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, 1997.
[ ] 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, 1997
total $1,812,456.
The aggregate market value as of September 16, 1997 of voting
stock held by non-affiliates of the registrant was $13,313,708.
As of September 16, 1997, 5,230,631 shares of registrant's Common
Stock $.01 par value were issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE: DEFINITIVE PROXY MATERIALS
FOR THE 1997 ANNUAL MEETING OF SHAREHOLDERS - PART III, ITEMS 9,
10, 11, AND 12.
The Index to Exhibits appears at Page 25.
TABLE OF CONTENTS
PART I
PAGE
ITEM 1. DESCRIPTION OF BUSINESS 1
ITEM 2. DESCRIPTION OF PROPERTY 4
ITEM 3. LEGAL PROCEEDINGS 14
ITEM 4. SUBMISSION OF MATTERS TO A VOTE
OF SECURITY HOLDERS 14
ITEM 4A. DIRECTORS AND EXECUTIVE OFFICERS 15
PART II
ITEM 5. MARKET FOR COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS 17
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS
OR PLAN OF OPERATION 18
ITEM 7. FINANCIAL STATEMENTS 22
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH
ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 23
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS
AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE
EXCHANGE ACT 23
ITEM 10. EXECUTIVE COMPENSATION 23
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT 23
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS 23
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K 23
PART I
ITEM 1. DESCRIPTION OF BUSINESS
(a) Business Development.
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, 1997, the Company had varying interests in 96 gross (18.61
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, 1997, the Company estimated proved reserves attributable
to its onshore properties to be approximately 163,000 Bbls of oil
and 5.42 Bcf of gas, of which approximately 34,000 Bbls of oil
and 3.42 Bcf of gas were proved developed reserves. At June 30,
1997, the Company estimated proved undeveloped reserves
attributable to its offshore California properties to be
approximately 72,328,000 Bbls of oil and 77.7 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, 1997, 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 5,230,631 shares of common
stock were issued and outstanding. Delta has outstanding
warrants and options to purchase 639,500 shares of common stock
at prices ranging from $1.25 per share to $8.50 per share at June
30, 1997. Additionally, Delta has outstanding options which were
granted to officers, employees and consultants under the
Company's 1993 Incentive Plan to purchase up to 1,260,077 shares
of common stock at prices ranging from $1.25 to $9.75 per share
at June 30, 1997.
At June 30, 1997, 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.
On May 23, 1997 Delta, Underwriters Financial Group,
Inc. ("UFG") and Snyder Oil Corporation ("SOCO") entered into an
agreement under which SOCO released its lien upon the Amber stock
owned by Delta. Prior to fiscal 1997, Delta had recorded a
promissory note ("UFG Note") from UFG to SOCO as a liability
because a portion of the common shares of Amber owned by Delta
were pledged to secure the UFG Note and because of uncertainties
regarding UFG's ability to fulfill its obligations under the UFG
Note. As a result of the agreement, the liability for the UFG
Note was eliminated with a corresponding increase in Delta's
stockholders' equity. (See "Management's Discussion and Analysis
or Plan of Operations"; Item 6 herein.)
(b) Business of Issuer.
During the year ended June 30, 1997, 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; non-producing interests in the Sacramento
Basin of California and producing and non-producing interests in
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 included 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 four major customers for the sale of oil and gas as of the
date of this report, namely, Tristar Gas Marketing, KN Energy,
Colorado Interstate Gas, and Chesapeake Gas Marketing. The loss
of any one or all of these customers 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, 1998.
(12) Employees. The Company has six 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 $6,975 per month and the
lease will expire in March of 2002. Currently, Delta subleases
approximately 2,500 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, 1997, 1996
and 1995.
Principal Properties.
The following is a brief description of Delta's
principal properties:
Onshore:
California: Sacramento Basin Area
The Company is participating in four 3-D seismic survey
programs located in Colusa and Yolo counties in the Sacramento
Basin in California with interests ranging from 12% to 15%.
These programs are operated by Slawson Exploration Company, Inc.
The program areas contain approximately 120 square miles in the
aggregate upon which the Company will participate in the costs of
collecting and processing 3-D seismic data, acquiring leases and
drilling wells upon these leases. As of September 23, 1997
leases or options to lease have been acquired within the program
areas totalling 41,170 gross acres. Seismic information has been
gathered on three of the prospects and has been further processed
and interpreted on two of these prospects. Processing and
interpretation of the 60 square miles of seismic information
which has already been run in these areas has revealed
at least 41 drillable prospects. Another approximately 32
square miles of seismic information has been collected and
another approximately 28 miles remain to be shot. Wells will be
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 up to $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,
1997, one well has been drilled and casing has been run. 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 in the
Denver-Julesburg Basin of Colorado 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 16,576
gross and 10,067 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 the
wells. The acreage is located in and around the Plateau Field.
Oklahoma.
The Company directly (21 wells) and through Amber (42
wells) owns non-operating working interests in 63 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. Apache Corporation operates 16 of the wells in which
the Company owns an interest. Other major operators include
Samson Resources Corporation, Meridian Oil Company and Ricks
Exploration. 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. The Company recently sold an 80%
interest in its Moneta Hills project to KCS Mountain Resources, Inc.,
a subsidiary of KCS Energy ("KCS"). 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 casing has been run. The second well is
scheduled to be drilled prior to the end of calendar 1997. 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 also has an
interest in an additional horizontal well, the ownership of which is
subject to pending litigation. 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.
At June 30, 1997, Delta's Offshore California reserves
from these units totaled approximately 72,328,000 Bbls of oil and
77.7 Bcf of gas for an aggregate equivalent of approximately
85,274,000 BOE.
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 750
million Bbls of oil and 700 billion cubic feet of gas have been
produced and sold. Currently, POCS production is approximately
160,000 Bbls of oil and 186 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 19 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 wells needed to develop reserves in the area. Use of these
new drilling methods and seismic technologies is expected to
improve development economics.
The first three miles off the shore of the coastline
are administered by each state and are known as "state waters".
Within the state waters offshore Santa Barbara County, the State
of California regulates oil and gas leases, drilling, and the
installation of permanent and temporary producing facilities.
Because the four units in which the Company owns interests are
located outside and beyond the state waters in the POCS, the
offshore area beyond the three-mile limit, leasing and drilling
of these units are not 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. State regulations
also govern the construction and operations of on-shore
facilities such as terminals, pumping stations, and water
separation facilities, all of which require a comprehensive
permitting process. Ocean disposal of effluents, such as
drilling muds and produced waters, is administered by the EPA.
Additionally, all development plans must be consistent with the
Federal Coastal Zone Management Act ("CZM"). In California the
CZM consistency determination is taken by the California Coastal
Commission.
Santa Barbara County, through its Board of Supervisors,
also has a significant impact on the method and timing of any
offshore field development through its concurrent regulation of
the construction and operation of on-shore facilities.
Leasing, lease administration, development, and
production within the POCS all fall under federal regulations
administered by the MMS.
The Company's offshore California proved undeveloped
reserves are attributable to its interests in these 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 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. As additional information becomes available in the
future, the Company's estimates of the proved undeveloped
reserves attributable to these properties could materially
change.
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 expand and clarify the November 5th Directive
and to notify all lease owners of the course of action to be
followed by the lease and unit operators during 1997 and 1998
prior to the expiration of the SOO. This letter requests that
each operator submit a Unit (or Lease) Plan of Operations
("Plan") to the MMS by December 31, 1997. This will not be a
binding document but the MMS intends to use it in determining a
strategy for development. In early 1998 each operator is to meet
with the MMS for a review of the Plan. Based on this meeting the
operator will submit, by September 1, 1998, a final Plan for
approval. The approved Plans for the units will go into effect
on January 1, 1999.
In order to carry out the requirements of this December
24, 1996 letter, 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, consultations,
and is sharing in the costs as invoiced by the operators.
The operators have committed to meet the MMS schedules as set out above.
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. Four of the five wells drilled on the unit to date
have indicated the presence of oil and gas reserves. 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, 1997, Forrest A. Garb &
Associates, Inc. ("Garb"), an independent petroleum engineering
firm based in Dallas, Texas, issued a report stating that Gato
Canyon contains proved recoverable reserves estimated to be 123.8
million Bbls of oil and 173.3 Bcf of natural gas, representing
15.84 million Bbls of oil and 22.17 Bcf of natural gas net to the
Company's 15.60% working interest at July 1, 1997. The oil has
an estimated average gravity of 16 degrees API. Based on prices of
$12.50 per Bbl and $1.41 per Mcf and applicable regulatory
parameters, the Company's 15.60% working interest in the Gato
Canyon Unit had a pretax discounted (10%) present value of
approximately $18,357,000 as of July 1, 1997. (See "--Oil and Gas
Reserves".)
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 subsidiary of Shell Oil Company.
All four wells drilled on this unit have indicated the presence
of producible oil and gas reserves 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 effective
July 1, 1997, Point Sal Unit contains proved undeveloped
recoverable reserves of 280.7 million Bbls of oil and 314.3 Bcf
of natural gas, equivalent to 15.71 million Bbls of oil and 17.59
Bcf of natural gas net to the Company's interest at July 1, 1997.
Based on prices of $12.50 per barrel and $1.41 per Mcf and
applicable regulatory parameters, the Company's 6.83% working
interest in the Point Sal Unit had a pre-tax present value
(discounted at 10%) of approximately $16,220,000 as of July 1,
1997. (See "-- Oil and Gas Reserves".)
Lion Rock Unit and Federal OCS Tract 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 Tract 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 also operated by
Aera Energy LLC, a subsidiary of Shell Oil Company. An aggregate
of seven wells have been drilled on this unit of which four have
been completed and tested which indicate producible oil and gas
reserves in the Monterey Formation. Additionally, the unit is
immediately contiguous with the San Miguel Field which is in the
same reservoir as defined by drilling and testing of six wells,
seismic data and geological analysis to date. Based on a report
prepared by Garb as of July 1, 1997, the Lion Rock Unit
(including lease P-0409) contains proved undeveloped recoverable
reserves of 527.1 million Bbls of oil and 474.4 Bcf of natural
gas, equivalent to 36.76 million Bbls of oil and 33.08 Bcf of
natural gas net to the Company's interest at July 1, 1997. The
oil has an average estimated gravity of 10.7 degrees API. Based on
prices of $12.50 per barrel and $1.41 per Mcf and applicable
regulatory parameters, the Company's aggregate interest in the
Lion Rock Unit had a pre-tax present value (discounted at 10%) of
approximately $33,035,000 as of July 1, 1997. (See "--Oil and
Gas Reserves".) The Garb evaluation includes the Lion Rock Unit
and Federal OCS Tract P-0409 which are both included in the San
Miguel Field. This tract 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.
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
have been completed and tested to date with calculated flow rates
of from 4,000 to 5,000 Bbls per day, which indicate producible
oil (having an estimated average gravity of 10.6 degrees API) and gas
reserves in the Monterey Formation. Based on a July 1, 1997
report prepared by Garb, the Sword Unit contains proved
undeveloped recoverable reserves of 193.9 million Bbls of oil and
232.7 Bcf of natural gas representing reserves of 4.03 million
Bbls of oil and 4.83 Bcf of natural gas net to the Company's
interest at July 1, 1997. Based on prices of $12.50 per barrel
and $1.41 per Mcf and applicable regulatory parameters, the
Company's interest in the Sword Unit had a pre-tax present value
(discounted at 10%) of approximately $3,964,000 as of July 1,
1997. (See "--Oil and Gas Reserves".)
(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, 1997,
1996 and 1995, 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,
1997 1996 1995
Average sales price:
Oil (per barrel) $ 22.36 17.74 13.64
Natural Gas (per Mcf) $ 2.14 1.71 1.55
Production costs
(per Mcf equivalent) $ .85 .78 .48
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, 1997, 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 5 2.2 0 .0 1,558 393
Colorado 8 .8 13 10.3 2,560 2,127
Oklahoma 1 .1 63 4.0 24,793 1,857
Wyoming 0 .0 6 1.2 960 192
14 3.1 82 15.5 29,871 4,569
(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, 1997, the Company held undeveloped acreage
by state as set forth below:
Undeveloped Acres (1) (2)
Location Gross Net
Wyoming 27,723 4,776
California, offshore(3) 50,805 4,244
California, onshore 41,170 5,368
Colorado 14,496 7,987
Oklahoma 3,360 271
Total 137,554 22,646
(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, 1997 June 30, 1996 June 30, 1995
Gross Net Gross Net Gross Net
Exploratory Wells(1):
Productive:
Oil. . . . . . . . . 0 .0 0 .0 0 .0
Gas. . . . . . . . . 0 .0 0 .0 1 .1
Nonproductive. . . . . 1 1.0 0 .0 1 .1
Total. . . . . . . . . 1 1.0 0 .0 2 .2
Development Wells(1):.
Productive:
Oil. . . . . . . . 0 .0 0 .0 2 .1
Gas. . . . . . . . 4 .2 2 .1 4 .2
Nonproductive. . . . 0 .0 0 .0 2 .1
Total. . . . . . . . 4 .2 2 .1 8 .4
Total Wells(1):
Productive:
Oil. . . . . . . . 0 .0 0 .0 2 .1
Gas. . . . . . . . 4 .2 2 .1 5 .3
Nonproductive. . . . 1 1.0 0 .0 3 .2
Total Wells. . . . . 5 1.2 2 .1 10 .6
(1) Does not include wells in which the Company had only a
royalty interest.
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. 52 Chairman of the May 1987
Board, Chief to Present
Executive Officer
Secretary, Treasurer,
and a Director
Roger A. Parker 35 President and May 1987
a Director to Present
Terry D. Enright 48 Director November 1987
to Present
Jerrie F. Eckelberger 53 Director September 1996
to Present
* Mr. Eckelberger was appointed as a director on
September 27, 1996 to fill the vacancy created by the death of
Don Mettler on September 3, 1996.
The following is biographical information as to the
business experience of each current officer and director of the
Company.
Aleron H. Larson, Jr., age 52, 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 18.74% 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 35, 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 48, 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 53, 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 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 Mettler served as the audit committee
and as the compensation committee. Messrs. Enright and Mettler
also constituted the Incentive Plan Committee for the Delta 1993
Incentive Plan for the Company. Upon appointment of Mr.
Eckelberger as a director subsequent to Mr. Mettler's death, Mr.
Eckelberger was also appointed to the Audit, Compensation and
Incentive Plan Committees to serve with Mr. Enright.
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, 1995 8.50 5.00
December 31, 1995 8.13 6.63
March 31, 1996 7.38 6.00
June 30, 1996 7.25 5.75
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
On September 23, 1997, the closing price of the Common
Stock was $3.75.
(b) Approximate Number of Holders of Common Stock.
The number of holders of record of the Company's
Common Stock at August 27, 1997 was approximately 1,047 which
does not include an unknown number of 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.
On December 20, 1996, the Company exchanged 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.
This transaction was exempt from registration under the
Securities Act of 1933 pursuant to Section 4(2) thereof.
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF
OPERATION
Liquidity and Capital Resources.
At June 30, 1997, the Company had a working capital
deficit of $530,822 compared to a working capital deficit of
$1,444,584 at June 30, 1996. The Company s working capital
deficit at June 30, 1996 included a note payable ( Note ) to
Snyder Oil Corporation ( SOCO ) by Underwriters Financial Group,
Inc., ( UFG ), the Company s former parent, which represents
UFG's obligation under the Note, which was recorded upon the
transfer by UFG (subject to the Note) of the common stock of
Amber to the Company in 1992. Prior to fiscal 1997, Delta had
recorded the Note as a liability 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 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, and as a reduction of the adjustment recorded to
stockholders' equity for the elimination of the liability for the
Note.
The Company's current liabilities include royalties
payable of $468,968 at June 30, 1997 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 1997 and 1996.
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 $1,500,000 for the year
ended June 30, 1998. 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
1998 and $1.0 and $4.2 million are expected to be incurred during
fiscal 1999 and 2000, 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 9, 1996, the Company established a series of
1,000 shares of Convertible Preferred stock designated Series C.
This stock converts into a number of shares of common stock
determined by a fraction the numerator of which is $10,000 and
the denominator of which is the lessor of $4.50 or 65% of the
previous five day average closing price of the corporation s
shares reported by NASDAQ; provided that if the five day average
closing price is less than $3.00 per share, then the $3.00 shall
be the denominator. On May 17, 1996 and June 6, 1996 the Company
sold a total of 160 shares of Series C Convertible Preferred
stock to certain unrelated individuals for $1,600,000.
Commissions paid on the sale of the preferred stock amounted to
$160,000. In a series of transactions during first quarter of
fiscal 1997, the 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 $760,844,
$1,664,350 and $284,073 during the years ended June 30, 1997,
1996 and 1995, respectively. On August 18, 1995, the Company
completed a sale of 231,000 shares of the Company's common stock
to third parties for $750,000 with net of proceeds to the Company
of $675,000 after payment of certain fees. Under the purchase
agreement the Company committed to register the shares within 30
days or increase the number of shares by 25,000 with an increase
of an additional 5,000 shares each 30 days thereafter until the
expiration of six months after which the Company had agreed to
repurchase all shares issued for $750,000 and to deliver a
promissory note therefore, with interest payable at 15% per annum
from the date funds were received. During fiscal 1996, in a
series of transactions, the redeemable shares were sold
privately, thereby waiving all rights of redemption. The Company
delivered a total of 276,000 shares before the redeemable shares
were sold privately. As a result of the sale, $750,000 ($675,000
net of commissions) was credited to equity.
During the year ended June 30, 1996, the Company raised
an additional $639,115 through the issuance of 140,478 shares of
the Company's common stock in private transactions.
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 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, 1997 was $2,457,007 compared to the net loss
of $3,328,230 for the year ended June 30, 1996. The loss for the
years ended June 30, 1997 and 1996 included stock option expense
of $40,469 and $293,125, respectively, for options granted to
certain officers, directors, employees and consultants. In
addition, the losses for the years ended June 30, 1997 and 1996
also included $350,000 and $250,000, respectively, 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, 1997 and 1996
also included $364,019 and $375,301, respectively, for abandoned
and impaired properties. Of these amounts, $77,168 in 1997 and
$56,461 in 1996 are write-downs of the Company's oil and gas
properties to comply with SFAS 121 "Accounting for the Impairment
of Long-Lived Assets and Long-Lived Assets to be Disposed of".
Revenue. Total revenue for the year ended June 30, 1997
was $1,812,456 compared to $1,385,317 for the year ended June 30,
1996. Oil and gas sales for the year ended June 30, 1997 were
$1,554,134 compared to $1,044,873 for the year ended June 30,
1996. The increase in oil and gas sales during the year ended
June 30, 1997 resulted from workovers, recompletion and
additional drilling in the Piceance Basin of Colorado, the
Anadarko Basin of Oklahoma, and the Moneta Hills project in
Wyoming and the increase in oil and gas prices during fiscal
1997.
Production volumes and average prices received for the
years ended June 30, 1997 and 1996 are as follows:
1997 1996
Production:
Oil (barrels) 7,755 10,713
Gas (Mcf) 644,256 499,294
Average Price:
Oil (per barrel) $22.36 $17.74
Gas (per Mcf) $ 2.14 $ 1.71
Lease Operating Expenses. Lease operating expenses for
the year ended June 30, 1997 were $587,251 compared to $439,805
for the year ended June 30, 1996. On an Mcf equivalent basis,
production expenses and taxes were $.85 per Mcf equivalent during
the year ended June 30, 1997 compared to $.78 per Mcf equivalent
for the year ended June 30, 1996. The increase in lease
operating costs on an equivalent basis compared to 1996 resulted
primarily from workover expenses relating to certain wells in
Wyoming.
Depreciation and Depletion Expense. Depreciation and
depletion expense for the year ended June 30, 1997 was $320,292
compared to $341,813 for the year ended June 30, 1996. On a Mcf
equivalent basis, the depletion rate was $.46 per Mcf equivalent
during the year ended June 30, 1997 compared to $.61 per Mcf
equivalent for the year ended June 30, 1996. The decrease in
depletion rate compared to 1996 is primarily the result of the
impairment of properties recorded in 1996 which reduced the
depletable basis in the properties.
Exploration Expenses. Exploration expenses consist of
geological and geophysical costs and lease rentals. Exploration
expenses were $607,431 for the year ended June 30, 1997 compared
to $110,963 for the year ended June 30, 1996. The increase in
exploration expenses compared to 1996 is primarily the result of
the Company s participation in the shooting of 3-D seismic on
four surveys 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,
1997 of $364,019 compared to $375,301 in 1996. The expense in
1997 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 on these properties. The expense
in 1996 includes a provision for impairment of the costs
associated with the original application for the South Sulu Sea
Geophysical Survey and Exploration Contract of $318,840. The
Company recorded a provision for impairment of the costs incurred
to date as a result of the Philippine Government's request to
resubmit the application.
General and Administrative Expenses. General and
administrative expenses for the year ended June 30, 1997 were
$1,808,701 compared to $2,457,423 for the year ended June 30,
1996. General and administrative expenses decreased from 1996 to
1997 primarily as a result of a decrease in broker and
shareholder relations expense.
Stock Option Expense. Stock option expense has been
recorded for the years ended June 30, 1997 and 1996 of $40,469
and $293,125, 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 1997 and
in 1996 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 1997 and $250,000 in
1996 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, 1997, the Company has paid a
total of $850,000 in minimum royalty payments.
Interest on Notes Payable. Interest on notes payable
was $0 and $439,399 for the years ended June 30, 1997 and June
30, 1996, respectively. Interest expense represents interest on
the SOCO Note.
Recent Accounting Standards
Statement of Financial Accounting Standards 123,
"Accounting for Stock Based Compensation" (SFAS 123), was
issued by the Financial Accounting Standards Board in October
1995. SFAS 123 established financial accounting and
reporting standards for stock-based employee compensation plans
as well as transactions in which an entity issues its equity
instruments to acquire goods or services from non-employees. The
Company has disclosed the information required by SFAS 123 in
the notes to the consolidated financial statements.
Statement of Financial Accounting Standards 128,
"Earnings Per Share" (SFAS 128), was issued by the Financial
Accounting Standards Board in February, 1997. SFAS 128
specifies the computation, presentation and disclosure
requirements for earnings per share for entities with publicly
held common stock. This statement simplifies the computation of
earnings per share and is required to be adopted by the Company
in the year ending June 30, 1998. The Company has not yet
evaluated the effects of adopting this statement.
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 25 are filed as part of this report.
(b) Reports on Form 8-K.
Form 8-K dated April 24, 1997; Items 5 and 7.
Form 8-K dated May 23, 1997; Items 5 and 7.
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 9/24/97
By (Signature and Title) s/Roger A. Parker
Roger A. Parker, Director
Date 9/24/97
By (Signature and Title) s/Terry D. Enright
Terry D. Enright, Director
Date 9/24/97
By (Signature and Title) s/Jerrie F. Eckelberger
Jerrie F. Eckelberger, Director
Date 9/24/97
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 November 28, 1994 agreement between Amber Resources
Company (a 92% owned subsidiary of the Company) and El Paso
Natural Gas Company exchanging four Amber wells for satisfaction
of Amber's +967,911 Mcf recoupment gas obligation. Incorporated by
reference from Exhibit 28.1 to the Company's Form 8-K dated
November 21, 1994.
10.9 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.
10.10 Agreement between Corporate Relations Group and Delta
Petroleum Corporation effective August 10, 1995. Incorporated
by reference from Exhibit 99.1 to the Company's Form 8-K dated
August 18, 1995.
10.11 Agreements dated August 15, 1995 with Corporate
Relations Group, Inc. relating to the purchase of stock.
Incorporated by reference from Exhibit 99.2 to the Company's Form
8-K dated August 18, 1995.
10.12 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.
10.13 Agreement between LoTayLingKyur, Inc. and Delta
Petroleum Corporation effective June 15, 1995. Incorporated by
reference to Exhibit 99.4 to the Company's Form 8-K dated
August 18, 1995.
10.14 Agreement with Miller Financial Group, Inc. dated August
3, 1995. Incorporated by reference to Exhibit 99.5 to the
Company's Form 8-K dated August 18, 1995.
10.15 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.
10.16 Agreement dated August 1, 1995 with David Castaneda
relating to employment. Incorporated by reference to Exhibit
99.8 to the Company's Form 8-K dated August 18, 1995.
10.17 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.
10.18 Agreement dated October 31, 1995 between Delta, Melange
Associates, Inc., Nautilus Oil and Gas Company and Thorofare
Resources, Inc. Incorporated by reference from Exhibit 99.1
to the Company's Form 8-K dated November 1, 1995.
10.19 Agreement between Delta and Sunnyside Production
Company, LLC. Incorporated by reference from Exhibit 99.2 to the
Company's Form 8-K dated November 1, 1995.
10.20 Copies of Aleron H. Larson, Jr. and Roger A. Parker
Employment Agreements. Incorporated by reference from Exhibit
99.1 to the Company's Form 8-K dated December 14, 1995.
10.21 Copy of the 1995 Non-employee Director Stock Plan.
Incorporated by reference from Exhibit 99.2 to the Company's
Form 8-K dated December 14, 1995.
10.22 Wagner & Brown, Ltd. Moneta Hills Purchase and Sale
Agreement (without exhibits) and Assignment and Assumption
Agreement. Incorporated by reference from Exhibit 99.1 to the
Company's Form 8-K dated April 5, 1996.
10.23 C.A. Opportunidad stock purchase agreement.
Incorporated by reference from Exhibit 99.2 to the Company's Form
8-K dated April 5, 1996.
10.24 Employment and related agreements including Stock Voting
Agreement. Incorporated by reference from Exhibit 99.3 to the
Company's Form 8-K dated April 5, 1996.
10.25 Employment agreement. Incorporated by reference from
Exhibit 99.4 to the Company's Form 8-K dated April 5, 1996.
10.26 Amendment to Corporate Relations Group, Inc. and Delta
Petroleum Corporation, Public Relations/Marketing Contract
dated August 10, 1995. Incorporated by reference from Exhibit
99.1 to the Company's Form 8-K dated June 27, 1996.
10.27 Investment Representation Agreement Regarding Offshore
Subscriptions for C.A. Opportunidad. Incorporated by
reference from Exhibit 99.2 to the Company's Form 8-K dated
June 27, 1996.
10.28 Investment Representation Agreement Regarding Offshore
Subscriptions for Fondo de Adquisciones E Inversiones
Internacionales XL S.A. Incorporated by reference from
Exhibit 99.3 to the Company's Form 8-K dated June 27, 1996.
10.29 Employment agreement with Aleron H. Larson, Jr.,
Chairman. Incorporated by reference from Exhibit 99.4 to the
Company's Form 8-K dated June 27, 1996.
10.30 Employment agreement with Roger A. Parker, President.
Incorporated by reference from Exhibit 99.5 to the Company's
Form 8-K dated June 27, 1996.
10.31 Letter agreement (without exhibits) with Slawson
Exploration Company, Inc. dated August 22, 1996 for an interest
in the Yolo Bypass prospect. Incorporated by reference from
Exhibit 99.2 to the Company's Form 8-K dated October 10, 1996.
10.32 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.
10.33 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.
10.34 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.
10.35 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.
10.36 Employment agreement with David Castaneda. Incorporated
by reference from Exhibit 99.3 to the Company's Form 8-K dated
January 7, 1997.
10.37 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.
10.38 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.
10.39 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.
10.40 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.
(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. Not applicable.
(24) Power of Attorney. Not applicable.
(27) Financial Data Schedule. Filed herewith electronically.
(99) Additional Exhibits. Not applicable.
Independent Auditor's 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, 1997
and 1996 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 statemetns based on our audits.
We conduted 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 misstatements. 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 presents fairly, in all material respects, the financial
position of Delta Petroleum Corporation and subsidiary as of June
30, 1997 and 1996 and the results of their operations and their
cash flows for the years then ended, in conformity with generally
accepted accounting principles.
KPMG Peat Marwick LLP
s/KPMG Peat Marwick LLP
Denver, Colorado
September 16, 1997
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
June 30, 1997 and 1996
1997 1996
ASSETS
Current Assets:
Cash $393,048 1,629,738
Trade accounts receivable, net of
allowance for doubtful accounts
of $50,000 in 1997 and $48,722 in 1996 333,535 377,260
Other current assets 10,100 12,100
Total current assets 736,683 2,019,098
Property and Equipment:
Oil and gas properties, at cost (using
the successful efforts method
of accounting) (Note 10):
Undeveloped offshore California
properties 6,959,830 6,786,580
Undeveloped onshore domestic properties 714,605 971,648
Developed onshore domestic properties 3,383,523 2,919,451
Office furniture and equipment 80,446 78,188
11,138,404 10,755,867
Less accumulated depreciation and depletion (2,059,461) (1,787,443)
Net property and equipment 9,078,943 8,968,424
Investment in Bion Environmental
Technologies, Inc. (Bion) (Note 2) 503,328 411,483
Accounts receivable from affiliates (Note 7) 119,419 116,727
$10,438,373 11,515,732
LIABILITIES AND STOCKHOLDERS' EQUITY
1997 1996
Current Liabilities:
Accounts payable trade $776,702 304,050
Other accrued liabilities 21,835 68,297
Royalties payable 468,968 649,835
Note and accrued interest payable
by Underwriters Financial Group (UFG)
(the Company's former parent) (Note 3) - 2,669,642
Total current liabilities 1,267,505 3,691,824
Stockholders' Equity (Note 4):
Preferred stock, $.10 par value;
authorized 3,000,000 shares,
issued 160 shares in 1996 - 16
Common stock, $.01 par value;
authorized 300,000,000 shares,
issued 5,230,631 shares in 1997 and
4,488,283 shares in 1996 52,306 44,882
Additional paid-in capital 24,950,128 21,299,784
Unamortized consulting expense - (105,000)
Cumulative unrealized loss (Note 2) (213,969) (255,184)
Accumulated deficit (15,617,597) (13,160,590)
Total stockholders' equity 9,170,868 7,823,908
Commitments (Note 8)
$10,438,373 11,515,732
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended June 30, 1997 and 1996
1997 1996
Revenue:
Oil and gas sales $1,554,134 1,044,873
Gain on sale of oil and gas properties 2,524 -
Other revenue 255,798 340,444
Total revenue 1,812,456 1,385,317
Expenses:
Lease operating expenses 587,251 439,805
Depreciation and depletion 320,292 341,813
Exploration expenses 607,431 110,963
Abandoned and impaired properties 364,019 375,301
Dry hole costs 191,300 5,718
Minimum royalty to related party (Note 7) 350,000 250,000
General and administrative 1,808,701 2,457,423
Stock option expense 40,469 293,125
Interest on notes payable - 439,399
Total expenses 4,269,463 4,713,547
Net loss ($2,457,007) ($3,328,230)
Loss per common share ($0.49) (0.81)
Weighted average number of common
shares outstanding 5,029,009 4,113,251
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Consolidated Statement of Stockholders' Equity
Years ended June 30, 1997 and 1996
<TABLE>
<CAPTION>
Preferred Stock Common Stock
Shares Amount Shares Amount
<S> <C> <C> <C> <C>
Balance, July 1, 1995 - $ 3,550,882 35,509
Unrealized gain on equity securities (Note 2) - - - -
Shares issued for cash -- preferred stock (Note 4) 160 16 - -
Commission paid on issuance of preferred stock - - - -
Shares issued for cash - common stock - - 140,478 1,405
Shares issued for cash-redeemable
common stock (Note 4) - - 276,000 2,760
Commission paid on issuance of redeemable
common stock (Note 4) - - - -
Capital contributions from UFG - - - -
Shares issued for cash upon exercise
of options (Note 4) - - 351,350 3,513
Shares issued for undeveloped oil and
gas properties (Note 4) - - 31,127 311
Shares issued for developed oil and
gas properties (Note 4) - - 5,000 50
Stock options granted as compensation (Note 4) - - - -
Shares issued for services (Note 4) - - 127,046 1,270
Amortization of consulting expense (Note 4) - - - -
Shares issued for obligation payable in common stock - - 6,400 64
Net loss - - - -
Balance, June 30, 1996 160 16 4,488,283 44,882
Unrealized gain on equity securities (Note 2) - - - -
Preferred stock converted into common
stock (Note 4) (160) (16) 396,601 3,966
Shares issued for cash upon exercise of
options (Note 4) - - 186,700 1,867
Shares issued for undeveloped oil and
gas properties (Note 4) - - 63,000 630
Shares issued for developed oil and
gas properties (Note 4) - - 500 5
Shares issued for services (Note 4) - - 7,500 75
Amortization of consulting expense (Note 4) - - - -
Shares of common stock reacquired and
retired (Note 4) - - (4,070) (40)
UFG settlement (Note 3) - - 92,117 921
Net loss - - - -
Balance, June 30, 1997 - $ 5,230,631 52,306
</TABLE>
<TABLE>
<CAPTION>
Obligation Additional Unamortized
payable in paid-in consulting
common stock capital expense
<S> <C> <C> <C>
Balance, July 1, 1995 46,400 15,627,201 -
Unrealized gain on equity securities (Note 2) - - -
Shares issued for cash -- preferred stock (Note 4) - 1,599,984 -
Commission paid on issuance of preferred stock - (160,000) -
Shares issued for cash - common stock - 637,710 -
Shares issued for cash-redeemable common stock (Note 4) - 747,240 -
Commission paid on issuance of redeemable
common stock (Note 4) - (75,000) -
Capital contributions from UFG - 62,098 -
Shares issued for cash upon exercise of options (Note 4) - 1,660,837 -
Shares issued for undeveloped oil and gas properties (Note 4) - 115,290 -
Shares issued for developed oil and gas properties (Note 4) - 16,825 -
Stock options granted as compensation (Note 4) - 365,977 -
Shares issued for services (Note 4) - 655,286 (656,556)
Amortization of consulting expense (Note 4) - - 551,556
Shares issued for obligation payable in common stock (46,400) 46,336 -
Net loss - - -
Balance, June 30, 1996 - 21,299,784 (105,000)
Unrealized gain on equity securities (Note 2) - 40,469 -
Preferred stock converted into common stock (Note 4) - (3,950) -
Shares issued for cash upon exercise of options (Note 4) - 758,977 -
Shares issued for undeveloped oil and gas properties (Note 4) - 172,620 -
Shares issued for developed oil and gas properties (Note 4) - 1,604 -
Shares issued for services (Note 4) - 29,925 -
Amortization of consulting expense (Note 4) - - 105,000
Shares of common stock reacquired and retired (Note 4) - (18,022) -
UFG settlement (Note 3) - 2,668,721 -
Net loss - - -
Balance, June 30, 1997 - 24,950,128 -
</TABLE>
<TABLE>
Cumulative
unrealized
gain Accumulated
(loss) deficit Total
<S> <C> <C> <C>
Balance, July 1, 1995 (350,142) (9,832,360) 5,526,608
Unrealized gain on equity securities (Note 2) 94,958 - 94,958
Shares issued for cash -- preferred stock (Note 4) - - 1,600,000
Commission paid on issuance of preferred stock - - (160,000)
Shares issued for cash - common stock - - 639,115
Shares issued for cash-redeemable
common stock (Note 4) - - 750,000
Commission paid on issuance of redeemable
common stock (Note 4) - - (75,000)
Capital contributions from UFG - - 62,098
Shares issued for cash upon exercise
of options (Note 4) - - 1,664,350
Shares issued for undeveloped oil
and gas properties (Note 4) - - 115,601
Shares issued for developed oil
and gas properties (Note 4) - - 16,875
Stock options granted as compensation (Note 4) - - 365,977
Shares issued for services (Note 4) - - -
Amortization of consulting expense (Note 4) - - 551,556
Shares issued for obligation payable in common stock - - -
Net loss - (3,328,230) (3,328,230)
Balance, June 30, 1996 (255,184) (13,160,590) 7,823,908
Unrealized gain on equity securities (Note 2) 41,215 - 81,684
Preferred stock converted into common
stock (Note 4) - - -
Shares issued for cash upon exercise
of options (Note 4) - - 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 (Note 4) - - 30,000
Amortization of consulting expense (Note 4) - - 105,000
Shares of common stock reacquired and
retired (Note 4) - - (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
</TABLE>
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended June 30, 1997 and 1996
<TABLE>
<CAPTION>
1997 1996
<S> <C> <C>
Cash flows operating activities:
Net loss ($2,457,007) (3,328,230)
Adjustments to reconcile net loss to cash used in
operating activities:
Write-off royalties payable (180,867) (288,954)
Depreciation and depletion 320,292 341,813
Abandoned and impaired properties 364,019 375,301
Bad debt expense (Note 7) 60,604 -
Amortization of consulting expense 105,000 551,556
Stock option expense 40,469 365,977
Gain on sale of oil and gas properties (2,524) -
Common stock issued for services 30,000 -
Interest on note payable by UFG - 436,787
Net changes in current assets and
and current liabilities:
Increase in trade accounts receivable (8,183) (50,075)
Decrease (increase) in other current assets 2,000 (10,000)
Increase (decrease) in accounts payable trade 472,652 (236,590)
Decrease in accrued interest payable - (8,000)
Decrease in other accrued liabilities (46,462) (114,701)
Decrease in consulting fees payable
to stockholder - (162,500)
Increase in royalties payable - 27,715
Net cash used in operating activities (1,300,007) (2,099,901)
Cash flows from investing activities:
Additions to property and equipment (1,068,167) (611,069)
Proceeds from sale of oil and gas properties 450,720 -
Net cash used in investing activities (617,447) (611,069)
Cash flows from financing activities:
Stock issued for cash upon exercise of options 742,782 1,664,350
Repayments of note payable - (100,000)
Issuance of redeemable preferred stock for cash - 1,600,000
Commission paid on issuance of redeemable
preferred stock - (160,000)
Issuance of redeemable common stock for cash - 750,000
Commission paid on issuance of redeemable
common stock - (75,000)
Issuance of common stock for cash - 639,115
(Increase) decrease in accounts receivable from
affiliates (62,018) (33,590)
Net cash provided by financing activities 680,764 4,284,875
Net (decrease) increase in cash (1,236,690) 1,573,905
Cash at beginning of year 1,629,738 55,833
Cash at end of year $393,048 1,629,738
Supplemental cashflow information:
Cash paid for interest - 10,612
Non-cash financing activities:
Common stock issued for properties $174,859 132,476
</TABLE>
See accompanying notes to consoldiated financial statements.
DELTA PETROLEUM CORPORATION
AND SUBSIDIARY
Notes to Consolidated Financial Statements
June 30, 1997 and 1996
(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, 1997, 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) was issued in March
1995. This statement requires that long-lived assets be
reviewed for impairment when events or changes in
circumstances indicate that the carrying value of such
assets may not be recoverable. This review consists of a
comparison of the carrying value of
the asset with the asset's expected future undiscounted cash
flows without interest costs.
Estimates of expected future cash flows are to represent
management's best estimate based on reasonable and
supportable assumptions and projections. If the expected
future cash flows exceed the carrying value of the asset, no
impairment is recognized. If the carrying value of the
asset exceeds the expected future cash flows, an impairment
exists and is measured by the excess of the carrying value
over the estimated fair value of the asset. Any impairment
provisions recognized in accordance with SFAS 121 are
permanent and may not be restored in the future.
The Company's proved properties were assessed for impairment
on an individual field basis and the Company recorded
impairment provisions attributable to certain producing
properties of $77,168 and $56,461 for the years ended June
30, 1997 and 1996, 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, 1997, the Company had produced and recognized
as revenue approximately 169,000 Mcf more than its entitled
share of production. The undiscounted value of this
imbalance is approximately $340,000 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 1997
and 1996.
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.
Income (Loss) Per Common Share
Income (loss) per share is computed by dividing the net
income or loss for the period by the weighted average number
of shares of common stock outstanding during the period.
Common stock options and warrants have not been considered
in the calculation of earnings per share as their effect is
antidilutive.
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 reported period. Actual results
could differ from these estimates.
Reclassifications
Certain amounts in the 1996 financial statements have been
reclassified to conform to the 1997 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 1997, the Company received an additional
22,524 shares of Bion's common
stock for rent and other services provided by the Company.
The 149,134 shares of Bion's common stock owned by the
Company represents approximately 4% of the outstanding
shares of Bion at June 30, 1997.
The cost and estimated market value of the Company's
investment in Bion at June 30, 1997 and 1996 are as follows:
Estimated
Unrealized Market
Cost (Loss) Value
1997 $717,297 (213,969) 503,327
1996 $666,667 (255,184) 411,483
As of September 2, 1997 the estimated market value of the
Company's investment in Bion, based on the quoted bid price
of Bion's common stock, was $484,685.
(3) Note Payable by UFG
At June 30, 1997, the note payable ( Note ) to Snyder Oil
Corporation ( SOCO ) by Underwriters Financial Group, Inc.,
( UFG ), the Company s former parent, represents UFG s
obligation under the Note, which was recorded upon the
transfer by UFG (subject to the Note) of the common stock of
Amber to the Company in 1992. Prior to fiscal 1997, Delta had
recorded the Note as a liability 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.
On May 9, 1996, the Company established a series of 1,000
shares of Convertible Preferred stock designated Series C.
This stock converts into a number of shares of common stock
determined by a fraction the numerator of which is $10,000 and
the denominator of which is the lesser of $4.50 or 65% of the
previous five day average closing price of the corporation's
share reported by NASDAQ; provided that if the five day
average closing price is less than $3.00 per share then the
$3.00 shall be the denominator.
On May 17, 1996 and June 6, 1996 the Company sold a total of
160 shares of Series C Convertible Preferred stock to certain
unrelated individuals for $1,600,000. Commissions paid on the
sale of the preferred stock amounted to $160,000.
During the year ended June 30, 1997, the 160 share of Series
C Convertible Preferred stock were converted into 396,601
shares of the Company's common stock.
Common Stock
On August 18, 1995, the Company completed a sale of 231,000
shares of the Company's common stock to third parties for
$750,000 with net proceeds to the Company of $675,000 after
payment of certain fees. Under the purchase agreement the
Company committed to register the shares within 30 days or
increase the number of shares by 25,000 with an increase of an
additional 5,000 shares each 30 days thereafter until the
expiration of six months after which the Company has agreed to
repurchase all shares issued for $750,000 and to deliver a
promissory note therefore, with interest payable at 15% per
annum from the date funds were received. During fiscal 1996,
in a series of transactions, the redeemable shares were sold
privately, thereby waiving all rights of redemption. The
Company delivered a total of 276,000 shares before the
redeemable shares were sold privately. As a result of the
sale, $750,000 ($675,000 net of certain commission) was
credited to shareholders' equity.
During the year ended June 30, 1996, the Company raised
$639,115 through the issuance of 140,478 shares of the
Company's common stock in private transactions.
The Company received proceeds from the exercise of options to
purchase shares of its common stock of $760,844 during the
year ended June 30, 1997 and $1,664,350 during the year ended
June 30, 1996.
During the years ended June 30, 1997 and 1996, 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, 1997 and 1996 are as
follows:
1997
Weighted-Average
Options Exercise Price
Outstanding-beginning
of year 922,350 $3.85
Granted 546,000 5.39
Exercised (186,700) 4.06
Returned (21,573) 3.75
Repriced 918,027 3.64
Returned for repricing (918,027) 5.58
Outstanding-end
of year 1,260,077 $3.25
Exercisable at
end of year 1,185,077 $3.20
1996
Weighted-Average
Options Exercise Price
Outstanding-beginning
of year 620,850 $2.32
Granted 588,850 6.43
Exercised (287,350) 5.46
Returned - -
Repriced 289,850 5.97
Returned for repricing (289,850) 6.85
Outstanding-end
of year 922,350 $3.85
Exercisable at
end of year 892,350 $3.79
Exercise prices for options outstanding under the plan as of
June 30, 1997 ranged from $1.25 to $9.75 per share. The
weighted-average remaining contractual life of those options
is 7.9 years. A summary of the outstanding and exercisable
options at June 30, 1997, segregated by exercise price
ranges, is as follows:
Weighted-
Average
Weighted- Remaining
Exercise Average Contractual
Price Options Exercise Life
Range Outstanding Price (in years)
$1.25 - $3.25 1,110,077 $2.75 7.8
$6.00 - $9.75 150,000 6.96 9.2
1,260,077 3.25 7.9
Weighted-
Exercise Average
Price Exercisable Exercise
Range Options Price
$1.25 - $3.25 1,060,077 $2.73
$6.00 - $9.75 125,000 7.15
1,185,000 $3.20
Proforma information regarding net income and earnings per
share is required by Statement of Financial Accounting
Standards 123, which also requires that the information be
determined as if the Company has accounted for its employee
stock options granted subsequent to June 30, 1995 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, 1997 and
1996, respectively, risk-free interest rate of 6.5% and 5.8%,
dividend yields of 0% and 0%, volatility factors of the
expected market price of the Company's common stock of 43.72%
and 46.00%, and a weighted-average expected life of the
options of 6.87 and 6.35 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, 1997 and 1996, would have been $4,191,673 and
$4,848,092, and loss per common share would have been $0.83
and $1.18 per share, respectively.
During the fiscal 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.
On July 25, 1995, the Company's Incentive Plan Committee
granted to each of the two officers options to purchase 7,000
shares of common stock at $2.50 per share under the Company's
Incentive Plan. The Options are immediately exercisable and
expire July 25, 2005. Also on July 25, 1995, each officer
surrendered to the Company 7,000 Class D warrants to purchase
stock at $2.50 per share owned by them. Stock option expense
of $43,750 has been recorded for the year ended June 30, 1996
based on the difference between the option price and the
quoted market price on the date of grant for the options
granted.
In July, 1995, the Company's Incentive Plan Committee granted
1,500 options at $1.25 to an employee of the Company. Stock
option expense of $7,125 has been recorded for the year ended
June 30, 1996 based on the difference between the option price
and the quoted market price on the date of grant for the
options granted. The options were exercised during the year
ended June 30, 1996.
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, 1997:
Number Exercise Expiration
Outstanding Price Date
7,000 $ 1.250 8/08/95 (1)
20,000 3.500 6/09/03
150,000 5.000 6/28/98
100,000 5.500 8/03/97
50,000 6.000 - (2)
50,000 6.000 9/01/97 (3)
62,500 6.125 11/06/00
100,000 8.000 8/31/99
100,000 8.500 8/03/98
(1) On August 7, 1995, the Company extended the
expiration date to thirty days after registration of the
underlying shares. The options are held by a director and
unrelated consultant. Stock option expense of $29,750 has
been recorded for the year ended June 30, 1996 based on the
difference between the option price and the quoted market price
on the date of the options were extended.
(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.
On August 7, 1995, the Company extended the expiration date of
certain options to thirty days after registration of the
underlying shares. The options were held by an unrelated
consultant. Stock option expense of $212,500 has been
recorded for the year ended June 30, 1996 based on the
difference between the option price and the quoted market
price on the date of the options were extended. During fiscal
1997, these options were exercised.
During fiscal 1996, the Company entered into employment
agreements with an employee to assist the Company in
assembling and disseminating public information about the
Company for a period through January 1997. Under the terms of
the agreements, the Company issued 47,500 shares of common
stock for the above mentioned services. The shares were
placed in escrow and were released ratably as services were
rendered. The fair value of the common stock issued of
$287,608 was estimated based on the quoted market price of the
common stock at the time it was issued and was charged to
unamortized consulting expense. Unamortized consulting
expense was recorded as a component of stockholders equity
and was amortized ratably as services were performed in 1996
and 1997.
During 1996, the Company entered into consulting agreements
with unrelated companies to provide investor and broker
services. The fair value of the common stock issued in
connection with the agreement of $368,750 was estimated based
on the quoted market price of the common stock at the time it
was issued and was charged to unamortized consulting expense.
Unamortized consulting expense was recorded as a component of
stockholders equity and amortized ratably over the period
services were provided during 1996.
(5) Employee Benefits
During 1997 the Company began sponsoring a qualified tax
deferred savings plan in the form of a Savings Incentive Match
Plan for Employees ("SIMPLE") IRA plan (the "Plan") available
to companies with fewer than 100 employees. Under the Plan,
the Company's employees may make annual salary reduction
contributions of up to 3% of an employee's base salary up to
a maximum of $6,000 (adjusted for inflation) on a pre-tax
basis. The Company will make matching contributions on behalf
of employees who meet certain eligibility requirements.
During the fiscal year ended June 30, 1997 the Company
contributed $4,491 under the Plan.
(6) Income Taxes
At June 30, 1997 and 1996, the Company s significant deferred
tax assets and liabilities are summarized as follows:
1997 1996
Deferred tax assets:
Net operating loss
carryforwards $7,168,000 6,655,000
Allowance for doubtful
accounts not deductible
for tax purposes 19,000 19,000
Oil and gas properties,
principally due to
differences in basis and
depreciation and depletion 1,685,000 1,777,000
Gross deferred tax assets 8,872,000 8,451,000
Less valuation allowance (8,872,000) (8,451,000)
Net deferred tax asset $ - -
No income tax benefit has been recorded for the years
ended June 30, 1997 and 1996 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, 1997, the Company had net operating loss
carryforwards for regular and alternative minimum tax purposes
of approximately $18,900,000 and $17,500,000, respectively.
If not utilized, the tax net operating loss carryforwards will
expire during the period from 1998 through 2012. Net
operating loss carryforwards attributable to Amber prior to
1993 which are included in the above amounts of approximately
$4,100,000 are available only to offset future taxable income
of Amber and are further limited to approximately $430,000 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 from Affiliates
At June 30, 1997, the Company had $119,419 of receivables
from affiliates of an officer of the Company primarily for
production taxes and other expenses on wells owned by the
affiliates 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. Subsequent to year
end, the Company agreed to extend the term of the consulting
agreement for an additional year.
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 1997 and $250,000 in 1996 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,
1997, the Company has paid a total of $850,000 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.
On September 5, 1995, the Company acquired certain leases in
Jackson County, Colorado from Sunnyside Production Company,
LLC ("Sunnyside"), a company in which Ogle is a stockholder,
for 26,627 shares of the Company's common stock. This
transaction was recorded at Sunnyside's predecessor cost for
the portion attributable to Ogle's interest.
(8) Commitments
The Company rents an office in Denver under an operating
lease which expires in March 2002. Rent expense, net of
sublease rental income, for the years ended June 30, 1997
and 1996 was approximately $44,000 and $69,000,
respectively. Future minimum payments under noncancelable
operating leases are as follows:
1998 $105,642
1999 112,182
2000 97,385
2001 92,444
2002 62,766
(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,
1997 1996
Undeveloped offshore
California properties $6,959,830 6,786,580
Undeveloped onshore
domestic properties 714,605 971,648
Developed onshore domestic
properties 3,383,523 2,919,451
11,057,958 10,677,679
Accumulated depreciation
and depletion (1,990,954) (1,724,140)
$9,067,004 8,953,539
Cost incurred in oil and gas producing activities for
the years ended June 30,1997 and 1996 are as follows:
1997 1996
Unproved property
acquisition costs $505,457 472,849
Proved property
acquisition costs 182,559 16,875
Development costs 567,492 198,814
Exploration costs 607,431 110,963
$1,862,939 799,501
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, 1997 and 1996 were:
1997 1996
A 42% 27%
B 14% 34%
C 13% -
D 7% 17%
(10) Information Regarding Proved Oil and Gas Reserves
(Unaudited)
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.
Proved developed oil and gas reserves are those expected to be
recovered through existing wells with existing equipment and
operating methods. The determination of oil and gas reserves
is highly complex and interpretive. The estimates are subject
to continuing changes as additional information becomes
available.
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.
A summary of changes in estimated quantities of proved reserves, net of
recoupment gas, for the years ended June 30, 1997
and 1996 are as follows:
<TABLE>
<CAPTION>
Onshore Offshore
GAS OIL GAS OIL
(MCF) (BBLS) (MCF) (BBLS)
<S> <C> <C> <C> <C>
Balance at July 1, 1996 4,162,885 120,816 62,073,644 57,044,952
Purchases of reserves in place 1,320,058 25,273 - -
Extension and discoveries 64,727 - - -
Revisions of quantity estimates 255,700 12,381 366,607 943,768
Sales of properties (33,131) (3,565) - -
Production (499,294) (10,713) - -
Balance at June 30, 1996 5,270,945 144,192 62,440,251 57,988,720
Purchases of reserves in place 659,515 - 3,140,745 2,616,072
Redetermination of working interest - - 9,288,371 8,359,569
Extension and discoveries 141,127 1,473 - -
Revisions of quantity estimates 1,338,004 50,982 2,809,079 3,363,139
Sales of properties (1,348,132) (26,080) - -
Production (644,256) (7,755) - -
Balance at June 30, 1997 5,417,203 162,812 77,678,446 72,327,500
Proved developed reserves:
June 30, 1995 2,550,626 43,125 - -
June 30, 1996 3,146,357 47,021 - -
June 30, 1997 3,419,077 34,176 - -
</TABLE>
Future net cash flows presented below are computed using year-end prices
and costs. Future corporate overhead expenses and interest expense have
not been included.
<TABLE>
<CAPTION>
Offshore
Onshore California Total
June 30, 1996:
<S> <C> <C> <C>
Future cash inflows $10,384,701 779,833,105 790,217,806
Future costs:
Production 4,071,196 203,812,088 207,883,284
Development 1,250,413 166,640,928 167,891,341
Income taxes - 134,309,964 134,309,964
Future net cash flows 5,063,092 275,070,125 280,133,217
10% discount factor 1,819,295 216,969,625 218,788,920
Standardized measure of discounted future
net cash flows $3,243,797 58,100,500 61,344,297
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
</TABLE>
The principal sources of changes in the standardized measure of discounted
net cash flows during the years ended June 30, 1997 and 1996 are as follows:
<TABLE>
<CAPTION>
1997 1996
<S> <C> <C>
Beginning of year $61,344,297 45,419,695
Sales of oil and gas produced during the
period, net of production costs (966,883) (605,068)
Net change in prices and production costs (15,964,408) (1,562,145)
Changes in estimated future development costs (1,304,543) (731,662)
Purchase of reserves in place 2,762,518 701,476
Redetermination of working interest 7,929,906 -
Extensions, discoveries and improved recovery 122,389 77,312
Revisions of previous quantity estimates,
estimated timing of development and other (8,530,750) 22,988,710
Net change in income taxes (2,426,782) (9,422,283)
Sales of reserves in place (694,654) (63,708)
Accretion of discount 6,134,430 4,541,970
End of year $48,405,520 61,344,297
</TABLE>
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 Standard 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> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> JUN-30-1997
<PERIOD-END> JUN-30-1997
<CASH> 393,048
<SECURITIES> 0
<RECEIVABLES> 333,535
<ALLOWANCES> 50,000
<INVENTORY> 0
<CURRENT-ASSETS> 736,683
<PP&E> 11,138,404
<DEPRECIATION> 2,059,461
<TOTAL-ASSETS> 10,438,373
<CURRENT-LIABILITIES> 1,267,505
<BONDS> 0
0
0
<COMMON> 52,306
<OTHER-SE> 9,118,562
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</TABLE>
