UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
[X] ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 For the fiscal year ended June 30, 2002.
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 For the transition period from .
Commission File No. 0-16203
DELTA PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Colorado 84-1060803
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
475 17th Street, Suite 1400
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-K or any
amendment to this Form 10-K. [X]
The aggregate market value as of September 18, 2002 of voting stock held by
non-affiliates of the registrant was $45,562,000.
As of September 18, 2002, 22,659,000 shares of registrant's Common Stock $.01
par value were issued and outstanding.
Documents incorporated by reference: The information required by Part III of
this Form 10-K is incorporated by reference to the Company's Definitive Proxy
Statement for the Company's 2002 Annual Meeting of Shareholders.
TABLE OF CONTENTS
PART I
PAGE
ITEM 1. DESCRIPTION OF BUSINESS ....................................
ITEM 2. DESCRIPTION OF PROPERTY ....................................
ITEM 3. LEGAL PROCEEDINGS ..........................................
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ........
ITEM 4A. DIRECTORS AND EXECUTIVE OFFICERS ...........................
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS ...
ITEM 6. SELECTED FINANCIAL DATA ....................................
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION ..
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK..
ITEM 8. FINANCIAL STATEMENTS .......................................
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE .....................
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT ..........
ITEM 11. EXECUTIVE COMPENSATION .....................................
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT .............................................
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS .............
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENTS AND REPORTS ON FORM 8-K .....
The terms "Delta," "Company," "we," "our," and "us" refer to Delta
Petroleum Corporation and its subsidiaries unless the context suggests
otherwise.
1
CAUTIONARY STATEMENT FOR PURPOSES OF THE PRIVATE SECURITIES LITIGATION REFORM
ACT OF 1995 AND OTHER FEDERAL SECURITIES LAWS
GENERAL. We are including the following discussion to inform our existing
and potential security holders generally of some of the risks and
uncertainties that can affect us and to take advantage of the "safe harbor"
protection for forward-looking statements afforded under federal securities
laws. From time to time, our management or persons acting on our behalf make
forward-looking statements to inform existing and potential security holders
about us. These statements may include projections and estimates concerning
the timing and success of specific projects and our future (1) income, (2) oil
and gas production, (3) oil and gas reserves and reserve replacement and (4)
capital spending. Forward-looking statements are generally accompanied by
words such as "estimate," "project," "predict," "believe," "expect,"
"anticipate," "plan," "goal" or other words that convey the uncertainty of
future events or outcomes. Sometimes we will specifically describe a
statement as being a forward-looking statement. In addition, except for the
historical information contained in this report, the matters discussed in this
report are forward-looking statements. These statements by their nature are
subject to certain risks, uncertainties and assumptions and will be influenced
by various factors. Should any of the assumptions underlying a forward-
looking statement prove incorrect, actual results could vary materially.
We believe the factors discussed below are important factors that could
cause actual results to differ materially from those expressed in a forward-
looking statement made herein or elsewhere by us or on our behalf. The factors
listed below are not necessarily all of the important factors. Unpredictable
or unknown factors not discussed herein could also have material adverse
effects on actual results of matters that are the subject of forward-looking
statements. We do not intend to update our description of important factors
each time a potential important factor arises. We advise our shareholders
that they should (1) be aware that important factors not described below could
affect the accuracy of our forward-looking statements and (2) use caution and
common sense when analyzing our forward-looking statements in this document or
elsewhere, and all of such forward-looking statements are qualified by this
cautionary statement.
- Historically, natural gas and crude oil prices have been volatile.
These prices rise and fall based on changes in market demand and
changes in the political, regulatory and economic climate and
other factors that affect commodities markets generally and are
outside of our control.
- Projecting future rates of oil and gas production is inherently
imprecise. Producing oil and gas reservoirs generally have
declining production rates.
- All of our reserve information is based on estimates. Reservoir
engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in
an exact way. There are numerous uncertainties inherent in
estimating quantities of proved natural gas and oil reserves.
2
- Changes in the legal, political and/or regulatory environment
could have a material adverse effect on our future results of
operations and financial condition. Our ability to economically
produce and sell our oil and gas production is affected and could
possibly be restrained by a number of legal, political and
regulatory factors, particularly with respect to our offshore
California properties which are the subject of significant
political controversy due to environmental concerns.
- Our drilling operations are subject to various risks common in
the industry, including cratering, explosions, fires and
uncontrollable flows of oil, gas or well fluids.
3
PART I
ITEM 1. DESCRIPTION OF BUSINESS
(a) Business Development.
Delta Petroleum Corporation ("Delta," "we," "us") is a Colorado
corporation organized on December 21, 1984. We maintain our principal
executive offices at Suite 1400, 475 Seventeenth Street, Denver, Colorado
80202, and our telephone number is (303) 293-9133. Our common stock is listed
on NASDAQ under the symbol DPTR.
We are engaged in the acquisition, exploration, development and
production of oil and gas properties. As of June 30, 2002, we had varying
interests in approximately 466 gross (215 net) productive wells located in
fifteen (15) states and offshore California. These do not include varying
small interests in approximately 700 gross (4.6 net) wells located primarily
in Texas which are owned by our subsidiary Piper Petroleum Company. We also
had interests in five federal units and one lease offshore California near
Santa Barbara along with a financial interest in a nearby producing offshore
federal unit (see Item 2 "Description of Property"). We operated
approximately 270 of the wells and the remaining wells were operated by
independent operators. We believe all of these wells are operated under
contracts that are standard in the industry. At June 30, 2002, we estimated
onshore proved reserves to be approximately 3,919,000 Bbls of oil and 43.95
Bcf of gas, of which approximately 1,651,000 Bbls of oil and 25.1 Bcf of gas
were proved developed reserves. At June 30, 2002, we estimated offshore
proved reserves to be approximately 902,000 Bbls of oil, of which
approximately 849,000 Bbls were proved developed reserves. (See "Description
of Property, Item 2 herein.)
We have an authorized capital of 3,000,000 shares of $.10 par value
preferred stock, of which no shares were issued, and 300,000,000 shares of
$.01 par value common stock, of which 22,618,000 shares were issued and
outstanding as of June 30, 2002. We have outstanding warrants and options to
non-employees to purchase 1,854,000 shares of common stock at prices ranging
from $2.50 per share to $6.00 per share at September 10, 2002. Additionally,
as of June 30, 2002 we had outstanding options which were granted to our
officers, employees and directors under our incentive plans, to purchase up to
3,503,487 shares of common stock at prices ranging from $0.05 to $9.75 per
share at June 30, 2002.
At June 30, 2002, we owned 4,277,977 shares of common stock of Amber
Resources Company ("Amber"), representing 91.68% of the outstanding common
stock of Amber. Amber is a public company (registered under the Securities
Exchange Act of 1934) whose activities include oil and gas exploration,
development, and production operations. Until July 1, 2001, Amber owned
interests in a portion of our producing oil and gas properties in Oklahoma.
At June 30, 2002, Amber still owned a portion of the interest referenced above
in our non-producing oil and gas properties offshore California near Santa
Barbara. The Company and Amber entered into an agreement effective October 1,
1998 which provides, in part, for the sharing of the management between the
two companies and allocation of expenses related thereto.
4
On May 31, 2002, Delta acquired all of the domestic oil and gas
properties of Castle Energy Corporation ("Castle"). The properties acquired
from Castle consist of interests in approximately 525 producing wells located
in fourteen (14) states, plus associated undeveloped acreage. Delta issued
9,566,000 shares of Common Stock to Castle as part of the purchase price.
Although all of these shares have been registered for sale, none has yet been
sold. Delta is entitled to repurchase up to 3,188,667 of its shares from
Castle for $4.50 per share for a period of one year after closing. Delta's
agreement with Castle was effective as of October 1, 2001 and the net
operating revenues from the properties between the effective date and the May
31, 2002 closing date were recorded as an adjustment to the purchase price.
Also on May 31, 2002 Delta obtained a new $20 million credit
facility with the Bank of Oklahoma and Local Oklahoma Bank, part of which was
used to pay the remainder of the Castle purchase price. Approximately $19
million of the credit facility was utilized to close the Castle transaction
and to pay off our existing loan with US Bank. Our total debt now approximates
$25 million. A substantial portion of oil and gas properties is pledged as
collateral for our new loan and the terms of the Credit Agreement limit our
flexibility to engage in many types of business activities without obtaining
the consent of our lenders in advance. As a part of the acquisition, upon
closing, Delta granted an option to acquire a 4% working interest in the
properties acquired for a cost of $878,000 to BWAB Limited Liability Company
("BWAB"), a less than 10% shareholder of Delta. The difference between the
$878,000 paid by BWAB which is less than fair value, and 4% of the cost of the
Castle properties was treated as an additional acquisition cost by Delta for
its consultation and assistance related to the transaction.
On March 1, 2002 we completed the sale of 21 producing wells and
acreage located primarily in the Eland and Stadium fields of Stark County,
North Dakota, to Sovereign Holdings, LLC, a privately-held Colorado limited
liability company, for cash consideration of $2,750,000 pursuant to a purchase
and sale agreement dated February 1, 2002 and effective January 1, 2002. As a
result of the sale, we recorded a loss on sale of oil and gas properties of
$1,000. These properties accounted for approximately 9.45% of our total
assets as of June 30, 2001 and also accounted for approximately 22.6% of our
total revenues and approximately 11.9% of our total operating expenses during
our past fiscal year. Approximately $1,300,000 of the proceeds from the sale
were used to pay existing debt. On May 24, 2002 we completed the sale of our
undivided interests in an Authority to Prospect (ATP) covering lands in
Queensland, Australia, to Tipperary Corporation, in exchange for Tipperary's
producing properties in the West Buna Field (Hardin and Jasper counties,
Texas),$700,000 in cash, and 250,000 unregistered shares of Tipperary common
stock. Net daily production from the West Buna Field approximates 900,000
cubic feet of natural gas equivalent.
On March 1, 2002, we sold the properties acquired on November 15,
2001, to Whiting Petroleum Corporation for $648,000. As a result of the sale,
we recorded a loss on sale of oil and gas properties of $106,000. Proceeds
from the sale were used to pay existing debt.
On February 19, 2002, we completed the acquisition of Piper
Petroleum Company ("Piper"), a privately owned oil and gas company
headquartered in Fort Worth, Texas. We issued 1,377,240 shares of our
restricted common stock for 100% of the shares of Piper. The 1,377,240 shares
5
of restricted common stock were valued at approximately $5,234,000 based on
the five-day average market closing price of Delta's common stock surrounding
the announcement of the merger. In addition, we issued 51,000 shares for the
cancellation of certain debt of Piper. As a result of the acquisition, we
acquired Piper's working and royalty interests in over 700 gross (4.6 net)
wells which are primarily located in Texas, Oklahoma and Louisiana along with
a 5% working interest in the Comet Ridge coal bed methane gas project in
Queensland, Australia. On May 24, 2002 we completed the sale of our undivided
interests in Australia, to Tipperary Corporation, in exchange for Tipperary's
producing properties in the West Buna Field (Hardin and Jasper counties,
Texas)which had a fair market value of approximately $4,100,000, $700,000 in
cash, and 250,000 unregistered shares of Tipperary common stock. No gain or
loss was recorded on this transaction. Net daily production from the West
Buna Field approximates 900,000 cubic feet equivalent. In addition, on May
28, 2002, we sold a commercial office building obtained in the merger with
Piper located in Fort Worth, Texas to a non-affiliate for its fair value of
$417,000. No gain or loss was recorded on this transaction. Piper was merged
into a subsidiary wholly owned by Delta and the subsidiary was then renamed
"Piper Petroleum Company".
On November 15, 2001, we acquired producing oil and gas interests in
Texas from three unrelated parties. The acquisition had a purchase price of
approximately $788,000 consisting of $413,000 in cash and 137,000 shares of
our restricted common stock with a fair value of $375,000 based on the market
closing price of Delta's common stock on the date of closing.
On July 1, 2001, we purchased all the producing properties of Amber,
our 91.68% owned subsidiary, for $107,000. The purchase price was based on an
evaluation performed by an unrelated engineering firm. The effects of this
transaction are eliminated in the consolidated financial statements.
(b) Business of Issuer.
During the year ended June 30, 2002, we were engaged in only one
industry, namely the acquisition, exploration, development, and production of
oil and gas properties and related business activities. Our oil and gas
operations have been comprised primarily of production of oil and gas,
drilling exploratory and development wells and related operations and
acquiring and selling oil and gas properties. Directly or through wholly owned
subsidiaries and through Amber, we currently own producing and non-producing
oil and gas interests, undeveloped leasehold interests and related assets in
fifteen (15) states; interests in a producing Federal unit offshore California
and undeveloped offshore Federal leases near Santa Barbara, California. We
intend to continue our emphasis on the drilling of exploratory and development
wells primarily in New Mexico, Texas, Alabama, and offshore California.
We intend to drill on some of our leases (presently owned or
subsequently acquired); may farm out or sell all or part of some of the leases
to others; and/or we 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.
6
(1) Principal Products or Services and Their Markets. The principal
products produced by us are crude oil and natural gas. The products are
generally sold at the wellhead to purchasers in the immediate area where the
product is produced. The principal markets for oil and gas are refineries and
transmission companies which have facilities near our producing properties.
(2) Distribution Methods of the Products or Services. Oil and
natural gas produced from our wells are normally sold to purchasers as
referenced in (6) below. Oil is picked up and transported by the purchaser
from the wellhead. In some instances we are charged a fee for the cost of
transporting the oil, which fee is deducted from or accounted for in the price
paid for the oil. Natural gas wells are connected to pipelines generally
owned by the natural gas purchasers. A variety of pipeline transportation
charges are usually included in the calculation of the price paid for the
natural gas.
(3) Status of Any Publicly Announced New Product or Service. We
have not made a public announcement of, and no information has otherwise
become public about, a new product or industry segment requiring the
investment of a material amount of our total assets.
(4) Competitive Business Conditions. Oil and gas exploration and
acquisition of undeveloped properties is a highly competitive and speculative
business. We compete with a number of other companies, including major oil
companies and other independent operators which are more experienced and which
have greater financial resources. We do not hold a significant competitive
position in the oil and gas industry.
(5) Sources and Availability of Raw Materials and Names of
Principal Suppliers. Oil and gas may be considered raw materials essential to
our business. The acquisition, exploration, development, production, and sale
of oil and gas are subject to many factors which are outside of our control.
These factors include national and international economic conditions,
availability of drilling rigs, casing, pipe, and other equipment and supplies,
proximity to pipelines, the supply and price of other fuels, and the
regulation of prices, production, transportation, and marketing by the
Department of Energy and other federal and state governmental authorities.
(6) Dependence on One or a Few Major Customers. During our fiscal
year ended June 30, 2002, we sold our oil and gas production to the following
companies: Dynegy, Texla, Cinergy, Gulfmark, BP and Plains Marketing. We do
not depend upon one or a few major customers for the sale of oil and gas as of
the date of this report. The loss of any one or several customers would not
have a material adverse effect on our business.
(7) Patents, Trademarks, Licenses, Franchises, Concessions, Royalty
Agreements or Labor Contracts. We do not own any patents, trademarks,
licenses, franchises, concessions, or royalty agreements except oil and gas
interests acquired from industry participants, private landowners and state
and federal governments. We are not a party to any labor contracts.
(8) Need for Any Governmental Approval of Principal Products or
Services. Except that we must obtain certain permits and other approvals from
various governmental agencies prior to drilling wells and producing oil and/or
7
natural gas, we do not need to obtain governmental approval of our principal
products or services.
(9) Government Regulation of the Oil and Gas Industry.
General.
-------
Our business is affected by numerous governmental laws and
regulations, including energy, environmental, conservation, tax and other laws
and regulations relating to the energy industry. Changes in any of these laws
and regulations could have a material adverse effect on our business. In view
of the many uncertainties with respect to current and future laws and
regulations, including their applicability to us, we cannot predict the
overall effect of such laws and regulations on our future operations.
We believe that our operations comply in all material respects with
all applicable laws and regulations and that the existence and enforcement of
such laws and regulations have no more restrictive effect on our method of
operations than on other similar companies in the energy industry.
The following discussion contains summaries of certain laws and
regulations and is qualified in its entirety by the foregoing.
Environmental Regulation.
------------------------
Together with other companies in the industries in which we operate,
our operations are subject to numerous federal, state, and local environmental
laws and regulations concerning our oil and gas operations, products and other
activities. In particular, these laws and regulations require the acquisition
of permits, restrict the type, quantities, and concentration of various
substances that can be released into the environment, limit or prohibit
activities on certain lands lying within wilderness, wetlands and other
protected areas, regulate the generation, handling, storage, transportation,
disposal and treatment of waste materials and impose criminal or civil
liabilities for pollution resulting from oil, natural gas and petrochemical
operations.
Governmental approvals and permits are currently, and may in the
future be, required in connection with our operations. The duration and
success of obtaining such approvals are contingent upon a significant number
of variables, many of which are not within our control. To the extent such
approvals are required and not obtained, operations may be delayed or
curtailed, or we may be prohibited from proceeding with planned exploration or
operation of facilities.
Environmental laws and regulations are expected to have an
increasing impact on our operations, although it is impossible to predict
accurately the effect of future developments in such laws and regulations on
our future earnings and operations. Some risk of environmental costs and
liabilities is inherent in our operations and products, as it is with other
companies engaged in similar businesses, and there can be no assurance that
material costs and liabilities will not be incurred. However, we do not
currently expect any material adverse effect upon our results of operations or
financial position as a result of compliance with such laws and regulations.
Although future environmental obligations are not expected to have a
material adverse effect on our results of operations or financial condition,
there can be no assurance that future developments, such as increasingly
stringent environmental laws or enforcement thereof, will not cause us to
incur substantial environmental liabilities or costs.
Hazardous Substances and Waste Disposal.
---------------------------------------
We currently own or lease interests in numerous properties that have
been used for many years for natural gas and crude oil production. Although
the operator of such properties may have utilized operating and disposal
practices that were standard in the industry at the time, hydrocarbons or
other wastes may have been disposed of or released on or under the properties
owned or leased by us. In addition, some of these properties have been
operated by third parties over whom we had no control. The U.S. Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA") and
comparable state statutes impose strict, joint and several liability on owners
and operators of sites and on persons who disposed of or arranged for the
disposal of "hazardous substances" found at such sites. The Resource
Conservation and Recovery Act ("RCRA") and comparable state statutes govern
the management and disposal of wastes. Although CERCLA currently excludes
petroleum from cleanup liability, many state laws affecting our operations
impose clean-up liability regarding petroleum and petroleum related products.
In addition, although RCRA currently classifies certain exploration
and production wastes as "non-hazardous," such wastes could be reclassified as
hazardous wastes thereby making such wastes subject to more stringent handling
and disposal requirements. If such a change in legislation were to be
enacted, it could have a significant impact on our operating costs, as well as
the gas and oil industry in general.
Oil Spills.
----------
Under the Federal Oil Pollution Act of 1990, as amended ("OPA"), (i)
owners and operators of onshore facilities and pipelines, (ii) lessees or
permittees of an area in which an offshore facility is located and (iii)
owners and operators of tank vessels ("Responsible Parties") are strictly
liable on a joint and several basis for removal costs and damages that result
from a discharge of oil into the navigable waters of the United States. These
damages include, for example, natural resource damages, real and personal
property damages and economic losses. OPA limits the strict liability of
Responsible Parties for removal costs and damages that result from a discharge
of oil to $350 million in the case of onshore facilities, $75 million plus
removal costs in the case of offshore facilities, and in the case of tank
vessels, an amount based on gross tonnage of the vessel. However, these limits
do not apply if the discharge was caused by gross negligence or willful
misconduct, or by the violation of an applicable Federal safety, construction
or operating regulation by the Responsible Party, its agent or subcontractor
or in certain other circumstances.
9
In addition, with respect to certain offshore facilities, OPA
requires evidence of financial responsibility in an amount of up to $150
million. Tank vessels must provide such evidence in an amount based on the
gross tonnage of the vessel. Failure to comply with these requirements or
failure to cooperate during a spill event may subject a Responsible Party to
civil or criminal enforcement actions and penalties.
Under our various agreements, we have primary liability for oil
spills that occur on properties for which we act as operator. With respect to
properties for which we do not act as operator, we are generally liable for
oil spills as a non-operating working interest owner. We do not act as
operator for any of our offshore California properties. The operators of our
offshore California properties are primarily liable for oil spills and are
required by the Minerals Management Service of the United States Department of
the Interior ("MMS") to carry certain types of insurance and to post bonds in
that regard. In addition, we also carry insurance as a non-operator in the
amount of $5 million onshore and $10 million offshore. There is no assurance
that our insurance coverage is adequate to protect us.
Offshore Production.
-------------------
Offshore oil and gas operations in U.S. waters are subject to
regulations of the United States Department of the Interior which currently
impose strict liability upon the lessee under a Federal lease for the cost of
clean-up of pollution resulting from the lessee's operations, and such lessee
could be subject to possible liability for pollution damages. In the event of
a serious incident of pollution, the Department of the Interior may require a
lessee under Federal leases to suspend or cease operations in the affected
areas.
(10) Research and Development. We do not engage in any research
and development activities. Since our inception, we have not had any customer
or government-sponsored material research activities relating to the
development of any new products, services or techniques, or the improvement of
existing products.
(11) Environmental Protection. Because we are engaged in
acquiring, operating, exploring for and developing natural resources, we are
subject to various state and local provisions regarding environmental and
ecological matters. Therefore, compliance with environmental laws may
necessitate significant capital outlays, may materially affect our earnings
potential, and could cause material changes in our proposed business. At the
present time, however, these laws do not materially hinder nor adversely
affect our business. Capital expenditures relating to environmental control
facilities have not been material to our operation since our inception. In
addition, we do not anticipate that such expenditures will be material during
the fiscal year ending June 30, 2003.
(12) Employees. We have twenty-two full time employees.
Additionally, certain operators, engineers, geologists, geophysicists,
landmen, pumpers, draftsmen, title attorneys and others necessary for our
operations are retained on a contract or fee basis as their services are
required.
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ITEM 2. DESCRIPTION OF PROPERTY
(a) Office Facilities.
Our offices are located at 475 Seventeenth Street, Suite 1400,
Denver, Colorado 80202. We lease approximately 9,500 square feet of office
space for approximately $15,500 per month and the lease will expire in
September, 2008.
(b) Oil and Gas Properties.
We own interests in producing oil and gas properties located
primarily in fifteen (15) states plus off-shore Santa Barbara California.
Most wells from which we receive revenues are owned only partially by us. For
information concerning our oil and gas production, average prices and costs,
estimated oil and gas reserves and estimated future cash flows, see the tables
set forth below in this section and "Notes to Financial Statements" included
in this report. We did not file oil and gas reserve estimates with any federal
authority or agency other than the Securities and Exchange Commission during
the past two years.
Principal Properties.
--------------------
The following is a brief description of our principal properties:
Onshore:
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We own interests in approximately 464 gross (215 net) producing
wells in fifteen (15) states, not including interests in those wells owned by
our subsidiary, Piper Petroleum Company ("Piper"). Piper owns varying very
small interests in approximately 700 gross (4.6 net) wells located primarily
in Texas. Piper's wells produce approximately 30 bbls per day and 200 mcf per
day net to Piper's interests.
Our principal onshore producing properties are in the following
states:
Alabama
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We own and operate a 94.5% working interest in 50 coal bed
methane gas wells at depths of about 2,500 feet in Tuscaloosa County. These
wells produce approximately 1650 mcf per day net to our interests.
We also own a .6455% working interest in the Hatter's Pond Unit
in Mobil County which is operated by Four Star Oil and Gas. This unit
produces approximately 18 barrels per day and 207 mcf per day net to our
interest.
11
Texas
-----
We own interests in 149 gross (52.7 net) wells in Texas located
primarily in South Texas, East Texas and the Permian Basin with approximately
one third of the production coming from each area. We operate 42 of these
wells. These wells are scattered throughout 32 counties and are drilled to
various depths and reservoirs with varying working interests. In aggregate
these wells produce approximately 370 barrels of oil and 4,000 mcf of gas per
day.
This includes our interest in the West Buna field located in
Jasper and Hardin Counties which we recently acquired from Tipperary
Corporation. The West Buna field contains 20 wells producing approximately 53
barrels of oil and 418 mcf of gas per day. We own an average working interest
of approximately 8.5% plus additional royalty interests which give us an
average net revenue interest of approximately 12.4%. We do not operate any of
the West Buna Field wells.
Pennsylvania
------------
We own 143 wells with an average working interest of
approximately 75% in six counties in Pennsylvania. We operate 104 of these
wells. The wells are drilled to an average depth of 3,500 feet and produce
approximately 1058 mcf per day net to our interests.
Louisiana
---------
In Louisiana we own interests in 15 wells with an average
working interest of 56.4% located in Acadia, Catahoula, Plaquemines and Pointe
Coupee parishes. We produce primarily from the Wilcox formation at a depth of
10,000 to 11,000 feet. We operate 11 of these wells. Daily production is
approximately 225 barrels of oil per day net to our interests.
New Mexico
----------
We own interests in 32 wells in New Mexico, including our East
Carlsbad field in Eddy County where 10 of the wells are located. These wells
produce approximately 30 barrels of oil and 970 mcf of gas per day net to our
interests. We operate 9 of these wells.
Other States:
------------
We also own varying interests in producing wells in the following
states: California (Sacramento Basin), Colorado (D-J and Piceance Basins),
Oklahoma, Illinois, Mississippi, Michigan, Kansas, Montana, Wyoming and
Nebraska.
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Offshore:
--------
Offshore Federal Waters: Santa Barbara, California Area
-------------------------------------------------------
Unproved Undeveloped Properties:
-------------------------------
We own interests in five undeveloped federal units (plus one
additional lease) located in federal waters offshore California near Santa
Barbara.
The Santa Barbara Channel and the offshore Santa Maria Basin
are the seaward portions of geologically well-known onshore basins with over
90 years of production history. These offshore areas were first explored in
the Santa Barbara Channel along the near shore three mile strip controlled by
the state. New field discoveries in Pliocene and Miocene age reservoir sands
led to exploration into the federally controlled waters of the Pacific Outer
Continental Shelf ("POCS"). Although significant quantities of oil and gas
have been produced and sold from drilling conducted on POCS leases between
1966 and 1989, we do not own any interest in any offshore California
production except for our small interest in the Point Arguello Unit discussed
below, and there is no assurance that any of our undeveloped properties will
ever achieve production.
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 224 million Bbls of oil production and 411 Bcf of gas production.
All told, offshore fields producing from the Monterey as of the end of
calendar 2000 have produced 526 million Bbls of oil and 544 Bcf of gas.
California's active tectonic history over the last few million
years has formed the large linear anticlinal features which trap the oil and
gas. Marine seismic surveys have been used to locate and define these
structures offshore.
Recent seismic surveying utilizing modern 3-D seismic
technology, coupled with exploratory well data, has greatly improved knowledge
of the size of reserves in fields under development and in fields for which
development is planned. Currently, 11 fields are producing from 18 platforms
in the Santa Barbara Channel and offshore Santa Maria Basin. Implementation
of extended high-angle to horizontal drilling methods is reducing the number
of platforms and wells needed to develop reserves in the area. Use of these
new drilling methods and seismic technologies is expected to continue to
improve development economics.
Leasing, lease administration, development and production
within the Federal POCS all fall under the Code of Federal Regulations
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administered by the MMS. The EPA controls disposal of effluents, such as
drilling fluids and produced waters. Other Federal agencies, including the
Coast Guard and the Army Corps of Engineers, also have oversight of offshore
construction and operations.
The first three miles seaward of the coastline are administered
by each state and are known as "State Tidelands" in California. Within the
State Tidelands off Santa Barbara County, the State of California, through the
State Lands Commission, regulates oil and gas leases and the installation of
permanent and temporary producing facilities. Because the four units in which
we own interests are located in the POCS seaward of the three mile limit,
leasing, drilling, and development of these units are not directly regulated
by the State of California. However, to the extent that any production is
transported to an on-shore facility through the state waters, our pipelines
(or other transportation facilities) would be subject to California state
regulations. Construction and operation of any such pipelines would require
permits from the state. Additionally, all development plans must be
consistent with the Federal Coastal Zone Management Act ("CZMA"). In
California the decision of CZMA consistency is made by the California Coastal
Commission.
The Santa Barbara County Energy Division and the Board of
Supervisors will have a significant impact on the method and timing of any
offshore field development through its permitting and regulatory authority
over the construction and operation of on-shore facilities. In addition, the
Santa Barbara County Air Pollution Control District has authority in the
federal waters off Santa Barbara County through the Federal Clean Air Act as
amended in 1990.
Each working interest owner will be required to pay its
proportionate share of these costs based upon the amount of the interest that
it owns. The size of our working interest in the units, other than the Rocky
Point Unit, varies from 2.492% to 15.60%. We also own a working interest of
approximately 75% in the Rocky Point Unit. This interest is expected to be
reduced if the Rocky Point Unit is included in the Point Arguello Unit and
developed from existing Point Arguello platforms. We may be required to farm
out all or a portion of our interests in these properties to a third party if
we cannot fund our share of the development costs. There can be no assurance
that we can farm out our interests on acceptable terms.
These units have been formally approved and are regulated by
the MMS. While the Federal Government has recently attempted to expedite the
process of obtaining permits and authorizations necessary to develop the
properties, there can be no assurance that it will be successful in doing so.
We do not act as operator of any offshore California properties
and consequently will not generally control the timing of either the
development of the properties or the expenditures for development unless we
choose to unilaterally propose the drilling of wells under the relevant
operating agreements.
The MMS initiated the California Offshore Oil and Gas Energy
Resources (COOGER) Study at the request of the local regulatory agencies of
the three counties (Ventura, Santa Barbara and San Luis Obispo) affected by
offshore oil and gas development. A private consulting firm completed the
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study under a contract with the MMS. The COOGER Study presents a long-term
regional perspective of potential onshore constraints that should be
considered when developing existing undeveloped offshore leases. The COOGER
Study projects the economically recoverable oil and gas production from
offshore leases which have not yet been developed. These projections are
utilized to assist in identifying a potential range of scenarios for
developing these leases. These scenarios are compared to the projected
infrastructural, environmental and socioeconomic baselines between 1995 and
2015.
No specific decisions regarding levels of offshore oil and gas
development or individual projects will occur in connection with the COOGER
Study. Information presented in the study is intended to be utilized as a
reference document to provide the public, decision makers and industry with a
broad overview of cumulative industry activities and key issues associated
with a range of development scenarios. We have attempted to evaluate the
scenarios that were studied with respect to properties located in the eastern
and central subregions (which include the Sword Unit and the Gato Canyon Unit)
and the results of such evaluation are set forth below:
Scenario 1 - No new development of existing offshore leases. If
this scenario were ultimately to be adopted by governmental
decision makers as the proper course of action for development,
our offshore California properties would in all likelihood have
little or no value. In this scenario we would seek to cause the
Federal government to reimburse us for all money spent by us and
our predecessors for leasing and other costs and for the value of
the oil and gas reserves found on the leases through our
exploration activities and those of our predecessors.
Scenario 2 - Development of existing leases, using existing
onshore facilities as currently permitted, constructed and
operated (whichever is less) without additional capacity. This
scenario includes modifications to allow processing and
transportation of oil and natural gas with different qualities.
It is likely that the adoption of this scenario by the industry as
the proper course of action for development would result in lower
than anticipated costs, but would cause the subject properties to
be developed over a significantly extended period of time.
Scenario 3 - Development of existing leases, using existing
onshore facilities by constructing additional capacity at existing
sites to handle expanded production. This scenario is currently
anticipated by our management to be the most reasonable course of
action although there is no assurance that this scenario will be
adopted.
Scenario 4 - Development of existing leases after
decommissioning and removal of some or all existing onshore
facilities. This scenario includes new facilities, and perhaps
new sites, to handle anticipated future production. Under this
scenario we would incur increased costs but revenues would be
received more quickly.
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We have also evaluated our position with regard to the scenarios
with respect to properties located in the northern sub-region (which includes
the Lion Rock Unit and the Point Sal Unit), the results of which are as
follows:
Scenario 1 - No new development of existing offshore leases.
If this scenario were ultimately to be adopted by governmental
decision makers as the proper course of action for development,
our offshore California properties would in all likelihood have
little or no value. In this scenario we would seek to cause the
Federal government to reimburse us for all money spent by us and
our predecessors for leasing and other costs and for the value of
the oil and gas reserves found on the leases through our
exploration activities and those of our predecessors.
Scenario 2 - Development of existing leases, using existing
onshore facilities as currently permitted, constructed and
operated (whichever is less) without additional capacity. This
scenario includes modifications to allow processing and
transportation of oil and natural gas with different qualities.
It is likely that the adoption of this scenario by the industry
as the proper course of action for development would result in
lower than anticipated costs, but would cause the subject
properties to be developed over a significantly extended period
of time.
Scenario 3 - Development of existing leases, using existing
onshore facilities by constructing additional capacity at existing
sites to handle expanded production. This scenario is currently
anticipated by our management to be the most reasonable course of
action although there is no assurance that this scenario will be
adopted.
Scenario 4 - Development of existing offshore leases, using
existing onshore facilities with additional capacity or adding new
facilities to handle a relatively low rate of expanded
development. This scenario is similar to #3 above, but would
entail increased costs for any new facilities.
Scenario 5 - Development of existing offshore leases, using
existing onshore facilities with additional capacity or adding new
facilities to handle a relatively higher rate of expanded
development. Under this scenario we would incur increased costs
but revenues would be received more quickly.
The development plans for the various units (which have been
submitted to the MMS for review) currently provide for 22 wells from one
platform set in a water depth of approximately 300 feet for the Gato Canyon
Unit; 63 wells from one platform set in a water depth of approximately 1,100
feet for the Sword Unit; 60 wells from one platform set in a water depth of
approximately 336 feet for the Point Sal Unit; and 183 wells from two
platforms for the Lion Rock Unit.
On the Lion Rock Unit, Platform A would be set in a water depth of
approximately 507 feet, and Platform B would be set in a water depth of
approximately 484 feet. The reach of the deviated wells from each platform
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required to drain each unit falls within the reach limits now considered to be
"state-of-the-art." The development plans for the Rocky Point Unit provide
for the inclusion of the Rocky Point leases in the Point Arguello Unit upon
which the Rocky Point leases would be drilled from existing Point Arguello
platforms with extended reach drilling technology. The approximate distances
required to drain the Rocky Point leases range from 2,276 feet to 13,999 feet
at proposed total vertical depths ranging from 6,620 feet to 7,360 feet.
Current Status. On October 15, 1992 the MMS directed a Suspension
of Operations (SOO), effective January 1, 1993, for the POCS undeveloped
leases and units. The SOO was directed for the purpose of preparing what
became known as the COOGER Study. Two-thirds of the cost of the Study was
funded by the participating companies in lieu of the payment of rentals on the
leases. Additionally, all operations were suspended on the leases during this
period. On November 12, 1999, as the COOGER Study drew to a conclusion, the
MMS approved requests made by the operating companies for a Suspension of
Production (SOP) status for the POCS leases and units. During the period of
an SOP, the lease rentals resume and each operator is generally required to
perform exploration and development activities in order to meet certain
milestones set out by the MMS. The milestones that were established by the
MMS for the properties in which we own an interest were established through
negotiations by the MMS on behalf of the United States government and the
operators on behalf of the working interest owners. We did not directly
participate in these negotiations. Until recently, progress toward the
milestones was monitored by the operator in quarterly reports submitted to the
MMS. In February 2000 all operators completed and timely submitted to the MMS
a preliminary "Description of the Proposed Project". This was the first
milestone required under the SOP. Quarterly reports were also prepared and
submitted for all subsequent quarters.
On June 22, 2001, however, a Federal Court in the case of California
v. Norton, et al. (discussed below - see "Management's Discussion and Analysis
or Plan of Operation-Offshore Undeveloped Properties") ordered the MMS to set
aside its approval of the suspensions of our offshore leases and to direct
suspensions, including all milestone activities, for a time sufficient for the
MMS to provide the State of California with a consistency determination under
federal law. As a result of this order, on July 2, 2001 the MMS directed
suspensions of operations for all of our offshore California leases for an
indefinite period of time and suspended all of the related milestones. The
ultimate outcome and effects of this litigation are not certain at the present
time. In order to continue to carry out the requirements of the MMS, all
operators of the units in which we own non-operating interests are prepared to
meet the next milestone leading to development of the leases, but the status
of the milestones is presently uncertain in light of the Norton ruling. The
United States government has filed a notice of its intent to appeal the
court's order in the Norton case.
On January 9, 2002, we and several other plaintiffs filed a lawsuit
in the United States Court of Federal Claims in Washington, D.C. alleging that
the U.S. Government has materially breached the terms of forty undeveloped
federal leases, some of which are part of our Offshore California properties.
The Complaint is based on allegations by the collective plaintiffs that the
United States has materially breached the terms of certain of their Offshore
California leases by attempting to deviate significantly from the procedures
and standards that were in effect when the leases were entered into, and by
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failing to carry out its own obligations relating to those leases in a timely
and fair manner. More specifically, the plaintiffs have alleged that the
judicial determination in the California v. Norton case that a 1990 amendment
to the Coastal Zone Management Act required the Government to make a
consistency determination prior to granting lease suspension requests in 1999
constitutes a material change in the procedures and standards that were in
effect when the leases were issued. The plaintiffs have also alleged that the
United States has failed to afford them the timely and fair review of their
lease suspension requests which has resulted in significant, continuing and
material delays to their exploratory and development operations.
The forty undeveloped leases are located in the Offshore Santa Maria
Basin off the coast of Santa Barbara and San Luis Obispo counties, and in the
Santa Barbara Channel off Santa Barbara and Ventura counties. None of these
leases is currently impaired, but in the event that there is some future
adverse ruling by the California Coastal Commission under the Coastal Zone
Management Act and we decide not to appeal such ruling to the Secretary of
Commerce, or the Secretary of Commerce either refuses to hear our appeal of
any such ruling or ultimately makes a determination adverse to us, it is
likely that some or all of these leases would become impaired and written off
at that time.
In addition, it should be noted that our pending litigation against
the United States is predicated on the ruling of the lower court in California
v. Norton. The United States has appealed the decision of the lower court to
the 9th Circuit Court of Appeals. In the event that the United States is not
successful in its appeal(s) of the lower court's decision in the Norton case
and the pending litigation with us is not settled, it would be necessary for
us to reevaluate whether the leases should be considered impaired at that
time.
As the ruling in the Norton case currently stands, the United States
has been ordered to make a consistency determination under the Coastal Zone
Management Act, but the leases are still valid. If through the appellate
process the leases are found not to be valid for some reason, or if the United
States is finally ordered to make a consistency determination and either does
not do so or finds that development is inconsistent with the Coastal Zone
Management Act, it would appear that the leases would become impaired even
though we would undoubtedly proceed with our litigation. It is also possible
that other events could occur during the appellate process that would cause
the leases to become impaired, and we will continuously evaluate those factors
as they occur.
The suit seeks compensation for the lease bonuses and rentals paid
to the Federal Government, exploration costs and related expenses. The total
amount claimed by all lessees for bonuses and rentals exceeds $1.2 billion,
with additional amounts for exploration costs and related expenses. our claim
for lease bonuses and rentals paid by us and our predecessors is in excess of
$152,000,000. In addition, our claim for exploration costs and related
expenses will also be substantial.
On May 18, 2001 (prior to the Norton decision), a revised
Development and Production Plan for the Point Arguello Unit was submitted to
the MMS and the California Coastal Commission ("CCC") for approval. If
approved by the CCC, this plan would enable development of the Rocky Point
Unit from the Point Arguello platforms that are already in existence.
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Under law, the CCC is typically required to make a determination as
to whether or not the Plan is "consistent" with California's Coastal Plan
within three months of submission, with a maximum of three months' extension
(a total of six months). By correspondence dated August 7, 2001, however, the
Unit operator requested that the CCC suspend the consistency review for the
revised Development and Production Plan since the MMS had temporarily stopped
work on the processing of the plan as the result of the Norton decision.
Although it currently appears likely that the CCC may require some
additional supplemental information to be provided with respect to some
aspects of air and water quality when its review continues, we believe that
the Rocky Point Development and Production Plan that was submitted meets the
requirements established by applicable federal regulations. In accordance
with these regulations, the Plan includes very specific information regarding
the planned activities, including a description of and schedule for the
development and production activities to be performed, including plan
commencement date, date of first production, total time to complete all
development and production activities, and dates and sequences for drilling
wells and installing facilities and equipment, and a description of the
drilling vessels, platforms, pipelines and other facilities and operations
located offshore which are proposed or known by the lessee (whether or not
owned or operated by the lessee) to be directly related to the proposed
development, including the location, size, design, and important safety,
pollution prevention, and environmental monitoring features of the facilities
and operations. The current Development and Production Plan calls for
drilling activities to be conducted from the existing Point Arguello platforms
using extended reach drilling techniques with oil and gas production to be
transported through existing pipelines to existing onshore production
facilities. The plan does not require the construction of new platforms,
pipelines or production facilities.
In accordance with applicable federal regulations, the following
supporting information accompanies the Development and Production Plan: (1)
geological and geophysical data and information, including: (i) a plat showing
the surface location of any proposed fixed structure or well; (ii) a plat
showing the surface and bottomhole locations and giving the measured and true
vertical depths for each proposed well; (iii) current interpretations of
relevant geological and geophysical data; (iv) current structure maps showing
the surface and bottomhole location of each proposed well and the depths of
expected productive formations; (v) interpreted structure sections showing the
depths of expected productive formations; (vi) a bathymetric map showing
surface locations of fixed structures and wells or a table of water depths at
each proposed site; and (vii) a discussion of seafloor conditions including a
shallow hazards analysis for proposed drilling and platform sites and pipeline
routes.
As required by federal regulations, the information contained in the
Plan contains proposed precautionary measures, including a classification of
the lease area, a contingency plan, a description of the environmental
safeguards to be implemented, including an updated oil-spill response plan;
and a discussion of the steps that have been or will be taken to satisfy the
conditions of lease stipulations, a description of technology and reservoir
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engineering practices intended to increase the ultimate recovery of oil and
gas, i.e., secondary, tertiary, or other enhanced recovery practices; a
description of technology and recovery practices and procedures intended to
assure optimum recovery of oil and gas; a discussion of the proposed drilling
and completion programs; a detailed description of new or unusual technology
to be employed; and a brief description of the location, description, and size
of any offshore and land-based operations to be conducted or contracted for as
a result of the proposed activity; including the acreage required in
California for facilities, rights-of-way, and easements, the means proposed
for transportation of oil and gas to shore; the routes to be followed by each
mode of transportation; and the estimated quantities of oil and gas to be
moved along such routes; an estimate of the frequency of boat and aircraft
departures and arrivals, the onshore location of terminals, and the normal
routes for each mode of transportation.
As required, the Plan also provides a list of the proposed drilling
fluids, including components and their chemical compositions, information on
the projected amounts and rates of drilling fluid and cuttings discharges, and
methods of disposal, and specifies the quantities, types, and plans for
disposal of other solid and liquid wastes and pollutants likely to be
generated by offshore, onshore, and transport operations and, regarding any
wastes which may require onshore disposal, the means of transportation to be
used to bring the wastes to shore, disposal methods to be utilized, and the
location of onshore waste disposal or treatment facilities.
In order to comply with federal regulations, the Plan also addresses
the approximate number of people and families to be added to the population of
local nearshore areas as a result of the planned development, provides an
estimate of significant quantities of energy and resources to be used or
consumed including electricity, water, oil and gas, diesel fuel, aggregate, or
other supplies which may be purchased within California, and specifies the
types of contractors or vendors which will be needed, although not
specifically identified, and which may place a demand on local goods and
services.
The Plan also identifies the source, composition, frequency, and
duration of emissions of air pollutants and provides a narrative description
of the existing environment with an emphasis placed on those environmental
values that may be affected by the proposed action. This section of the Plan
contains a description of the physical environment of the area covered by the
Plan and includes data and information obtained or developed by the lessee
together with other pertinent information and data available to the lessee
from other sources. The environmental information and data includes a
description of the aquatic biota, including fishery and marine mammal use of
the lease, the significance of the lease and identifies the threatened and
endangered species and their critical habitat.
The Plan also addresses environmentally sensitive areas (e.g.,
refuges, preserves, sanctuaries, rookeries, calving grounds, coastal habitats,
beaches, and areas of particular environmental concern) which may be affected
by the proposed activities, the predevelopment, ambient water-column quality
and temperature data for incremental depths for the areas encompassed by the
plan, the physical oceanography, including ocean currents described as to
prevailing direction, seasonal variations, and variations at different water
depths in the lease, and describes historic weather patterns and other
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meteorological conditions, including storm frequency and magnitude, wave
height and direction, wind direction and velocity, air temperature,
visibility, freezing and icing conditions, and ambient air quality listing,
where possible, the means and extremes of each.
The Plan further identifies other uses of the area, including
military use for national security or defense, subsistence hunting and
fishing, commercial fishing, recreation, shipping, and other mineral
exploration or development and describes the existing and planned monitoring
systems that are measuring or will measure impacts of activities on the
environment in the planning area. As required, the Plan provides an
assessment of the effects on the environment expected to occur as a result of
implementation of the Plan, and identifies specific and cumulative impacts
that may occur both onshore and offshore, and describes the measures proposed
to mitigate these impacts. These impacts are quantified to the fullest extent
possible including magnitude and duration and are accumulated for all
activities for each of the major elements of the environment (e.g., water and
biota). The Plan also provides a discussion of alternatives to the activities
proposed that were considered during the development of the Plan, including a
comparison of the environmental effects.
As required, the Plan provides certain supporting information with
respect to the projected emissions from each proposed or modified facility for
each year of operation and the bases for all calculations, including, for each
source, the amount of the emission by air pollutant expressed in tons per year
and frequency and duration of emissions; for each proposed facility, the total
amount of emissions by air pollutant expressed in tons per year, the frequency
distribution of total emissions by air pollutant expressed in pounds per day
and, in addition for a modified facility only, the incremental amount of total
emissions by air pollutant resulting from the new or modified source(s); and a
detailed description of all processes, processing equipment and storage units,
including information on fuels to be burned; and a schematic drawing which
identifies the location and elevation of each source.
In order to continue to carry out the requirements of the MMS when
they resume, all operators of the units in which we own non-operating
interests are prepared to complete any studies and project planning necessary
to commence development of the leases. Where additional drilling is needed,
the operators will bring a mobile drilling unit to the POCS to further
delineate the undeveloped oil and gas fields.
Cost to Develop Offshore California Properties. The cost to develop
four of the five undeveloped units (plus one lease) located offshore
California, including delineation wells, environmental mitigation,
development wells, fixed platforms, fixed platform facilities, pipelines and
power cables, onshore facilities and platform removal over the life of the
properties (assumed to be 38 years), is estimated by the partners to be in
excess of $3 billion. Our share based on our current working interest of such
costs over the life of the properties is estimated to be over $200 million.
There will be additional costs of a currently undetermined amount to develop
the Rocky Point Unit which is the fifth undeveloped unit in which we own an
interest.
To the extent that we do not have sufficient cash available to pay
our share of expenses when they become payable under the respective operating
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agreements, it will be necessary for us to seek funding from outside sources.
Likely potential sources for such funding are currently anticipated to include
(a) public and private sales of our common stock (which may result in
substantial ownership dilution to existing shareholders), (b) bank debt from
one or more commercial oil and gas lenders, (c) the sale of debt instruments
to investors, (d) entering into farm-out arrangements with respect to one or
more of our interests in the properties whereby the recipient of the farm-out
would pay the full amount of our share of expenses and we would retain a
carried ownership interest (which would result in a substantial diminution of
our ownership interest in the farmed-out properties), (e) entering into one or
more joint venture relationships with industry partners, (f) entering into
financing relationships with one or more industry partners, and (g) the sale
of some or all of our interests in the properties.
It is unlikely that any one potential source of funding would be
utilized exclusively. Rather, it is more likely that we will pursue a
combination of different funding sources when the need arises. Regardless of
the type of financing techniques that are ultimately utilized, however, it
currently appears likely that because of our small size in relation to the
magnitude of the capital requirements that will be associated with the
development of the subject properties, we will be forced in the future to
issue significant amounts of additional shares, pay significant amounts of
interest on debt that presumably would be collateralized by all of our assets
(including our offshore California properties), reduce our ownership interest
in the properties through sales of interests in the properties or as the
result of farmouts, industry financing arrangements or other partnership or
joint venture relationships, or to enter into various transactions which will
result in some combination of the foregoing. In the event that we are not
able to pay our share of expenses as a working interest owner as required by
the respective operating agreements, it is possible that we might lose some
portion of our ownership interest in the properties under some circumstances,
or that we might be subject to penalties which would result in the forfeiture
of substantial revenues from the properties.
While the costs to develop the offshore California properties in
which we own an interest are anticipated to be substantial in relation to our
small size, management believes that the opportunities for us to increase our
asset base and ultimately improve our cash flow are also substantial in
relation to our size. Although there are several factors to be considered in
connection with our plans to obtain funding from outside sources as necessary
to pay our proportionate share of the costs associated with developing our
offshore properties (not the least of which is the possibility that prices for
petroleum products could decline in the future to a point at which development
of the properties is no longer economically feasible), we believe that the
timing and rate of development in the future will in large part be motivated
by the prices paid for petroleum products.
To the extent that prices for petroleum products were to decline
below their recent levels, it is likely that development efforts will proceed
at a slower pace such that costs will be incurred over a more extended period
of time. If petroleum prices remain at current levels, however, we believe
that development efforts will intensify. Our ability to successfully
negotiate financing to pay our share of development costs on favorable terms
will be inextricably linked to the prices that are paid for petroleum products
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during the time period in which development is actually occurring on each of
the subject properties.
Gato Canyon Unit. We hold a 15.60% working interest in the Gato
Canyon Unit. This 10,100 acre unit is operated by Samedan Oil Corporation.
Seven test wells have been drilled on the Gato Canyon structure. Five of
these were drilled within the boundaries of the Unit and two were drilled
outside the Unit boundaries in the adjacent State Tidelands. The test wells
were drilled as follows: within the boundaries of the Unit, three wells were
drilled by Exxon, two in 1968 and one in 1969; one well was drilled by Arco
in 1985 and one well was drilled by Samedan in 1989. Outside the boundaries
of the Unit, in the State Tidelands but still on the Gato Canyon Structure,
one well was drilled by Mobil in 1966 and one well was drilled by Union Oil in
1967. In April 1989, Samedan tested the P-0460 #2 which yielded a combined
test flow rate of 5,160 Bbls of oil per day from six intervals in the Monterey
Formation between 5,880 and 6,700 feet of drilled depth. The Monterey
Formation is a highly fractured shale formation. The Monterey (which ranges
from 500 feet to 2,900 feet in thickness) is the main productive and target
zone in many offshore California oil fields (including our federal leases
and/or units).
The Gato Canyon field is located in the Santa Barbara Channel
approximately three to five miles offshore (see Map). Water depths range from
280 feet to 600 feet in the area of the field. Oil and gas produced from the
field is anticipated to be processed onshore at the existing Las Flores Canyon
facility (see Map). Las Flores Canyon has been designated a "consolidated
site" by Santa Barbara County and is available for use by offshore operators.
Any processed oil is expected to be transported out of Santa Barbara County in
the All American Pipeline (see Map). Offshore pipeline distance to access the
Las Flores site is approximately six miles. Our share of the estimated
capital costs to develop the Gato Canyon field is approximately $45 million.
As a result of the Norton case, the Gato Canyon Unit leases are held
under directed suspensions of operations with no specified end date. An
updated Exploration Plan is expected to include plans to drill an additional
delineation well when activities are resumed. This well will be used to
determine the final location of the development platform. Following the
platform decision, a Development Plan will be prepared for submittal to the
MMS and the other involved agencies. Two to three years will likely be
required to process the Development Plan and receive the necessary approvals.
Point Sal Unit. We hold a 6.83% working interest in the Point Sal
Unit. This 22,772 acre unit is operated by Aera Energy LLC, a limited
liability company jointly owned by Shell Oil Company and ExxonMobil Company.
Four test wells were drilled within this unit. These test wells were drilled
as follows: two wells were drilled by Sun Oil (now Oryx Energy), one in 1984
and one in 1985; and the other two wells were drilled by Reading & Bates, both
in 1984. All four wells drilled on this unit have indicated the presence of
oil and gas in the Monterey Formation. The largest of these, the Sun P-0422
#1, yielded a combined test flow rate of 3,750 Bbls of oil per day from the
Monterey. The oil in the upper block has an average estimated gravity of 10E
API and the oil in the subthrust block has an average estimated gravity of 15E
API.
23
The Point Sal field is located in the Offshore Santa Maria Basin
approximately six miles seaward of the coastline. Water depths range from 300
feet to 500 feet in the area of the field. It is anticipated that oil and gas
produced from the field will be processed in a new facility at an onshore site
or in the existing Lompoc facility. Any processed oil would then be
transported out of Santa Barbara County in either the All American Pipeline or
the Tosco-Unocal Pipeline. Offshore pipeline distance is approximately six to
eight miles depending on the final choice of the point of landfall. Our share
of the estimated capital costs to develop the Point Sal Unit is approximately
$38 million.
As a result of the Norton case, the Point Sal Unit leases are held
under directed suspensions of operations with no specified end date. An
updated Exploration Plan is expected to include plans to drill an additional
delineation well when activities are resumed prior to preparing the
Development Plan.
Lion Rock Unit and Federal OCS Lease P-0409. We hold a 1% net
profits interest in the Lion Rock Unit and a 24.21692% working interest in
5,693 acres in Federal OCS Lease P-0409 which is immediately adjacent to the
Lion Rock Unit and contains a portion of the San Miguel Field reservoir. The
Lion Rock Unit is operated by Aera Energy LLC. An aggregate of 13 test wells
have been drilled on the Lion Rock Unit and OCS Lease P-0409. Nine of these
wells were completed and tested and indicated the presence of oil and gas in
the Monterey Formation. The test wells were drilled as follows: one well was
drilled by Socal (now Chevron) in 1965; six wells were drilled by Phillips
Petroleum, one in 1982, two in 1983, two in 1984 and one in 1985; and six
wells were drilled by Occidental Petroleum in Lease P-0409, three in 1983 and
three in 1984. The oil has an average estimated gravity of 10.7E API.
The Lion Rock Unit and Lease P-0409 are located in the Offshore
Santa Maria Basin eight to ten miles from the coastline. Water depths range
from 300 feet to 600 feet in the area of the field. It is anticipated that any
oil and gas produced at Lion Rock and P-0409 would be processed at a new
facility in the onshore Santa Maria Basin or at the existing Lompoc facility,
and would be transported out of Santa Barbara County in the All American
Pipeline or the Tosco-Unocal Pipeline. Offshore pipeline distance will be
eight to ten miles, depending on the point of landfall. Our share of the
estimated capital costs to develop the Lion Rock/San Miguel field is
approximately $113 million.
As a result of the Norton case, the Lion Rock Unit and Lease P-0409
are held under directed suspensions of operations with no specified end date.
It is anticipated that upon the resumption of activities there will be an
interpretation of the 3D seismic survey and the preparation of an updated Plan
of Development leading to production. Additional delineation wells may or may
not be drilled depending on the outcome of the interpretation of the 3D
survey.
Sword Unit. We hold a 2.492% working interest in the Sword Unit.
This 12,240 acre unit is operated by Conoco, Inc. In aggregate, three wells
have been drilled on this unit, of which two wells were completed and tested
in the Monterey formation with calculated flow rates of from 4,000 to 5,000
Bbls per day with an estimated average gravity of 10.6E API. The two
24
completed test wells were drilled by Conoco, one in 1982 and the second in
1985.
The Sword field is located in the western Santa Barbara Channel ten
miles west of Point Conception and five miles south of Point Arguello's field
Platform Hermosa. Water depths range from 1000 feet to 1800 feet in the area
of the field. It is anticipated that the oil and gas produced from the Sword
Field will likely be processed at the existing Gaviota consolidated facility
and the oil would then be transported out of Santa Barbara County in the All
American Pipeline. Access to the Gaviota plant is through Platform Hermosa
and the existing Point Arguello Pipeline system. A pipeline proposed to be
laid from a platform located in the northern area of the Sword field to
Platform Hermosa would be approximately five miles in length. Our share of
the estimated capital costs to develop the Sword field is approximately $19
million.
As a result of the Norton case, the Sword Unit leases are held under
directed suspensions of operations with no specified end date. An updated
Exploration Plan is expected to include plans to drill an additional
delineation well when activities are resumed.
Rocky Point Unit. Delta, owns an 11.11% interest in OCS Block 451
(E/2) and 100% interest in OCS Block 452 and 453, which leases comprise the
undeveloped Rocky Point Unit. On November 2, 2000 we entered into an
agreement with all of the interest owners of Point Arguello for the
development of Rocky Point and agreed, among other things, that Arguello,
Inc. would become the operator of Rocky Point. Six test wells have been
drilled on these leases from mobile drilling units. Five were successful and
one was a dry hole. OCS-P 0451 #1, drilled in 1982, was the discovery well
for the Rocky Point Field. Five delineation wells were drilled on the Unit
between 1982 and 1984. Rates up to 1,500 Bbls of oil per day were tested from
the Monterey formation. Rates up to 3,500 Bbls of oil per day were tested
from the lower Sisquoc formation which overlies the Monterey. Oil gravities
at Rocky Point range from 24 degrees to 31 degrees API.
Development of the Rocky Point Unit will be accomplished through
extended-reach drilling from the platforms located within the adjacent Point
Arguello Unit (see below). In 1987 an extended-reach well was successfully
drilled to the southwestern edge of the Rocky Point field from Platform
Hermosa located in the Point Arguello Unit. Since that time the technology of
extended-reach drilling has dramatically advanced. The entire Rocky Point
field is now within drilling distance from the Point Arguello Unit platforms.
As a result of the Norton case, the Rocky Point Unit leases are held
under directed suspensions of operations with no specified end date. The Unit
operator has prepared and timely submitted a Project Description for the
development program to the MMS as the first milestone in the Schedule of
Activities for the Unit. The operator, under the auspices of the MMS, has
also made a presentation of the Project to the affected Federal, state and
local agencies. On May 18, 2001 a revised Development and Production Plan and
supporting information was submitted to the MMS and distributed to the CCC and
the Office of the California Governor. The revised Development and Production
Plan calls for development of the Rocky Point Unit using extended reach
drilling from the existing Point Arguello platforms, and is deemed to be in
final form as the MMS has acknowledged that all regulatory requirements
25
necessary for such a Plan have been addressed. Under law, the CCC is
typically required to make a determination as to whether or not the Plan is
"consistent" with California's Coastal Plan within three months of submission,
with a maximum of three months' extension (a total of six months). By
correspondence dated August 7, 2001, however, the Unit operator requested that
the CCC suspend the consistency review for the revised Development and
Production Plan since the MMS had temporarily stopped work on the processing
of the plan as the result of the court decision in the Norton. See
"Management's Discussion and Analysis or Plan of Operation-Offshore
Undeveloped Properties".
On January 9, 2002, we filed a lawsuit against the U.S. government
along with several other companies alleging that the government breached the
terms of some of our undeveloped, offshore California properties. See "Legal
Proceedings."
Offshore Producing Properties:
-----------------------------
Point Arugello Unit. Whiting holds, as our nominee, the equivalent
of a 6.07% working interest in the form of a financial arrangement termed a
"net operating interest" in the Point Arguello Unit and related facilities.
In layman's terms, the term "net operating interest" is defined in our
agreement with Whiting as being the positive or negative cash flow resulting
to the interest from a seven step calculation which in summary subtracts
royalties, operating expenses, severance taxes, production taxes and ad
valorem taxes, capital expenditures, Unit fees and certain other expenses from
the oil and gas sales and certain other revenues that are attributable to the
interest. Within this unit are three producing platforms (Hidalgo, Harvest
and Hermosa) which are operated by Arguello, Inc., a subsidiary of Plains
Petroleum. In an agreement between Whiting and us (see Form 8-K dated June 9,
1999) Whiting agreed to retain all of the abandonment costs associated with
our interest in the Point Arguello Unit and the related facilities.
We anticipate that we will drill one to four developmental wells on
the Point Arguello Unit during fiscal 2003. Each well will cost
approximately $2.8 million ($170,000 to our interest). We anticipate the
costs to be paid through current operations or additional financing.
26
- ---------------
map page
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27
(c) Production.
During the years ended June 30, 2002 and 2001 we have not had, nor
do we now have, any long-term supply or similar agreements with governments or
authorities under which we acted as producer.
Impairment of Long Lived Assets
-------------------------------
Unproved Undeveloped Offshore California Properties
---------------------------------------------------
We acquired many of our offshore properties (including our
interest in Amber) in a series of transactions from 1992 to the present.
These properties are carried at our cost bases and have been subject to an
impairment review on an annual basis.
These properties will be expensive to develop and produce and
have been subject to significant regulatory restrictions and delays.
Substantial quantities of hydrocarbons are believed to exist based on
estimates reported to us by the operator of the properties and the U.S.
government's Mineral Management Services. The classification of these
properties depends on many assumptions relating to commodity prices,
development costs and timetables. We annually consider impairment of
properties assuming that properties will be developed. Based on the range of
possible development and production scenarios using current prices and costs,
we have concluded that the cost bases of our offshore properties are not
impaired at this time. There are no assurances, however, that when and if
development occurs, we will recover the value of our investment in such
properties.
Other Undeveloped Properties
----------------------------
Other undeveloped properties are carried at historical cost and
consist of the several onshore properties. These properties are carried at
our cost bases and have been subject to an impairment review on an annual
basis. There are no proven reserves associated with these properties. Based
on our continued interest in these properties and the possibility for future
development, we have concluded that the cost bases of these other undeveloped
properties are not impaired at this time. There are no assurances, however,
that when and if development occurs, we will recover the value of our
investments in such properties.
Onshore Producing Properties
----------------------------
We annually compare our historical cost basis of each
developed oil and gas property to its expected future undiscounted cash flow
from each property (on a field by field basis). Estimates of expected future
cash flows represent management's best estimate based on reasonable and
supportable assumptions and projections. If the expected future cash flows
exceed the carrying value of the property, no impairment is recognized. If
the carrying value of the property exceeds the expected future cash flows, an
28
impairment exists and is measured by the excess of the carrying value over
the estimated fair value of the asset.
We had an impairment provision attributed to producing
properties during the year ended June 30, 2002, of $878,000 and during the
year ended June 30, 2001 of $174,000.
Any impairment provisions recognized for developed and
undeveloped properties are permanent and may not be restored in the future.
The following table sets forth our average sales prices and
average production costs during the periods indicated:
Year Ended Year Ended Year Ended
June 30, June 30, June 30,
2002 2001 2000
---- ---- ----
Onshore Offshore Onshore Offshore Onshore Offshore
------- -------- ------- -------- ------- --------
Average sales price:
Net of forward contract sales
Oil (per barrel) $22.22 $14.36 $27.10 $18.49 $25.95 $11.54
Natural Gas (per Mcf) $ 2.75 $ - $ 6.27 - $ 2.62 -
Gross of forward contract sales
Oil (per barrel) $22.32 $14.45 $27.30 $22.53 $25.95 $21.14
Natural Gas (per Mcf) $ 2.75 $ - $ 6.27 - $ 2.62 -
Production costs
(per Bbl equivalent) $ 5.68 $11.64 $ 3.88 $12.65 $ 4.94 $11.02
(d) Productive Wells and Acreage.
The table below shows, as of June 30, 2002, the approximate number
of gross and net producing oil and gas wells by state and their related
developed acres owned by us. Calculations include 100% of wells and acreage
owned by us and by Amber. Productive wells are producing wells capable of
production, including shut-in wells. Developed acreage consists of acres
spaced or assignable to productive wells.
Oil (1) Gas Developed Acres
Gross (2) Net (3) Gross (2) Net (3) Gross (2) Net (3)
--------- ------- --------- ------- --------- -------
North Dakota 0 0 0 0 5,120 1,344
New Mexico 8 1.2 24 7.2 6,000 2,115
Texas 37 21.48 113 31.4 880 656
Colorado 6 4.2 5 4.00 4,480 1,600
Oklahoma 3 .93 4 1.57
California:
Onshore 10 .558 8 .664 720 49
Offshore 38 2.30 0 0 11,042 669
Wyoming 0 0 2 .634 1,280 811
29
Nebraska 2 .0625 0 0 160 10
Michigan 1 .0096 0 0 80 1
Mississippi 5 .413 5 1.01 400 57
Illinois 12 1.8 0 0 480 72
Alabama 0 0 51 49.2 4,080 3,916
Pennsylvania 0 0 143 89.29 5,720 3,577
Louisiana 12 7.14 3 1.32 600 388
Montana 12 3.7 0 0 480 148
Kansas 1 .048 0 0 40 2
--- ----- --- ------ ------ ------
108 27.26 358 186.27 41,562 15,360
______________
(1) All of the wells classified as "oil" wells also produce various
amounts of natural gas.
(2) A "gross well" or "gross acre" is a well or acre in which a working
interest is held. The number of gross wells or acres is the total
number of wells or acres in which a working interest is owned.
(3) A "net well" or "net acre" is deemed to exist when the sum of
fractional ownership interests in gross wells or acres equals
one. The number of net wells or net acres is the sum of the
fractional working interests owned in gross wells or gross acres
expressed as whole numbers and fractions thereof.
(4) This does not include varying very small interests in approximately
700 gross wells (4.6 net) located primarily in Texas which are owned
by our subsidiary, Piper Petroleum Company.
(e) Undeveloped Acreage.
At June 30, 2002, we held undeveloped acreage by state as set forth
below:
Undeveloped Acres (1) (2)
-------------------------
Location Gross Net
- -------- ----- ---
South Dakota 58,400 29,200
California, offshore(3) 64,905 15,837
California, onshore 640 96
Colorado 6,060 4,554
Wyoming 960 768
Alabama 420 406
Texas 8,923 3,265
------- ------
Total 140,308 54,126
_______________
(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.
30
(2) Includes acreage owned by Amber.
(3) Consists of Federal leases offshore California near Santa Barbara.
(f) Drilling Activity.
During the years indicated, we drilled or participated in the
drilling of the following productive and nonproductive exploratory and
development wells:
Year Ended Year Ended Year Ended
June 30,2002 June 30, 2001 June 30, 2000
Gross Net Gross Net Gross Net
------------ ------------- -------------
Exploratory Wells(1):
Productive:
Oil 0 .00 0 .00 0 .00
Gas 0 .00 0 .00 0 .00
Nonproductive 5 2.70 6 2.24 0 .00
- ---- - ---- - ---
Total 5 2.70 6 2.24 0 .00
Development Wells(1):
Productive:
Oil 4 .242 3 .18 3 .18
Gas 6 .491 7 .37 2 .25
Nonproductive 0 .00 0 .00 0 .00
-- ---- -- ---- - ---
Total 10 .733 10 .55 5 .43
Total Wells(1):
Productive:
Oil 4 .242 3 .18 3 .18
Gas 6 2.700 7 .37 2 .25
Nonproductive 5 .491 6 2.24 0 .00
-- ----- -- ---- - ---
Total Wells 15 3.433 16 2.79 5 .43
________________
(1) Does not include wells in which the Company had only a royalty
interest.
(g) Present Drilling Activity.
We plan to participate in the drilling of approximately 20 new wells
before the end of fiscal 2003.
Certain Risks
Prospective investors should consider carefully, in addition to the
other information in this Annual Report, the following:
31
1. We have substantial debt obligations and shortages of funding could hurt
our future operations.
As the result of debt obligations that we have incurred in connection
with purchases of oil and gas properties, we are obligated to make substantial
monthly payments to our lenders on loans which encumber our oil and gas
properties and our production revenue. At the present time we are almost
totally dependent upon the revenues that we receive from our oil and gas
properties to service the debt. In the event that oil and gas prices and/or
production rates drop to a level that we are unable to pay the minimum
principal and interest payments that are required by our debt agreements, it
is likely that we would lose our interest in some or all of our properties.
In addition, our level of oil and gas activities, including exploration and
development of existing properties, and additional property acquisitions, will
be significantly dependent on our ability to successfully conclude funding
transactions.
2. A default under our credit agreement could cause us to lose our
properties.
In connection with our acquisition of Castle's properties on May 31,
2002, we entered into a credit facility with Bank of Oklahoma and Local
Oklahoma Bank which allows us to borrow, repay and reborrow amounts. In order
to obtain this facility, we granted a first and prior lien to the lending
banks on most of our oil and gas properties, certain related equipment, oil
and gas inventory, certain bank accounts and proceeds. Under the terms of our
credit agreement, the oil and gas properties mortgaged must represent not less
than 80% of the engineered value of our oil and gas properties as determined
by the Bank of Oklahoma using its own pricing parameters, exclusive of the
properties that are mortgaged to Kaiser-Francis under a separate lending
arrangement. Our borrowing base, which determines the amounts that we are
allowed to borrow or have outstanding under our credit facility, was initially
determined to be $20 million at the time we entered into our credit agreement.
Subsequent determinations of our borrowing base will be made by the lending
banks at least semi-annually on October 1 and April 1 of each year beginning
October 1, 2002 or as unscheduled redeterminations. In connection with each
determination of our borrowing base, the banks will also redetermine the
amount of our monthly commitment reduction. The monthly commitment reduction
was $260,000.00 beginning as of July 1, 2002 and will continue at that amount
until the amount of the monthly commitment reduction is redetermined.
Our borrowing base and the revolving commitment of the banks to lend
money under the credit agreement must be reduced as of the first day of each
month by an amount determined by the banks under our credit agreement. The
amount of the borrowing base must also be reduced from time to time by the
amount of any prepayment that results from our sale of oil and gas properties.
If as a result of any such monthly commitment reduction or reduction in the
amount of our borrowing base, the total amount of our outstanding debt ever
exceeds the amount of the revolving commitment then in effect, then within 30
days after we are notified by the Bank of Oklahoma, we must make a mandatory
prepayment of principal that is sufficient to cause our total outstanding
indebtedness to not exceed our borrowing base.
32
If for any reason we were unable to pay the full amount of the mandatory
prepayment within the 30 requisite day period, we would be in default of our
obligations under our credit agreement.
For so long as the revolving commitment is in existence or any amount is
owed under any of the loan documents, we will also be required to comply with
a substantial number of loan covenants that will limit our flexibility in
conducting our business and which could cause us significant problems in the
event of a downturn in the oil and gas market.
Upon occurrence of an event of default and after the expiration of any
cure period that is provided in our credit agreement, the entire principal
amount due under the notes, all accrued interest and any other liabilities
that we might have to the lending banks under the loan documents will all
become immediately due and payable, all without notice and without
presentment, demand, protest, notice of protest or dishonor or any other
notice of default of any kind, and we will not be permitted to service our
obligations under our loan agreement with Kaiser-Francis Oil Company from
proceeds of the collateral securing the loan under our credit agreement
including, but not limited to, oil and gas properties or any related operating
fees.
The foregoing information is provided to alert investors that there is
risk associated with our existing debt obligations. It is not intended to
provide a summary of the terms of our agreements with our lenders. Complete
copies of our credit agreement and other loan documents are filed as an
exhibit to our Report on Form 8-K dated May 24, 2002.
3. We have a history of losses and we may not achieve profitability.
We have incurred substantial losses from our operations over the past
several years except fiscal 2001, and at June 30, 2002 we had an accumulated
deficit of $28,853,000. During the fiscal year ended June 30, 2002, we had
total revenue of $8,210,000, operating expenses of $13,251,000 and a net loss
for the year of $6,253,000. During fiscal 2001 we had total revenue of
$12,877,000, operating expenses of $11,199,000 and had net income of $345,000.
During the year ended June 30, 2000, we had total revenue of $3,576,000,
operating expenses of $5,655,000 and a net loss for fiscal 2000 of $3,367,000.
4. The substantial cost to develop certain of our offshore California
properties could result in a reduction in our interest in these
properties or penalize us.
Certain of our offshore California undeveloped properties, in which we
have ownership interests ranging from 2.49% to 75%, are attributable to our
interests in four of our five federal units (plus one additional lease)
located offshore California near Santa Barbara. The cost to develop these
properties will be very substantial. The cost to develop all of these
offshore California properties in which we own an interest, including
delineation wells, environmental mitigation, development wells, fixed
platforms, fixed platform facilities, pipelines and power cables, onshore
facilities and platform removal over the life of the properties (assumed to be
38 years), is estimated to be in excess of $3 billion. Our share of such
33
costs, based on our current ownership interest, is estimated to be over $200
million.
Operating expenses for the same properties over the same period of time,
including platform operating costs, well maintenance and repair costs, oil,
gas and water treating costs, lifting costs and pipeline transportation costs,
are estimated to be approximately $3.5 billion, with our share, based on our
current ownership interest, estimated to be approximately $300 million. There
will be additional costs of a currently undetermined amount to develop the
Rocky Point Unit. Each working interest owner will be required to pay its
proportionate share of these costs based upon the amount of the interest that
it owns. If we are unable to fund our share of these costs or otherwise cover
them through farmouts or other arrangements, then we could either forfeit our
interest in certain wells or properties or suffer other penalties in the form
of delayed or reduced revenues under our various unit operating agreements.
5. The development of the offshore units could be delayed or halted.
The California offshore federal units have been formally approved and are
regulated by the Minerals Management Service of the federal government
("MMS"). The MMS initiated the California Offshore Oil and Gas Energy
Resources(COOGER) study at the request of the local regulatory agencies of the
affected Tri-Counties. The COOGER study was completed in January of 2000 and
is intended to present a long-term regional perspective of potential onshore
constraints that should be considered when developing existing undeveloped
offshore leases. The "worst" case scenario under the COOGER study is that no
new development of existing offshore leases would occur. If this scenario
were ultimately to be adopted by governmental decision makers and the industry
as the proper course of action for development, our offshore California
properties would in all likelihood have little or no value. Under those
circumstances we would seek to cause the Federal government to reimburse us
for all money spent by us and our predecessors for leasing and other costs
and/or for the value of the oil and gas reserves found on the leases through
our exploration activities and those of our predecessors. On June 22, 2001,
in litigation relating to the development of these properties brought by the
State of California, a Federal Court ordered the MMS to set aside its approval
of the suspensions of our offshore leases that were granted while the COOGER
Study was being completed, and to direct suspensions, including all milestone
activities, for a time sufficient for the MMS to provide the State of
California with a consistency determination under federal law. On July 2,
2001 these milestones were suspended by the MMS.
In a separate action, on January 9, 2002 we and several other plaintiffs
filed a lawsuit in the United States Court of Federal Claims in Washington,
D.C. alleging that the U.S. Government materially breached the terms of the
leases for our offshore California properties. Our suit seeks compensation
for the lease bonuses and rentals paid to the Federal Government, exploration
costs, and related expenses. The ultimate outcome and effects of the
litigation pertaining to our Offshore California properties are not certain at
the present time.
34
6. We will have to incur substantial costs in order to develop our
reserves and we may not be able to secure funding.
Relative to our financial resources, we have significant undeveloped
properties in addition to those in offshore California discussed above that
will require substantial costs to develop. During the year ended June 30,
2001, we participated in the drilling and completion or recompletion of seven
gas wells and six non-productive wells. During the year ended June 30, 2002,
we participated in the drilling of four offshore wells at a cost to us of
approximately $680,000, and 11 (6 successful and 5 unsuccessful) onshore wells
at a cost to us of approximately $1,140,000. The cost of these wells either
has been or will be paid out of our cash flow.
We drilled 6 successful and 5 unsuccessful wells onshore and drilled 4
successful offshore wells in fiscal 2002. Our level of future oil and gas
activity, including exploration and development and property acquisitions,
will be to a significant extent dependent upon our ability to successfully
conclude funding transactions.
We expect to continue incurring costs to acquire, explore and develop oil
and gas properties, and management predicts that these costs (together with
general and administrative expenses) will be in excess of funds available from
revenues from properties owned by us and existing cash on hand. It is
anticipated that the source of funds to carry out such exploration and
development will come from a combination of our sale of working interests in
oil and gas leases, production revenues, sales of our securities, and funds
from any funding transactions in which we might engage.
7. Current and future governmental regulations will affect our operations.
Our activities are subject to extensive federal, state, and local laws
and regulations controlling not only the exploration for and sale of oil, but
also the possible effects of such activities on the environment. Present as
well as future legislation and regulations could cause additional
expenditures, restrictions and delays in our business, the extent of which
cannot be predicted, and may require us to cease operations in some
circumstances. In addition, the production and sale of oil and gas are
subject to various governmental controls. Because federal energy policies are
still uncertain and are subject to constant revisions, no prediction can be
made as to the ultimate effect on us of such governmental policies and
controls.
8. We hold only a minority interest in certain properties and, therefore,
generally will not control the timing of development.
We currently do not operate approximately 42% of the wells in which we
own an interest and we are dependent upon the operators of the wells that we
do not operate to make most decisions concerning such things as whether or not
to drill additional wells, how much production to take from such wells, or
whether or not to cease operation of certain wells. Further, we do not act as
operator of and, with the exception of Rocky Point, we do not own a
controlling interest in any of our offshore California properties. While we,
as a working interest owner, may have some voice in the decisions concerning
the wells, we are not the primary decision maker concerning them. As a
result, we will generally not control the timing of either the development of
35
most of these non-operated properties or the expenditures for their
development. Because we are not in control of the non-operated wells, we may
not be able to cause wells to be drilled even though we may have the funds
with which to pay our proportionate share of the expenses of such drilling,
or, alternatively, we may incur development expenses at a time when funds are
not available to us. We hold only a minority interest in and do not operate
many of our properties and, therefore, generally will not control the timing
of development on these properties.
9. We are subject to the general risks inherent in oil and gas exploration
and operations.
Our business is subject to risks inherent in the exploration, development
and operation of oil and gas properties, including but not limited to
environmental damage, personal injury, and other occurrences that could result
in our incurring substantial losses and liabilities to third parties. In our
own activities, we purchase insurance against risks customarily insured
against by others conducting similar activities. Nevertheless, we are not
insured against all losses or liabilities which may arise from all hazards
because such insurance is not available at economic rates, because the
operator has not purchased such insurance, or because of other factors. Any
uninsured loss could have a material adverse effect on us.
10. We have no long-term contracts to sell oil and gas.
We do not have any long-term supply or similar agreements with
governments or authorities for which we act as a producer. We are therefore
dependent upon our ability to sell oil and gas at the prevailing well head
market price. There can be no assurance that purchasers will be available or
that the prices they are willing to pay will remain stable.
11. Our business is not diversified.
Since all of our resources are devoted to one industry, purchasers of our
common stock will be risking essentially their entire investment in a company
that is focused only on oil and gas activities.
12. Our shareholders do not have cumulative voting rights.
Holders of our common stock are not entitled to accumulate their votes
for the election of directors or otherwise. Accordingly, the present
shareholders will be able to elect all of our directors, and holders of the
common stock offered by this prospectus will not be able to elect a
representative to our Board of Directors. See "DESCRIPTION OF COMMON STOCK."
13. We do not expect to pay dividends.
There can be no assurance that our proposed operations will result in
sufficient revenues to enable us to operate at profitable levels or to
generate a positive cash flow, and our current loan documents prevent us from
paying dividends. For the foreseeable future, it is anticipated that any
earnings which may be generated from our operations will be used to finance
our growth and that dividends will not be paid to holders of common stock.
See "DESCRIPTION OF COMMON STOCK."
36
14. We depend on key personnel.
We currently have only three employees that serve in management roles,
and the loss of any one of them could severely harm our business. In
particular, Roger A. Parker is responsible for the operation of our oil and
gas business, Aleron H. Larson, Jr. is responsible for other business and
corporate matters, and Kevin K. Nanke is our chief financial officer. We do
not have key man insurance on the lives of any of these individuals.
15. We allow our key personnel to purchase working interests on the same
terms as us.
In the past we have occasionally allowed our key employees to purchase
working interests in our oil and gas properties on the same terms as us in
order to provide a meaningful incentive to the employees and to align their
own personal financial interests with ours in making decisions affecting the
properties in which they own an interest.
Specifically, on February 12, 2001, our Board of Directors permitted
Aleron H. Larson, Jr., our Chairman, Roger A. Parker, our President, and
Kevin K. Nanke, our CFO, to purchase working interests of 5% each for Messrs.
Larson and Parker and 2-1/2% for Mr. Nanke in our Cedar State gas property
located in Eddy County, New Mexico and in our Ponderosa Prospect consisting of
approximately 52,000 gross acres in Harding and Butte Counties, South Dakota
held for exploration. These officers were authorized to purchase these
interests on or before March 1, 2001 at a purchase price equivalent to the
amounts paid by us for each property as reflected upon our books by delivering
to us shares of Delta common stock at the February 12, 2001 closing price of
$5.125 per share. Messrs. Larson and Parker each delivered 31,310 shares and
Mr. Nanke delivered 15,655 shares in exchange for their interests in these
properties.
Also on February 12, 2001, we granted to Messrs. Larson and Parker and
Mr. Nanke the right to participate in the drilling of the Austin State #1 well
in Eddy County, New Mexico by having them commit to us on February 12, 2001
(prior to any bore hole knowledge or information relating to the objective
zone or zones)to pay 5% each by Messrs. Larson and Parker and 2-1/2% by Mr.
Nanke of our working interest costs of drilling and completion or abandonment
costs, which costs may be paid in either cash or in Delta common stock at
$5.125 per share. All of these officers committed to participate in the well
under the condition that they would be assigned their respective working
interests in the well and associated spacing unit after they had been billed
and had paid for the interests as required.
To the extent that key employees are permitted to purchase working
interests in wells that are successful, they will receive benefits of
ownership that might otherwise have been available to us. Conversely, to the
extent that key employees purchase working interests in wells that are
ultimately not successful, such purchases may result in personal financial
losses for our key employees that could potentially divert their attention
from our business.
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16. The exercise of our Put Rights may dilute the interests of other
security holders.
We have entered into an arrangement with Swartz Private Equity, LLC under
which we may sell shares of our common stock to Swartz at a discount from the
then prevailing market price. The exercise of these rights may substantially
dilute the interests of other security holders.
Under the terms of our relationship with Swartz, we will issue shares to
Swartz upon exercise of our Put Rights at a price equal to the lesser of: the
market price for each share of our common stock minus $.25; or 91% of the
market price for each share of our common stock.
17. The sale of material amounts of our common stock could reduce the price
of our common stock and encourage short sales.
If and when we exercise our Put Rights and sell shares of our common
stock to Swartz, if and to the extent that Swartz sells the common stock, our
common stock price may decrease due to the additional shares in the market. If
the price of our common stock decreases, and if we decide to exercise our
right to put shares to Swartz, we must issue more shares of our common stock
for any given dollar amount invested by Swartz, subject to a designated
minimum Put price that we specify. This may encourage short sales, which could
place further downward pressure on the price of our common stock. Under the
terms of the Investment Agreement with Swartz, however, we are not obligated
to sell any of our shares to Swartz nor do we intend to sell shares to Swartz
unless it is beneficial to us.
ITEM 3. LEGAL PROCEEDINGS
On January 9, 2002, we and several other plaintiffs filed a lawsuit in
the United States Court of Federal Claims in Washington, D.C. alleging that
the U.S.