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, 2003.
[ ] 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. [X] Yes [ ] 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]
Indicate by a check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act) [ ]Yes No [X]
The aggregate market value as of September 15, 2003 of voting stock held by
non-affiliates of the registrant was $70,202,000.
As of September 15, 2003, 23,418,000 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 2003 Annual Meeting of Shareholders.
TABLE OF CONTENTS
PART I
PAGE
ITEM 1. DESCRIPTION OF BUSINESS ........................................ 4
ITEM 2. DESCRIPTION OF PROPERTY ........................................ 16
ITEM 3. LEGAL PROCEEDINGS .............................................. 36
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ............ 37
ITEM 4A DIRECTORS AND EXECUTIVE OFFICERS ............................... 37
PART II
ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS ....... 40
ITEM 6. SELECTED FINANCIAL DATA ........................................ 41
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS ...................................... 41
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ..... 54
ITEM 8. FINANCIAL STATEMENTS ........................................... 54
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE ......................... 54
ITEM 9A. CONTROLS AND PROCEDURES ........................................ 55
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ............. 55
ITEM 11. EXECUTIVE COMPENSATION ......................................... 55
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT ................................................. 55
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ................. 55
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES ......................... 55
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K ...................................................... 56
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 475 Seventeenth Street, Suite 1400, 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, 2003, we had varying
interests in 488 gross (260 net) productive wells located in fourteen (14)
states and offshore California. These do not include varying small interests
in 666 gross (5.2 net) wells located primarily in Texas which are owned by our
subsidiary Piper Petroleum Company. We also have 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 operate approximately 270 of the wells and the
remaining wells are operated by independent operators. All of these wells are
operated under contracts which we believe are standard in the industry. At
June 30, 2003, we estimated onshore proved reserves to be approximately
3,698,000 Bbls of oil and 55.2 Bcf of gas, of which approximately 2,608,000
Bbls of oil and 28.6 Bcf of gas were proved developed reserves. At June 30,
2003, we estimated offshore proved reserves to be approximately 2,051,000 Bbls
of oil, of which approximately 919,000 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 23,286,000 shares were issued and
outstanding as of June 30, 2003. We have outstanding warrants and options to
non-employees to purchase 1,255,000 shares of common stock at prices ranging
from $3.00 per share to $6.00 per share at June 30, 2003. Additionally, as of
June 30, 2003 we had outstanding options which were granted to our officers,
employees and directors under our incentive plans, to purchase up to 3,411,000
shares of common stock at prices ranging from $0.05 to $9.75 per share.
On June 20, 2003, Delta acquired producing oil and gas interests and
related undeveloped acreage in Kansas from JAED Production Company ("JAED"),
an unrelated entity, for which Delta paid $9,000,000 in cash and issued
200,000 shares of common stock. The shares issued were recorded at a stock
price of $4.61, a five day average closing price surrounding the announcement
of the transaction. Delta recorded a purchase price adjustment of
approximately $291,000 which reflects the net revenues after operating costs
and acquisition related costs from the effective date of June 1, 2003 through
the closing date of June 20, 2003.
Also on June 20, 2003, Delta increased its credit facility from $20
million to $29.3 million with Bank of Oklahoma and Local Oklahoma Bank (the
"Banks"). The proceeds from this facility were used for the acquisitions of
4
JAED during fiscal 2003 and Castle Energy Corporation ("Castle") during fiscal
2002. At June 30, 2003, our total borrowings were approximately $32,214,000.
A substantial portion of our oil and gas properties are pledged as collateral
for our 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.
At June 30, 2003, 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. 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. At June 30, 2003, 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.
On May 31, 2002, Delta acquired all of the domestic oil and gas
properties of Castle. The properties acquired from Castle consisted 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.
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, which BWAB exercised. 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. This transaction
was exempt from registration under Section 4(2) of the Securities Act of 1933.
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.
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 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
5
and royalty interests in over 700 gross (5.3 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."
Subsequent to June 30, 2003, we completed the acquisition of certain oil
and gas properties for a purchase price of approximately $13,000,000, which
consisted of one million shares of our common stock valued at approximately
$5,000,000, $2 million in cash and $6 million in notes payable due October 3,
2003.
(b) Business of Issuer.
During the year ended June 30, 2003, 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
fourteen (14) 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 Alabama, Louisiana, New Mexico,
Pennsylvania, Texas, Wyoming, and offshore California.
We intend to drill on some of our leases (presently owned or subsequently
acquired); may farm out or sell all or part of some of the leases to others;
and/or we may participate in joint venture arrangements to develop certain
other leases. Such transactions may be structured in a number of different
manners which are in use in the oil and gas industry. Each such transaction is
likely to be individually negotiated and no standard terms may be predicted.
(1) Principal Products or Services and Their Markets. The principal
products produced by us are crude oil and natural gas. The products are
generally sold at the wellhead to purchasers in the immediate area where the
product is produced. The principal markets for oil and gas are refineries and
transmission companies which have facilities near our producing properties.
(2) Distribution Methods of the Products or Services. Oil and natural
gas produced from our wells are normally sold to purchasers as referenced in
(6) below. Oil is picked up and transported by the purchaser from the
6
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 is
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, 2003, we sold a significant portion of 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
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
7
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.
8
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 regulations by the Responsible Party, its agent or subcontractor
or in certain other circumstances.
In addition, with respect to certain offshore facilities, OPA requires
evidence of financial responsibility in an amount of up to $150 million. Tank
vessels must provide such evidence in an amount based on the gross tonnage of
the vessel. Failure to comply with these requirements or failure to cooperate
during a spill event may subject a Responsible Party to civil or criminal
enforcement actions and penalties.
Under our various agreements, we have primary liability for oil spills
that occur on properties for which we act as operator. With respect to
9
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, 2004.
Abandonment Costs. We are responsible for costs associated with the
plugging of wells, the removal of facilities and equipment and site
restoration on our oil and natural gas properties, pro rata to our working
interest. As of January 1, 2003 we adopted SFAS No. 143 "Accounting for Asset
Retirement Obligations". SFAS No. 143 requires entities to record the fair
value of liabilities for retirement obligations of acquired assets. We
recorded an asset retirement obligation of approximately $868,000 at June 30,
2003 and a cumulative effect of change in accounting principle on prior years
of $20,000 in our consolidated statement of operations for the year ended June
30, 2003. Estimates of abandonment costs and their timing may change due to
many factors, including actual drilling and production results, inflation
rates, and changes to environmental laws and regulations. Estimated asset
retirement obligations are added to net unamortized historical oil and gas
property costs for purposes of computing depreciation, depletion and
amortization expense charges.
10
(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.
Certain Risks.
--------------
Prospective investors should consider carefully, in addition to the
other information in this Annual Report, the following:
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. We currently owe Bank of Oklahoma and
Local Oklahoma Bank approximately $27.7 million, and we are currently required
to pay approximately $600,000 per month to service this debt. We also
currently owe Kaiser-Francis Oil Company approximately $4.5 million, and we
are required to make minimum monthly payments of principal and interest on the
Kaiser-Francis debt that are equal to the greater of $150,000 or 75% of net
cash flows from our property acquisitions that were completed on November 1,
1999 and December 1, 1999. The entire amount of the Kaiser-Francis debt will
become due and payable in full on July 1, 2004. It is likely that we will
sell some of our properties to pay the amount due on the Kaiser-Francis debt
at that time. Although we also intend to seek outside capital to either
refinance our bank debt or provide liquidity, at the present time we are
almost totally dependent upon the revenues that we receive from our oil and
gas properties to service our 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.
Our credit facility with Bank of Oklahoma and Local Oklahoma Bank 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 recently increased to $29.3
million. Subsequent determinations of our borrowing base will be made by the
11
lending banks at least semi-annually on October 1 and April 1 of each year 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. Our monthly commitment reduction is currently $600,000
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. 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.
3. History of net income (loss).
Although we had net income of $1,257,000 during fiscal 2003 we incurred
substantial losses from our operations during fiscal 2002, and we had an
accumulated deficit of $27,596,000 at June 30, 2003. During fiscal year ended
June 30, 2003, we had total revenue of $23,980,000 and operating expenses of
$20,967,000. During the fiscal year ended June 30, 2002, we had total revenue
of $8,033,000, operating expenses of $13,074,000 and a net loss for the year
of $6,253,000. During fiscal 2001 we had total revenue of $12,712,000,
operating expenses of $11,093,000 and had net income of $345,000.
4. The substantial cost to develop certain of our offshore California
properties could result in a reduction of 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
12
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
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.
Our offshore California leases are located in federal units that have
been formally approved and are regulated by the Minerals Management Service of
the federal government ("MMS"). There has historically been political
resistance to the development of these leases due to environmental concerns.
At the request of the local regulatory agencies of the affected Tri-Counties
in California, the MMS initiated a study, called the California Offshore Oil
and Gas Energy Resources(COOGER) study, which was intended to present a
long-term regional perspective of potential onshore constraints that should be
considered when developing the existing undeveloped offshore leases. The
COOGER study took several years to complete and was presented as a final
document in January of 2000. During the period while the COOGER study was
being completed, the MMS unilaterally approved suspensions of operations for
the affected leases which had the effect of allowing most of our offshore
leases to continue in effect after their stated expiration dates. During that
same period, the State of California commenced litigation in Federal Court in
California which, among other things, challenged the ability of the MMS under
federal law to approve the subject suspensions and thereby extend the terms of
the leases without providing the State of California with a formal
determination that the granting of the suspensions was consistent with the
requirements of the Coastal Zone Management Act. On June 22, 2001, the
California 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, but as of the date of this
prospectus the MMS has not yet made a consistency determination. On January
9, 2002 we and several other plaintiffs filed a separate 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
13
California properties. Our suit seeks compensation for the lease bonuses and
rentals paid to the Federal Government, exploration costs, and related
expenses. While it is still our present intent to develop our Offshore
California properties as soon as possible, the ultimate outcome and effects of
the litigation pertaining to these properties are not certain at the present
time. In the event that we make a determination that development of all or any
portion of these properties is not feasible, we intend to write off an
appropriate portion of these assets on our balance sheet irrespective of the
status of our litigation against the United States government at that time.
As of June 30, 2003, these properties had an aggregate carrying value of
$10,164,000.
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,
2003, we did not participate in the drilling of any offshore wells, but we did
participate in the drilling of 9 onshore wells, of which three were non-
productive, at a cost to us of approximately $2,145,000. The cost of these
wells either has been or will be paid out of our cash flow. Although we
believe that we will participate in the drilling of additional wells during
our 2004 fiscal year, our level of oil and gas activity, including exploration
and development and property acquisitions, will be to a significant extent
dependent upon our cash flow from operations which is in turn dependent upon
the prices that we receive from the sale of our oil and gas production.
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 40% of the wells in which we
own an interest and we are dependent upon the operators of the wells that we
14
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
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.
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
15
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.
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.
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
fourteen (14) 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:
--------
We own interests in approximately 488 gross (260 net) producing wells in
fourteen (14) states, not including interests in those wells owned by our
subsidiary, Piper Petroleum Company ("Piper"). Piper owns varying very small
interests in 666 gross (5.2 net) wells located primarily in Texas. Piper's
wells produce approximately 70 bbls per day and 470 mcf per day net to Piper's
interests. In addition to our producing properties, we have interests in
undeveloped properties and unproved undeveloped properties throughout the
United States.
Our principal onshore producing properties are in the following states:
16
Alabama
-------
We own and operate a 98.4% working interest in 52 coal bed methane gas
wells at depths of about 2,500 feet in Tuscaloosa County. These wells produce
approximately 1800 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 16 barrels per day and 100 mcf per day net to our interest.
Kansas
------
We own interests in 21 gross (16.7 net) wells in 9 separate leases
located in Sumner County, Kansas. Delta operates all of the wells located on
these leases. Current production is 850 BOPD and 450 MCFD, which is 670 BOPD
and 360 MCFD net to our interest.
Texas
-----
We own interests in 112 gross (43.9 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 37 of these wells. These
wells are scattered throughout 33 counties and are drilled to various depths
and reservoirs with varying working interests. In aggregate these wells
produce approximately 240 barrels of oil and 3,600 mcf of gas per day net to
our interest.
Pennsylvania
------------
We own 142 wells with an average working interest of approximately 64% 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 1,007 mcf
per day net to our interests.
Louisiana
---------
In Louisiana we own interests in 15 wells with an average working
interest of 58.4% 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 220 barrels of oil per day net to our interests.
New Mexico
----------
We own interests in 36 wells in New Mexico, including the 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.
17
Other States
------------
We also own varying interests in producing wells in the following states:
California (Sacramento Basin), Colorado (Denver-Julesburg and Piceance
Basins), Nebraska, Michigan, Mississippi, Montana, Oklahoma, and Wyoming.
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
18
planned. Currently, 11 fields are producing from 18 platforms in the Santa
Barbara Channel and offshore Santa Maria Basin. Implementation of extended
high-angle to horizontal drilling methods is reducing the number of platforms
and wells needed to develop reserves in the area. Use of these new drilling
methods and seismic technologies is expected to continue to improve
development economics.
Leasing, lease administration, development and production within the
Federal POCS all fall under the Code of Federal Regulations administered by
the MMS. The EPA controls disposal of effluents, such as drilling fluids and
produced waters. Other Federal agencies, including the Coast Guard and the
Army Corps of Engineers, also have oversight 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.
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.
19
We do not act as operator of any offshore California properties and
consequently will not generally control the timing of either the development
of the properties or the expenditures for development unless we choose to
unilaterally propose the drilling of wells under the relevant operating
agreements.
The MMS initiated the California Offshore Oil and Gas Energy Resources
(COOGER) Study at the request of the local regulatory agencies of the three
counties (Ventura, Santa Barbara and San Luis Obispo) affected by offshore oil
and gas development. A private consulting firm completed the study under a
contract with the MMS. The COOGER 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.
20
Scenario 4 - Development of existing leases after decommissioning and
removal of some or all existing onshore facilities. This scenario
includes new facilities, and perhaps new sites, to handle anticipated
future production. Under this scenario we would incur increased costs
but revenues would be received more quickly.
We have also evaluated our position with regard to the scenarios with
respect to properties located in the northern sub-region (which includes the
Lion Rock Unit and the Point Sal Unit), the results of which are as follows:
Scenario 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.
21
On the Lion Rock Unit, Platform A would be set in a water depth of
approximately 507 feet, and Platform B would be set in a water depth of
approximately 484 feet. The reach of the deviated wells from each platform
required to drain each unit falls within the reach limits now considered to be
"state-of-the-art." The development plans for the Rocky Point Unit provide
for the inclusion of the Rocky Point leases in the Point Arguello Unit upon
which the Rocky Point leases would be drilled from existing Point Arguello
platforms with extended reach drilling technology. 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.
22
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
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. In the event, however, that we receive any
23
proceeds as the result of such litigation, we will be obligated to pay a
portion of any amount received by us to landowners and other owners of
royalties and similar interests, and to pay expenses of litigation and to
fulfill certain pre-existing contractual commitments to third parties.
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 a portion of the Rocky Point Unit from
the Point Arguello platforms that are already in existence.
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:
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.
24
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
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.
25
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 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
26
(assumed to be 38 years), is estimated by the partners to be in excess of $3
billion. Our share based on our current working interest of such costs over
the life of the properties is estimated to be over $200 million. There will be
additional costs of a currently undetermined amount to develop the Rocky Point
Unit which is the fifth undeveloped unit in which we own an interest.
To the extent that we do not have sufficient cash available to pay our
share of expenses when they become payable under the respective operating
agreements, it will be necessary for us to seek funding from outside sources.
Likely potential sources for such funding are currently anticipated to include
(a) public and private sales of our common stock (which may result in
substantial ownership dilution to existing shareholders), (b) bank debt from
one or more commercial oil and gas lenders, (c) the sale of debt instruments
to investors, (d) entering into farm-out arrangements with respect to one or
more of our interests in the properties whereby the recipient of the farm-out
would pay the full amount of our share of expenses and we would retain a
carried ownership interest (which would result in a substantial diminution of
our ownership interest in the farmed-out properties), (e) entering into one or
more joint venture relationships with industry partners, (f) entering into
financing relationships with one or more industry partners, and (g) the sale
of some or all of our interests in the properties.
It is unlikely that any one potential source of funding would be utilized
exclusively. Rather, it is more likely that we will pursue a combination of
different funding sources when the need arises. Regardless of the type of
financing techniques that are ultimately utilized, however, it currently
appears likely that because of our small size in relation to the magnitude of
the capital requirements that will be associated with the development of the
subject properties, we will be forced in the future to issue significant
amounts of additional shares, pay significant amounts of interest on debt that
presumably would be collateralized by all of our assets (including our
offshore California properties), reduce our ownership interest in the
properties through sales of interests in the 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.
27
To the extent that prices for petroleum products were to decline below
their recent levels, it is likely that development efforts will proceed at a
slower pace such that costs will be incurred over a more extended period of
time. If petroleum prices remain at current levels, however, we believe that
development efforts will intensify. Our ability to successfully negotiate
financing to pay our share of development costs on favorable terms will be
inextricably linked to the prices that are paid for petroleum products during
the time period in which development is actually occurring on each of the
subject properties.
Gato Canyon Unit. We hold a 15.60% working interest 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
28
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.
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.
29
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 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. We own 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
30
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
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 case. (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 Arguello Unit. Whiting Petroleum Corporation holds, as our
nominee, the equivalent of a 6.07% working interest in 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 or two developmental wells on the
Point Arguello Unit during fiscal 2004. 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.
31
- ---------------
map page
- ---------------
32
(c) Production.
During the years ended June 30, 2003 and 2002 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 basis, $10,164,000, 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 several onshore properties. These properties are carried at our cost
basis, $12,518,000, 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 basis 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 proved developed
and undeveloped 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
impairment exists and is measured by the excess of the carrying value over the
estimated fair value of the asset.
33
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 and none during the year ended June 30, 2003.
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,
2003 2002 2001
---------- ---------- ----------
Onshore Offshore Onshore Offshore Onshore Offshore
------- -------- ------- -------- ------- --------
Average sales price:
Oil (per barrel) $28.81 $20.21 $22.22 $14.36 $27.10 $18.49
Natural Gas (per Mcf) $ 4.67 $ - $ 2.75 $ - $ 6.27 $ -
Hedge effect
(per barrel equivalent) $(2.50) $ - $ .17 $ - $(0.11) $ -
Production costs
(per Bbl equivalent) $ 8.37 $14.41 $ 5.68 $11.64 $ 3.88 $12.65
(d) Productive Wells and Acreage.
The table below shows, as of June 30, 2003, 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 28 7.9 9,280 2,576
Texas (4) 28 16.7 84 27.2 14,560 5,020
Colorado 6 3.5 5 4.00 1,040 780
Oklahoma 3 .96 0 0 120 38
California:
Onshore 10 .558 5 .7 1,200 134
Offshore 38 2.3 0 0 11,042 669
Wyoming 0 0 2 .634 320 101
Nebraska 1 .0625 0 0 40 3
Michigan 1 .0096 0 0 40 0
Mississippi 4 .3 4 1.0 1,440 332
Alabama 0 0 72 69.6 2,880 2,784
Pennsylvania 0 0 142 91.1 5,680 3,644
Louisiana 13 7.6 2 .88 1,160 586
Montana 10 3.2 1 .50 720 288
Kansas 21 20.2 0 0 840 808
--- ----- --- ----- ------ ------
143 56.59 345 203.5 55,482 19,107
34
(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 666
gross wells (5.2 net) located primarily in Texas which are owned by our
subsidiary, Piper Petroleum Company.
(e) Undeveloped Acreage.
At June 30, 2003, we held undeveloped acreage by state as set forth
below:
Undeveloped Acres (1) (2)
-------------------------
Location Gross Net
California, offshore(3) 64,905 15,837
California, onshore 640 96
Colorado 5,163 3,283
Wyoming 1,200 632
Alabama 1,040 1,028
Texas 8,923 3,265
------ ------
Total 81,871 24,141
______________________
(1) Undeveloped acreage is considered to be those lease acres on which wells
have not been drilled or completed to a point that would permit the
production of commercial quantities of oil and gas, regardless of
whether such acreage contains proved reserves.
(2) Includes acreage owned by Amber.
(3) Consists of Federal leases offshore California near Santa Barbara.
(f) Drilling Activity.
During the years indicated, we drilled or participated in the drilling of
the following productive and nonproductive exploratory and development wells:
35
Year Ended Year Ended Year Ended
June 30, 2003 June 30, 2002 June 30, 2001
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 3 1.55 5 2.70 6 2.24
--- ---- --- ---- --- ----
Total 3 1.55 5 2.70 6 2.24
Development Wells(1):
Productive:
Oil 0 .00 4 .242 3 .18
Gas 6 5.15 6 .491 7 .37
Nonproductive 0 .00 0 .00 0 .00
--- ---- --- ----- --- ----
Total 6 5.15 10 .733 10 .55
Total Wells(1):
Productive:
Oil 0 .00 4 .242 3 .18
Gas 6 5.15 6 2.700 7 .37
Nonproductive 3 1.55 5 .491 6 2.24
--- ---- --- ----- --- ----
Total Wells 9 6.70 15 3.433 16 2.79
______________________
(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 2004.
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. 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
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.
36
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. In the event, however, that we receive any
proceeds as the result of such litigation, we will be obligated to pay a
portion of any amount received by us to landowners and other owners of
royalties and similar interests, and to pay expenses of litigation and to
fulfill certain pre-existing contractual commitments to third parties.
The Federal Government has not yet filed an answer in this proceeding
pending its motion to dismiss the lawsuit, which motion has not yet been heard
by the court.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matter was submitted to a vote of security holders during the fourth
quarter of our fiscal year.
ITEM 4A. DIRECTORS AND EXECUTIVE OFFICERS.
The following information with respect to Directors and Executive
Officers is furnished pursuant to Item 401(a) of Regulation S-K.
Name Age Positions Period of Service
- ---- --- --------- -----------------
Aleron H. Larson, Jr. 58 Chairman of the Board, May 1987 to Present
Secretary and a Director
Roger A. Parker 41 President, Chief May 1987 to Present
Executive Officer and
a Director
Jerrie F. Eckelberger 59 Director September 1996 to
Present
James B. Wallace 74 Director November 2001 to
Present
Joseph L. Castle II 71 Director June 2002 to Present
Russell S. Lewis 48 Director June 2002 to Present
John P. Keller 64 Director June 2002 to Present
Kevin K. Nanke 38 Treasurer and Chief December 1999 to
Financial Officer Present
The following is biographical information as to the business experience
of each of our current officers and directors.
37
Aleron H. Larson, Jr. has operated as an independent in the oil and gas
industry individually and through public and private ventures since 1978. Mr.
Larson served as the Chairman, Secretary, CEO and a Director of Chippewa
Resources Corporation, a public company then li