DELTA
PETROLEUM CORPORATION COMPENSATION
COMMITTEE:
By: s/Terry D. Enright
Terry D. Enright
s/Jerrie F. Eckelberger
Jerrie F. Eckelberger
EMPLOYMENT AGREEMENT
This agreement is entered into as of April 10, 1998, by and
between Delta Petroleum Corporation ("Delta" or the "Company")
and Roger A. Parker ("Employee").
Employee has in the past and does at present act as an
officer and director by the Company.
The Company desires to retain the services of Employee as an
employee upon the conditions contained in this Agreement and
Employee desires to provide services to the Company under such
conditions.
NOW THEREFORE, in consideration of the mutual covenants and
conditions hereafter set forth, the Company and Employee agree as
follows:
1. Employment. The Company hereby agrees to engage
Employee, and Employee does hereby agree to be engaged by the
Company, upon the terms and conditions set forth in the following
paragraphs. This agreement replaces and supersedes all prior
employment agreements.
2. Employment Period. The Company hereby engages Employee
for the period commencing April 10, 1998 and ending on the fifth
anniversary of such date ("Employment Period") to continue to
serve in all present positions with the Company and to render
such other services in an executive capacity as the Company shall
reasonably require. Except as provided in Paragraph 10
(Termination Upon Change in Control hereof), Employee hereby
agrees to remain in the employ of the Company for the Employment
Period, provided that Employee may, by 90 days written notice to
the Company, terminate his employment with the Company; in which
case this Agreement shall terminate, except as to provisions
which survive termination of employment as provided herein,
without liability to the Company upon the date specified by
Employee.
3. Duties. Employee agrees that at all times during the
Employment Period, he will faithfully and diligently endeavor to
promote the business and business interests of the Company, and
that he will devote such time and attention to the affairs of the
Company as is necessary and appropriate to its proper management;
provided, however, that this Agreement shall not restrict
Employee from engaging, directly or indirectly, in any business,
investment or activity which is not inconsistent with the
performance by the Employee of his duties under this Agreement.
4. Salary and Benefits. Subject to the provisions of
Paragraph 8 below, during the Employment Period, Employee shall
be compensated as follows:
a) Employee shall earn a salary of $198,000 per annum,
payable in monthly installments, subject to the customary payroll
deductions for Federal, State and local taxes, and which salary
shall escalate each year by 10% beginning January 1, 1999;
b) the Board of Directors and/or the Compensation
Committee of the Board of Directors of the Company may review
Employee's salary from time to time with a view to making such
increases in Employee's salary or declaring such bonuses or other
benefits to Employee as merited and warranted in light of factors
considered pertinent;
c) Employee shall have the use of a Company automobile,
receive free of cost parking and servicing for his automobile and
health, hospitalization and life insurance with coverage
exceeding or equal to that now in force, plus such other benefits
as the Board shall vote; and
d) Employee shall be entitled to four weeks vacation per
year to be taken at such times as do not interfere with the
performance of his duties hereunder; and
5. Expenses. All reasonable and necessary expenses
incurred by Employee in the performance of his duties under this
Agreement, including but not limited to expenses for
entertainment, travel and similar items, will be paid or
reimbursed monthly by the Company. The Company will furnish
Employee with an office in its principal executive offices in
Denver and all secretarial, geological, engineering, legal,
accounting and other services necessary to properly support
Employee's performance of his duties at the Company's expenses.
6. Disability of Employee. In the event of the disability
(as defined herein) of Employee prior to the expiration of the
Employment Period, Employee shall nevertheless continue to be
compensated for a period of one year following the date of
disability at the annual rate and with such benefits provided for
in Paragraph 4 hereof. For purposes of this Agreement, Employee
shall be deemed to be disabled if, because of illness or other
physical or mental condition, he is unable to perform for two
successive months, or for short periods aggregating over two
months in any twelve successive calendar months, his duties under
this Agreement. Such benefit period shall run from the time
disability commenced until Employee's condition improves
sufficiently to permit him to work after which date he must be
available at the Company's option.
7. Termination Upon Death and Disability. The Employment
Period shall automatically terminate upon the death of Employee;
provided, however, that in the event of the Employee's death, all
compensation Employee is entitled to receive under this Agreement
at the time of his death shall be paid to his legal
representative in accordance with the provisions of Paragraph
(4)(a) hereof for the shorter of a period of one year following
the date of Employee's death or the remainder of the Employment
Period. The Employment Period shall automatically terminate upon
the payment for twelve consecutive months of disability benefits
to Employee (as defined in Paragraph 6 above).
8. Termination for Cause. Upon the occurrence of any of
the events listed below, the Company may terminate the Employee
without further obligation under this Agreement except as to
provisions which survive termination of employment or termination
of this agreement as provided herein:
a) Employee's conviction of any criminal act directly
related to Employee's duties hereunder including without
limitation misappropriation of funds or property of the Company
or a felony criminal act directly related to Employee's duties
hereunder.
b) Employee's misfeasance or malfeasance in office, which
the parties agree shall mean fraud, dishonesty, wilful misconduct
or gross neglect of duties.
c) Breach by Employee of any material provision of this
Agreement.
9. Termination without Cause. In the event Employee is
terminated by the Company for any reason except as set forth at
Paragraph 8 above, he shall continue to be compensated, funded
and reimbursed for the duration of the Employment Period in the
full amounts provided for in Paragraphs 4, 5, 6 and 7 hereof.
10. Termination Upon Change in Control. In the event that
a Change in Control (as defined in Delta's 1993 Incentive Plan,
as amended, or as now or later defined by rules and regulations
of the S.E.C.) of the Company or a sale of all or a majority of
the Company's assets shall occur at any time during the
Employment Period, as a result of which the Board of Directors
appoints a person other than Employee to serve in the capacity
for which Employee is employed hereunder, or as a result of which
Employee shall elect to resign his executive position hereunder,
Employee nevertheless shall be entitled to the benefits of and
subject to all of the terms and conditions set forth herein,
including, without limitation, the right to receive full
compensation, funding and reimbursement as provided in Paragraphs
4, 5, 6 and 7 hereof regardless of whether Employee continues to
perform any services for the Company. In addition, in the event
of any such Change in Control or sale, irrespective of any
resulting termination or resignation, the Company shall
immediately cause all of Employee's then outstanding unexercised
options or warrants, granted under the 1993 Incentive Plan, as
amended, or otherwise, to be exercised by the Company on behalf
of Employee with the Company paying, waiving or otherwise being
responsible for the exercise prices therefore and, in addition,
the Company shall thereupon pay to Employee an amount equal to
the Employee's estimated federal, state and local taxes
applicable to the exercise of said warrants or options. All
shares underlying said options or warrants shall be issued to
Employee immediately thereafter and all shares shall be covered
by and included in an effective S-8 or similar registration
statement filed with the S.E.C. These provisions under this
Paragraph 10 shall survive any termination of this agreement
under any other section hereunder.
11. Notice of Termination. Prior to termination, for any
reason (with or without cause), Employee will be given notice
thereof sufficient to allow Employee to exercise any and all
options granted to Employee under Delta's 1993 Incentive Plan, as
amended, or otherwise, but which notice in any event shall be
given not less than thirty (30) days prior to such termination.
The expiration date of any such options which have not been
exercised and which would expire prior to or within 90 days of
any such termination shall be extended by an additional six
months.
12. Parties in Interest. This Agreement shall be binding
upon, and shall inure to the benefit of the Company and its
successors and assigns and any person acquiring, whether by
merger, consolidation, liquidation, purchase of assets or
otherwise, all or substantially all of the Company's equity or
assets, and business.
13. Choice of Law. It is the intention of the parties
hereto that this Agreement and the performance hereunder and all
suits and special proceedings hereunder be construed in
accordance with and under the laws of the State of Colorado and
that in any action, special proceeding or other proceeding that
may be brought arising out of, in connection with, or by reason
of this Agreement, the laws of the State of Colorado shall be
applicable and shall govern to the exclusion of the law of any
other forum, without regard to the jurisdiction in which any
action or special proceeding may be instituted.
14. Severance of Invalid Provisions. In case any one or
more of the provisions, or portions thereof, of this Agreement
should be determined to be invalid, illegal or unenforceable in
any respect, the validity, legality and enforceability of the
remaining provisions contained herein shall not in any way be
affected or impaired thereby.
15. Integrated Agreement. This Agreement shall constitute
the entire agreement between the parties hereto relating to the
Engagement of Employee.
IN WITNESS WHEREOF, Employee has executed this Agreement and
the Company has caused this Agreement to be duly executed on its
behalf by its duly authorized officer, all as of the date first
above written.
DELTA PETROLEUM CORPORATION
By: s/Aleron H. Larson, Jr.
Authorized Officer
EMPLOYEE:
s/Roger A. Parker
Roger A. Parker
RATIFIED AND APPROVED BY DELTA
PETROLEUM CORPORATION COMPENSATION
COMMITTEE:
By: s/Terry D. Enright
Terry D. Enright
s/Jerrie F. Eckelberger
Jerrie F. Eckelberger
OPTION
and
FIRST RIGHT OF REFUSAL
1. Option:
For good and valuable consideration the receipt of which is
hereby acknowledged, Evergreen Resources, Inc. ("Evergreen") is
hereby granted an option ("Option"), until November 1, 1998, to
acquire 50% of those property interests owned by Delta Petroleum
Corporation ("Delta") which are listed on the attached Exhibit A
(the "Properties") by transferring to Delta the 156,950 shares
purchased by Evergreen under an Investment Representation Agreement
of even date herewith. Delta will warrant and defend title against
all persons claiming title thereto through Delta. In the event
that Evergreen exercises its option to acquire the Properties,
Delta will assign 50% of its interest in the Properties to
Evergreen subject to its proportionate share of the reserved
production payment in favor of Burdette A. Ogle ("Ogle") described
in the copies of the documents attached hereto and listed below
(the "Documents").
The Documents provide for the reservation of an undivided
three percent (3%) of substances produced from the Properties
("Production Payment") until an aggregate amount of $8,000,000 (or
a reduced amount as provided in the Documents under certain
circumstances) has been paid to Ogle or his successors either from
any production attributable to the reserved 3% or the minimum
annual advanced payment ("Minimum Payment") discussed below. The
Documents further provide that, irrespective of whether the
Properties are producing or non-producing at any time, that Ogle
shall be paid a Minimum Payment in the amount of $350,000 per year.
This Minimum Payment may be composed of the proceeds from the
production of the reserved 3%, a direct cash payment or a
combination thereof. Upon exercise of its option, Evergreen will
assume and agree to pay the direct cash portion of the Minimum
Payment under the terms set forth in the Documents until the
production proceeds from the reserved 3% from 100% of the
Properties are adequate to cover the Minimum Payment. It is
provided, however, that Evergreen shall be responsible only for
payment of the cash portion of the Minimum Payment with respect to
the Properties and that the reserved Production Payment derived
from the reservation of an undivided three percent (3%) of
substances produced from the Properties shall burden and be paid
from 100% of the substances produced from the Properties equally
and proportionately regardless of ownership.
Delta represents that it has paid $850,000 to date in Minimum
Payments, thereby correspondingly reducing the maximum aggregate
amount due under the Production Payment from $8,000,000 to
$7,150,000. Each successive payment shall further reduce the
remaining amount due under the Production Payment.
The following Document copies are attached hereto:
* Lease interests Purchase Option Agreement between Delta
and Ogle;
* Purchase and Sale Agreement between Delta and Ogle;
* Assignments from Ogle to Delta for interests in OCS-P409,
OCS-P0415, OCS-P-0416, OCS-P0421, OCS-P0422, OCS-P0460, OCS-P0462,
and OCS-P464;
In the event Evergreen exercises its Option, the parties will
enter into agreements and assignments in the format of those
included in the attached Documents.
Until November 1, 1998, or the exercise of the Option,
whichever occurs first, Delta agrees: 1) that it will pay all costs
associated with or derived from the ownership of the Properties,
including payments to Ogle as provided in the attached Documents;
2) that it will not otherwise encumber the Properties or allow the
Properties to be encumbered in any fashion through operation of law
or otherwise except as is already provided in the attached
documents in favor of Ogle and his successors.
In the event of any failure by Delta to pay costs associated
with or derived from the ownership of the Properties or in the
event of the placement of any encumbrance upon the Properties,
Delta will notify Evergreen in writing within three business days
of such event. Upon such notification, Evergreen shall have the
option, but not the obligation, to pay such unpaid cost(s) or to
pay the funds necessary to prevent or remove any such encumbrance.
If Evergreen advances funds to Delta or directly to others for such
purposes, Delta will execute a twelve month promissory note in an
amount equal to the funds advanced with interest at ten percent
(10%) per annum in favor of Evergreen and the Properties shall
secure the repayment thereof under documentation customary in such
transactions.
2. Right of First Refusal:
In the event of a proposed sale or farmout by Delta of any of
its property interests in the offshore Santa Barbara area, Delta
agrees to afford Evergreen the right, within 30 days of written
notice by Delta to Evergreen, to purchase or farm into such
properties upon the same terms as those proposed; provided that
Evergreen must have exercised or must then exercise the above
described option.
Dated: December 23, 1997
DELTA PETROLEUM CORPORATION
s/Aleron H. Larson, Jr.
Authorized Officer,
Aleron H. Larson, Jr.,
Chairman, CEO
EVERGREEN RESOURCES, INC.
s/Mark S. Sexton
Authorized Officer,
Mark S. Sexton,
President, CEO
AGGREGATE LIST OF OIL & GAS LEASES
SUJECT TO RESERVED PRODUCTION PAYMENTS
1. San Miguel Field
OCS-P 0409: Oil and Gas LeasE from the Unitod Statos of Amorica, as
Lessor, to Oxy Petroleum, Inc., et al, as Lessee, effective July 1,
1981, designated Serial No. OCS-P 0409 and covering all of Block
22, OCS Official Protraction Diagram NI 10-6, Santa Maria (Tract
53-182).
Leasehold Interest: 12.67169%
2. Point Sal Unit
OCS-P 0415: Oil and Gas Lease from the Unitcd States of America, as
Lessor, to Ogle Petroleum Inc., et al., as Lessee, effcctive July
1, 1981 designated Serial No. OCS-P 0415, and covering all of Block
66, OCS Official Protraction Diagram, NI 10-6, Santa Maria.
Leasehold Interest: 1.88682%
OCS-P 0416: Oil and Gas Lease from the United Statos of
America, as Lessor, to Ogle Petroleum Inc., et al., as
Lessee, effective July 1, 1981 designated Serial No. OCS-P
0416, and covering all of Block 67, OCS Official Protraction
Diagram, NI 10-6, Santa Maria.
Leasehold Interest: 3.03049%
OCS-P 0421: Oil and Gas Lease from the United States of America,
as Lessor, to Ogle Petroleum Inc., et al., as Lessee, effective
Juiy 1, 1981 designated Serial No. OCS-P 0421, and covering all
of Block 110, OCS Official Protraction Diagram, NI 10-6, Santa
Maria.
Leasehold Interest: 1.88682%
OCS-P 0422: Oil and Gas Lease from the United States of America,
as Lessor, to Ogle Petroleum Inc., et al., as Lessee, effective
July 1, 1981 designated Serial No. OCS-P 0422, and covering all
of Block 111, OCS Official Protraction Diagram, Nl 10-6, Santa
Maria.
Leasehold Interest: 4.50000%
5. Gato Canyon Unit
OCS-P 0460: Oil and Gas Lease from the United States of America, as
Lessor, to Atlantic Richfield Company, as Lessee, effective August
1, 1982, designated Serial No. OCS-P 046O, and covering all of
Block 53N 72W, that portion seaward of the Three Geographical Mile
Line, Channel Islands Area, OCS Leasing Map No. 6A.
Leasehold Interest: 1.52930%
OCS-P 0462: Oil and Gas Lease from the United States of America, as
Lessor, to Ogle Petroleum Inc., et al., as Lessee, effective August 1,
1982, designated Serial No. OCS-P 0462, and covering all of Block 52N
72W, Channel Islands Area, OCS Leasing Map No. 6A.
Leasehold Interest- 1.52930%
OCS-P 0464: Oil and Gas Lease from the United States of America,
as Lessor, to Atlantic Richfield Company, as Lessee, effective
August 1, 1982, designated Serial No. OCS-P 0464, and covering all
of Block 53N 71W, that portion seaward of the Three Geographical
Mile Line, Channel Islands Area, OCS Leasing Map No. 6B.
Leasehold Interest: 1.52930%
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 24, 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 of Delta Petroleum Corporation.
s/KPMG Peat Marwick LLP
KPMG Peat Marwick LLP
Denver, Colorado
September 25, 1998
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<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> JUN-30-1998
<PERIOD-END> JUN-30-1998
<CASH> 17,135
<SECURITIES> 0
<RECEIVABLES> 351,700
<ALLOWANCES> 50,000
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<CURRENT-ASSETS> 378,935
<PP&E> 11,136,284
<DEPRECIATION> 2,234,525
<TOTAL-ASSETS> 10,349,843
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0
0
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<TOTAL-LIABILITY-AND-EQUITY> 10,349,843
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<INCOME-PRETAX> (962,003)
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