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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
|X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1999
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _________________
Commission file number: 0-10990
CASTLE ENERGY CORPORATION
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(Exact name of registrant as specified in its charter)
Delaware 76-0035225
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
One Radnor Corporate Center
Suite 250, 100 Matsonford Road
Radnor, Pennsylvania 19087
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number: (610) 995-9400
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: Common Stock-- $.50
par value and related Rights
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes __X__ No ____
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X].
As of November 22, 1999, there were 2,342,629 shares of the
registrant's Common Stock ($.50 par value) outstanding. The aggregate market
value of voting stock held by non-affiliates of the registrant as of such date
was $30,605,477 (1,820,346 shares at $16.813 per share).
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the 2000 Annual Meeting of
Stockholders are incorporated by reference in Items 10, 11, 12 and 13
CASTLE ENERGY CORPORATION
1999 FORM 10-K
TABLE OF CONTENTS
Item Page
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PART I
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1. and 2. Business and Properties..................................... 1
3. Legal Proceedings........................................... 5
4. Submission of Matters to a Vote of Security Holders......... 8
PART II
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5. Market for the Registrant's Common Equity and Related
Stockholder Matters......................................... 9
6. Selected Financial Data..................................... 9
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations......................... 11
8. Financial Statements and Supplementary Data.................. 27
PART III
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9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure........................... 59
10. Directors and Executive Officers of the Registrant............ 59
11. Executive Compensation........................................ 59
12. Security Ownership of Certain Beneficial Owners and
Management.................................................... 59
13. Certain Relationships and Related Transactions................ 59
PART IV
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14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K..................................................... 60
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
INTRODUCTION
All statements other than statements of historical fact contained in
this report are forward-looking statements. Forward-looking statements in this
report generally are accompanied by words such as "anticipate," "believe,"
"estimate," or "expect" or similar statements. Although the Company believes
that the expectations reflected in such forward-looking statements are
reasonable, no assurance can be given that such expectations will prove correct.
Factors that could cause the Company's results to differ materially from the
results discussed in such forward-looking statements are disclosed in this
report, including without limitation in conjunction with the expected cash
sources and expected cash obligations discussed below. All forward-looking
statements in this Form 10-K are expressly qualified in their entirety by the
cautionary statements in this paragraph. Furthermore, this statement constitutes
a Year 2000 Readiness Disclosure Statement and the statements contained herein
are subject to the Year 2000 Information and Readiness Disclosure Act ("Act").
In case of a dispute, this document and information contained herein are
entitled to protection of the Act.
Castle Energy Corporation (the "Company") is currently engaged in oil
and gas exploration and production in the United States and Romania. References
to the Company mean Castle Energy Corporation, the parent, and/or its
subsidiaries. Such references are for convenience only and are not intended to
describe legal relationships. During the period from August of 1989 through
September 30, 1995, the Company, through certain subsidiaries, was primarily
engaged in petroleum refining. Indian Refining I Limited Partnership (formerly
Indian Refining Limited Partnership) ("IRLP"), an indirect wholly-owned
subsidiary of the Company, owned the Indian Refinery, an 86,000 barrel per day
(B/D) refinery located in Lawrenceville, Illinois ("Indian Refinery"). Powerine
Oil Company ("Powerine"), a former indirect wholly-owned subsidiary of the
Company, owned and operated a 49,500 B/D refinery located in Santa Fe Springs,
California ("Powerine Refinery"). By September 30, 1995, the Company's refining
subsidiaries had terminated and discontinued all of their refining operations.
For accounting purposes, refining operations were classified as discontinued
operations in the Company's Consolidated Financial Statements as of September
30, 1995 (see Note 3 to the consolidated financial statements included in Item 8
of this Form 10-K).
During the period from December 31, 1992 to May 31, 1999, the Company,
through three of its subsidiaries, was also engaged in natural gas marketing and
transmission operations. During this period one of the Company's subsidiaries
sold natural gas to Lone Star Gas Company ("Lone Star") under a long-term gas
sales contract. The subsidiaries also entered into two long-term gas sales
contracts and one long-term gas supply contract with MG Natural Gas Corp.
("MGNG"), a subsidiary of MG Corp. ("MG"), whose parent is Metallgesellschaft
A.G. ("MGAG"), a large German conglomerate. All of the subsidiaries' gas
contracts terminated on May 31, 1999. The Company has not replaced these
contracts because it sold its pipeline assets to a subsidiary of UPRC in May
1997 and because it is unlikely that similar profitable long-term contracts can
be negotiated since most gas purchasers buy gas on the spot market. Although the
Company is currently seeking additional natural gas marketing operations, it is
currently operating exclusively in the exploration and production segment of the
energy industry.
Since inception to the present the Company continues to operate in the
exploration and production business. During the fiscal year ended September 30,
1999, the Company invested $23,964,000 in oil and gas property acquisition,
exploration and development including $934,000 in Romania. In addition, the
Company entered into two drilling joint ventures to drill up to 16 new wells in
South Texas over the next two years. The Company also expects to drill 2-3 new
wells in Romania over the next 18 months. The Company is currently evaluating
several other possible acquisitions of oil and gas assets and oil and gas
companies. As of September 30, 1999, the Company's exploration and production
subsidiaries owned interests in 507 producing oil and gas wells located in ten
states. The subsidiaries operate approximately half of the wells. At September
30, 1999, the Company's exploration and production assets included proved
reserves of approximately 28.4 billion cubic feet of natural gas and
approximately 2,030,000 barrels of oil.
In October 1996, the Company commenced a program to repurchase shares of
its common stock at stock prices beneficial to the Company. At November 22,
1999, 4,486,017 shares representing approximately 66% of previously outstanding
shares had been repurchased and the Company's Board of Directors has authorized
the purchase of up to 263,983 additional shares.
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OIL AND GAS EXPLORATION AND PRODUCTION
General
The Company's oil and gas exploration and production business is
currently conducted through Castle Exploration Company, Inc. ("CECI"), a
wholly-owned subsidiary, and Petroleum Reserve Corporation ("PRC"), a division
of the Company. From December 3, 1992 to May 30, 1997 Castle Texas Production
Limited Partnership ("Production"), one of the Company's exploration and
production subsidiaries, owned and operated approximately 115 oil and gas wells
in Rusk County, Texas. On May 30, 1997, Production sold these wells and related
undrilled acreage to Union Pacific Resources Company ("UPRC").
On June 1, 1999, CECI consummated the purchase of the oil and gas
properties of AmBrit Energy Corp. ("AmBrit"). The oil and gas properties
purchased included interests in approximately 180 oil and gas properties in
Alabama, Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Texas and
Wyoming, as well as undrilled acreage in several of these states. The production
from the oil and gas properties acquired from AmBrit increased the Company's
consolidated production by approximately 425%. The oil and gas reserves acquired
approximated 150% of the Company's oil and gas reserves before the acquisition.
Subsequent to September 30, 1999, CECI acquired additional outside
interests in several Alabama wells which it operates for $372,000. In addition,
CECI entered into three agreements to acquire additional oil and gas interests
in operated wells in Alabama and in non-operated wells in Pennsylvania and to
acquire a majority interest in twenty-six (26) offshore Louisiana wells. The
adjusted purchase price for these acquisitions, assuming closings as planned, is
expected to approximate $3,075,000. The interests in the Louisiana offshore
wells, assuming the anticipated purchase is consummated, will be the Company's
first investment in offshore wells. As of September 30, 1999, all of the wells
in which the Company has an interest were onshore.
Properties
Proved Oil and Gas Reserves
The following is a summary of the Company's oil and gas reserves as of
September 30, 1999. All estimates of reserves are based upon engineering
evaluations prepared by the Company's independent petroleum reservoir engineers,
Huntley & Huntley and Ralph E. Davis Associates, Inc., in accordance with the
requirements of the Securities and Exchange Commission. Such estimates include
only proved reserves. The Company reports its reserves annually to the
Department of Energy. The Company's estimated reserves as of September 30, 1999
were as follows:
Net MCF(1) of gas:
Proved developed....................................... 23,547,000
Proved undeveloped..................................... 4,855,000
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Total.................................................. 28,402,000
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Net barrels of oil:
Proved developed....................................... 1,788,000
Proved undeveloped..................................... 242,000
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Total.................................................. 2,030,000
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(1) Thousand cubic feet
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Oil and Gas Production
The following table summarizes the net quantities of oil and gas
production of the Company for each of the three fiscal years in the period ended
September 30, 1999, including production from acquired properties since the date
of acquisition.
Fiscal Year Ended September 30,
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1999 1998 1997
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Oil -- Bbls (barrels).............................................. 124,000 20,000 36,000
Gas -- MCF......................................................... 1,971,000 869,000 2,454,000
Average Sales Price and Production Cost Per Unit
The following table sets forth the average sales price per barrel of oil
and MCF of gas produced by the Company and the average production cost (lifting
cost) per equivalent unit of production for the periods indicated. Production
costs include applicable operating costs and maintenance costs of support
equipment and facilities, labor, repairs, severance taxes, property taxes,
insurance, materials, supplies and fuel consumed in operating the wells and
related equipment and facilities.
Fiscal Year Ended September 30,
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1999 1998 1997
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Average Sales Price per Barrel of Oil................................... $18.36 $15.46 $19.94
Average Sales Price per MCF of Gas...................................... $ 2.25 $ 2.38 $ 2.46
Average Production Cost per Equivalent MCF(1)........................... $ .88 $ 0.78 $ .73
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(1) For purposes of equivalency of units, a barrel of oil is assumed equal to
six MCF of gas, based upon relative energy content.
The average sales price per barrel of crude oil increased $.11 per
barrel for the year ended September 30, 1999 as a result of hedging. The average
sales price per mcf (thousand cubic feet) of natural gas decreased $.07 for the
year ended September 30, 1999. Oil and gas sales were not hedged in fiscal 1998
and 1997.
Productive Wells and Acreage
The following table presents the oil and gas properties in which the
Company held an interest as of September 30, 1999. The wells and acreage owned
by the Company and its subsidiaries are located primarily in Alabama,
California, Illinois, Louisiana, Mississippi, New Mexico, Montana, Oklahoma,
Pennsylvania and Wyoming.
As of
September 30, 1999
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Gross(2) Net (3)
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Productive Wells:(1)
Gas Wells.................................. 411 128
Oil Wells.................................. 96 46
Acreage:
Developed Acreage.......................... 124,491 24,637
Undeveloped Acreage........................ 86,564 31,077
In addition, one of the Company's subsidiaries has a fifty percent
interest in approximately 3,100,000 gross undeveloped acres in Romania
(1,550,000 net acres).
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(1) A "productive well" is a producing well or a well capable of production.
Sixty-four wells are dual wells producing oil and gas. Such wells are
classified according to the dominant mineral being produced.
(2) A gross well or acre is a well or acre in which a working interest is owned.
The number of gross wells is the total number of wells in which a working
interest is owned.
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(3) A net well or acre is deemed to exist when the sum of fractional working
interests owned in gross wells or acres equals one. The number of net wells
or acres is the sum of the fractional working interests owned in gross wells
or acres.
Drilling Activity
The table below sets forth for each of the three fiscal years in the
period ended September 30, 1999 the number of gross and net productive and dry
developmental wells drilled including wells drilled on acquired properties since
the dates of acquisition. No exploratory wells were drilled during the periods
presented.
Fiscal Year Ended September 30,
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1999 1998 1997
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Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- ---
Developmental:
Gross.................................. 5 3 23.0 -- 3.0 --
Net.................................... 2.3 1.2 15.2 -- 1.4 --
The Company is currently participating in a twelve well exploratory
drilling venture in South Texas, another four well exploratory drilling program
also in South Texas, an Appalachian drilling program in Western Pennsylvania and
a wildcat drilling program in Romania, where a subsidiary of the Company owns
fifty percent (50%) of a drilling concession granted by the Romanian government.
Subsequent to September 30, 1999, CECI also acquired additional outside
interests in several Alabama wells it operates for $372,000. In addition, CECI
has entered into agreements to acquire additional oil and gas interests in
operated wells in Alabama and Pennsylvania and to acquire majority interests in
twenty-six wells in offshore Louisiana, including 18 non-producing wells. See
Note 22 to the consolidated financial statements included in Item 8 to this Form
10-K.
REGULATIONS
Since the Company's subsidiaries have disposed of their refineries and
third parties have assumed environmental liabilities associated with the
refineries, the Company's current activities are not subject to environmental
regulations that generally pertain to refineries, e.g., the generation,
treatment, storage, transportation and disposal of hazardous wastes, the
discharge of pollutants into the air and water and other environmental laws.
Nevertheless, the Company has some contingent environmental exposures. See Items
3 and 7 and Note 12 to the consolidated financial statements included in Item 8.
of this Form 10-K.
The oil and gas exploration and production operations of the Company are
subject to a number of local, state and federal environmental laws and
regulations. To date, compliance with such regulations by the Company's natural
gas marketing and transmission and exploration and production subsidiaries has
not resulted in material expenditures.
Most states in which the Company conducts oil and gas exploration and
production activities have laws regulating the production and sale of oil and
gas. Such laws and regulations generally are intended to prevent waste of oil
and gas and to protect correlative rights and opportunities to produce oil and
gas as between owners of interests in a common reservoir. Some state regulatory
authorities also regulate the amount of oil and gas produced by assigning
allowable rates of production to each well or unit. Most states also have
regulations requiring permits for the drilling of wells and regulations
governing the method of drilling, casing and operating wells, the surface use
and restoration of properties upon which wells are drilled and the plugging and
abandonment of wells. In recent years there has been a significant increase in
the amount of state regulation, including increased bonding, plugging and
operational requirements. Such increased state regulation has resulted in, and
is anticipated to continue to result in, increased legal and compliance costs
being incurred by the Company. Based on past costs and even considering recent
increases, management of the Company does not believe such legal and compliance
costs will have a material adverse effect on the financial condition or results
of operations of the Company although compliance issues continue to absorb an
increasing percentage of management's time. If the Company consummates its
acquisition of twenty-six (26) offshore Louisiana wells, as planned, it
anticipates its environmental and plugging and abandonment costs may increase
significantly. Seventeen of the wells to be acquired are temporarily abandoned
or shut in and will eventually have to be returned to production or plugged and
abandoned.
The Company is also subject to various state and Federal laws regarding
environmental and ecological matters because it acquires, drills and operates
oil and gas properties. To alleviate the environmental risk the Company carries
$25,000,000
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of liability insurance and $3,000,000 of special operator's extra expense
(blowout) insurance for wells it drills. Such insurance covers sudden and
accidental pollution. Although management believes that its current insurance
coverage is adequate, management is obtaining additional property and operator's
extra expense insurance coverage for the twenty-six offshore Louisiana wells it
expects to acquire because the property and environmental exposure for such
offshore wells is considerably greater than that for similar onshore wells. At
the present time, all of the Company's wells are onshore.
EMPLOYEES AND OFFICE FACILITIES
As of November 22, 1999, the Company, through its subsidiaries, employed
27 personnel. Until June 30, 1998, the Company outsourced all of its
administrative, land and accounting functions. Effective July 1, 1998, the
Company exercised its option to acquire the computer equipment and software of
the company providing the outsourcing services and also hired most of that
company's employees. As a result the Company now performs all administrative,
land and accounting functions in-house. The Company also recently established an
Oklahoma City office and entered into a service agreement providing for legal
and land services.
The Company leases certain offices as follows:
Office Location Function
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Radnor, PA Corporate Headquarters
Plymouth Meeting, PA Accounting Office
Mt. Pleasant, PA Oil and Gas Production Office
Pittsburgh, PA Drilling and Exploration Office
Tuscaloosa, Alabama Gas Production Office
Oklahoma City, Oklahoma Land and Legal
ITEM 3. LEGAL PROCEEDINGS
Contingent Environmental Liabilities
In December 1995, IRLP sold the Indian Refinery to American Western
Refining Limited Partnership ("American Western"), an unaffiliated party. As
part of the related purchase and sale agreement, American Western assumed all
environmental liabilities and indemnified IRLP with respect thereto.
Subsequently American Western filed for bankruptcy and sold the Indian Refinery
to an outside party pursuant to a bankruptcy proceeding. The new owner is
currently dismantling the Indian Refinery.
During fiscal 1998, the Company was also informed that the United States
Environmental Protection Agency ("EPA") has investigated offsite acid sludge
waste found near the Indian Refinery and was also investigating and remediating
surface contamination in the Indian Refinery property. Neither the Company nor
IRLP was initially named with respect to these two actions.
In October 1998, the EPA named the Company and two of its refining
subsidiaries as potentially responsible parties for the expected clean-up of the
Indian Refinery. In addition, eighteen other parties were named including Texaco
Refining and Marketing, Inc., the refinery operator for over 50 years. The
Company subsequently responded to the EPA indicating that it was neither the
owner nor operator of the Indian Refinery and thus not responsible for its
remediation.
In November 1999, the Company received a request for information from
the EPA concerning the Company's involvement in the ownership and operation of
the Indian Refinery. The Company expects that it will respond to the EPA
information request during the second quarter of fiscal 2000.
In September 1995, Powerine sold the Powerine Refinery to Kenyen
Resources ("Kenyen"), an unaffiliated party. In January 1996, Powerine merged
into a subsidiary of Energy Merchant Corp. ("EMC"), an unaffiliated party, and
EMC assumed all environmental liabilities. In August 1998, EMC sold the Powerine
Refinery to a third party which is seeking financing to restart the Powerine
Refinery. In July of 1996, the Company was named a defendant in a class action
lawsuit concerning emissions from the Powerine Refinery. In April of 1997, the
court granted the Company's motion to quash the plaintiff's summons based upon
lack of jurisdiction and the Company is no longer involved in the case.
Although the environmental liabilities related to the Indian Refinery
and Powerine Refinery have been transferred to others, there can be no assurance
that the parties assuming such liabilities will be able to pay them. American
Western, owner
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of the Indian Refinery, filed for bankruptcy and is in the process of
liquidation. EMC, which assumed the environmental liabilities of Powerine, sold
the Powerine Refinery to an unrelated party, which we understand is still
seeking financing to restart that refinery. Furthermore, as noted above, the EPA
named the Company as a potentially responsible party for remediation of the
Indian Refinery and has requested relevant information from the Company.
Estimated gross undiscounted clean up costs for this refinery are $80,000,000 -
$150,000,000 according to third parties. If the Company were found liable for
the remediation of the Indian Refinery, it could be required to pay a percentage
of the clean-up costs. Since the Company's subsidiary only operated the Indian
Refinery five years, whereas Texaco and others operated it over fifty years, the
Company would expect that its share of remediation liability would be
proportional to its years of operation, although such may not be the case.
An opinion issued by the U.S. Supreme Court in June 1998 in a comparable
matter supports the Company's position. Nevertheless, if funds for environmental
clean-up are not provided by these former and/or present owners, it is possible
that the Company and/or one of its former refining subsidiaries could be named a
party in additional legal actions to recover remediation costs. In recent years,
government and other plaintiffs have often sought redress for environmental
liabilities from the party most capable of payment without regard to
responsibility or fault. Whether or not the Company is ultimately held liable in
such a circumstance, should litigation involving the Company and/or IRLP occur,
the Company would probably incur substantial legal fees and experience a
diversion of management resources from other operations.
Although the Company does not believe it is liable for any of its
subsidiaries' clean-up costs and intends to vigorously defend itself in such
regard, the Company cannot predict the ultimate outcome of these matters due to
inherent uncertainties.
General
Powerine Arbitration
In June 1997, an arbitrator ruled in the Company's favor in an
arbitration hearing concerning a contract dispute between MGNG and Powerine
which had been assigned to the Company. In October 1997, the Company recovered
$8,700,000 from the arbitration and sought an additional $2,142,000 plus
interest. In January 1999, the Company recovered $900,000 in connection with the
$2,142,000 sought.
Rex Nichols et al Lawsuit
In March of 1998, the Company, one of its subsidiaries and one of its
officers were sued by two outside interest owners owning interests in several
wells formerly operated by one of the Company's exploration and production
subsidiaries. The lawsuit was filed in the Fourth Judicial District of Rusk
County, Texas.
The lawsuit, as initially filed, sought unspecified net production
revenues resulting from reversionary interests on several wells formerly
operated by the Company's subsidiary. Management believes the Company's exposure
on the matter, if any, is less than $50,000.
Subsequently, the plaintiffs expanded their petition claiming amounts
due in excess of $250,000 based upon their interpretation of other provisions of
the underlying oil and gas leases. The case is currently in discovery and no
date has been set for a trial. Management believes that the plaintiffs
additional claims are without merit and intends to vigorously defend its
position.
SWAP Agreement - MGNG
In January 1998, IRLP filed suit against MG Refining and Marketing, Inc.
("MGR&M"), a subsidiary of MG, to collect $704,000 plus interest. The dispute
concerned funds owed to IRLP but not paid by MGR&M. In February 1998, MG
contended that the $704,000 was not owed to IRLP and that it had liquidated
MGR&M. In April 1999, IRLP recovered $575,000 of the $704,000 sought. The
difference between the book value, $704,000 and the actual recovery, $575,000
was recorded as a reduction in the value of discontinued net refining assets
since the recovery relates to IRLP's discontinued refining operations (See Note
3 to the consolidated financial statements included in Item 8 of this Form
10-K.)
Powerine/EMC/Litigation
In July 1998, the Company sued Powerine and EMC to recover $330,000 plus
interest. The amount sought represented amounts that Powerine or EMC were
required to pay to the Company under the January 1996 purchase and sale
agreement whereby Powerine merged into a subsidiary of EMC. In April 1999, the
Company recovered $355,000 from EMC. The recovery was recorded as other income.
-6-
Larry Long Litigation
In May 1996, Larry Long, representing himself and allegedly "others
similarly situated," filed suit against the Company, three of the Company's
natural gas marketing and transmission and exploration and production
subsidiaries, Atlantic Richfield Company ("ARCO"), B&A Pipeline Company, a
former subsidiary of ARCO ("B&A"), and MGNG in the Fourth Judicial District
Court of Rusk County, Texas. The plaintiff originally claimed, among other
things, that the defendants underpaid non-operating working interest owners,
royalty interest owners, and overriding royalty interest owners with respect to
gas sold to Lone Star pursuant to the Lone Star Contract. Although no amount of
actual damages was specified in the plaintiff's initial pleadings, it appeared
that, based upon the volumes of gas sold to Lone Star, the plaintiff may have
been seeking actual damages in excess of $40,000,000.
After some initial discovery, the plaintiff's pleadings were
significantly amended. Another purported class representative, Travis Crim, was
added as a plaintiff, and ARCO, B&A and MGNG were dropped as defendants.
Although it is not completely clear from the amended petition, the plaintiffs
have apparently now limited their proposed class of plaintiffs to royalty owners
and overriding royalty owners in leases owned by the Company's exploration and
production subsidiary limited partnership. In amending their pleadings, the
plaintiffs revised their basic claim to seeking royalties on certain operating
fees paid by Lone Star to the Company's natural gas marketing subsidiary limited
partnership. No hearing has been held on the plaintiffs' request for class
certification. After a lengthy period of inactivity the plaintiff's counsel has
recently sought to continue or settle the case. At present no class has been
certified and no trial date set.
Based upon the revised pleadings, management of the Company initially
determined that the worst possible exposure for the Company and its subsidiary
limited partnerships for all gas sold to Lone Star, were they to lose the case
on all points, was less than $3,000,000. However, the Company sold all of its
Rusk County oil and gas properties to UPRC in May of 1997. The sale to UPRC
effectively removed any possibility of exposure by the Company or its subsidiary
limited partnerships to claims for additional royalties with respect to
production after May 1997, thus reducing the exposure to the Company and its
subsidiaries to less than $2,000,000 in actual damages if they were to lose the
case on all points. Although the Company believes that the plaintiff's claims
are without merit and intends to continue to vigorously defend itself in this
matter, the Company cannot predict the ultimate outcome.
MGNG Litigation
On May 4, 1998, Production filed a lawsuit against MGNG and MG
Gathering Company ("MGC"), two subsidiaries of MG, in the district court of
Harris County, Texas. Production seeks to recover gas measurement and
transportation expenses charged by the defendants in breach of a certain gas
purchase contract. Improper charges exceed $750,000 before interest. In October
of 1998, MGNG and MGC filed a suit in Harris County, Texas. This suit seeks
indemnification from two of the Company's subsidiaries in the event Production
wins its lawsuit against MGNG and MGC. The MG entities have cited no basis for
their claim of indemnification. The management of the Company and special
counsel retained by the Company believe that the Company's subsidiary is
entitled to at least $750,000 plus interest and that the Company's two
subsidiaries have no indemnification obligations to MGNG or MGC. The Company is
pursuing this case using all legal remedies. The parties participated in
mediation but were not able to resolve the issue. The case is expected to be
scheduled for trial in May 2000. UPRC, to whom the Company sold its Rusk County,
Texas oil and gas properties, has also informed the Company that it intends to
sue MGNG on the same transportation expense issue.
On October 6, 1999, MGNG filed a second lawsuit against the Company and
three of its subsidiaries claiming $772,000 was owed to MGNG under a gas supply
contract between one of the Company's subsidiaries and MGNG. The suit was filed
in the district court of Harris County, Texas. The Company and its subsidiaries
believe that they do not owe $772,000 and that they are entitled to offset some
or all of the $772,000 claimed against amounts owed to Production by MGNG for
improper gas measurement and transportation deductions. The Castle entities have
answered this suit denying MGNG claims based partially on the legal right of
offset.
Pilgreen Litigation
As part of the AmBrit purchase, CECI acquired a 10.65% overriding
royalty interest ("ORRI") in the Pilgreen #2ST gas well in Texas. Because of
title disputes, AmBrit and other interest owners had previously filed claims
against the operator of the Pilgreen well, and CECI acquired post January 1,
1999 rights in that litigation. Although revenue attributed to the ORRI has been
suspended by the operator since first production, because of recent related
appellate decisions and settlement
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negotiations, the Company believes that revenue attributable to the ORRI should
be released to CECI in the second quarter of fiscal 2000. As of September 30,
1999, approximately $124,000 attributable to CECI's share of the ORRI revenue
was suspended.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company did not hold a meeting of stockholders or otherwise submit
any matter to a vote of stockholders during the fourth quarter of fiscal 1999.
-8-
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Principal Market
The Company's Common Stock is quoted on the Nasdaq National Market
("NNM") under the trading symbol "CECX."
Stock Price and Dividend Information
Stock Price:
The table below presents the high and low sales prices of the Company's
Common Stock as reported by the NNM for each of the quarters during the two
fiscal years ended September 30, 1999.
1999 1998
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High Low High Low
--------- ------ ---------- --------
First Quarter (December 31).................................. $19.38 $16.88 $15.06 $12.75
Second Quarter (March 31).................................... $17.88 $15.75 $18.00 $13.50
Third Quarter (June 30)...................................... $19.25 $15.00 $20.63 $17.50
Fourth Quarter (September 30)................................ $18.25 $16.50 $19.69 $16.50
The final sale of the Company's Common Stock as reported by the NNM on
November 22, 1999 was at $16.81.
Dividends:
On June 30, 1997, the Company's Board of Directors adopted a policy of
paying regular quarterly cash dividends of $.15 per share on the Company's
common stock. Commencing July 15, 1997, dividends have been paid quarterly. As
with any company the declaration and payment of future dividends are subject to
the discretion of the Company's Board of Directors and will depend on various
factors.
Approximate Number of Holders of Common Stock
As of November 22, 1999, the Company's Common Stock was held by
approximately 3,000 stockholders.
ITEM 6. SELECTED FINANCIAL DATA
During the five fiscal years ended September 30, 1999, the Company
consummated a number of transactions affecting the comparability of the
financial information set forth below. In August 1989, IRLP acquired the Indian
Refinery. From April 1990 until September 30, 1995, IRLP, operated the Indian
Refinery. In December 1992, three of the Company's subsidiaries acquired certain
oil and gas and pipeline assets from ARCO. In October 1993, one of the Company's
subsidiaries acquired Powerine, which owned the Powerine Refinery. During fiscal
1995, both refineries ceased operations and the Company's refining subsidiaries
reached a settlement with MG and its affiliates and terminated most of their
transactions and relationships with MG. By September 1995, the Company's
refining subsidiaries had discontinued all their refining operations. In May
1997, the Company sold its Rusk County, Texas oil and gas properties and
pipeline to UPRC and one of its subsidiaries. In June 1999, CECI acquired all of
the oil and gas assets of AmBrit. See Item 7 - "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and Note 4 to the
Company's consolidated financial statements included in Item 8 of this Form
10-K.
The following selected financial data have been derived from the
Consolidated Financial Statements of the Company for each of the five years
ended September 30, 1999. Certain information in the Consolidated Statements of
Operations has been reclassified to give effect to the discontinuance of
refining operations. The information should be read in conjunction with the
consolidated financial statements and notes thereto included in Items 8 of this
Form 10-K.
-9-
Earnings per share have been retroactively restated in accordance with
SFAS 128.
For the Fiscal Years Ended September 30,
----------------------------------------------------------------
(in Thousands, except per share amounts)
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
Revenues:
Natural gas marketing and transmission............. $50,067 $70,001 $ 64,606 $ 59,471 $ 70,402
Exploration and production......................... 7,190 2,603 7,113 9,224 9,197
Gross Margin:
Natural gas marketing and transmission............. 19,005 26,747 24,640 25,238 30,242
Exploration and production......................... 4,802 1,828 5,173 7,179 6,831
Earnings before interest, taxes, depreciation, and
amortization:
Natural gas marketing and transmission............. 17,847 25,162 23,054 23,162 28,252
Exploration and production......................... 3,764 836 4,036 5,944 5,761
Corporate general and administrative expenses.......... (4,112) (3,081) (3,370) (3,499) (4,995)
Depreciation, depletion and amortization............... (8,330) (9,885) (12,250) (13,717) (14,155)
Interest expense....................................... (2) (1,038) (1,959) (4,046)
Interest income and other income....................... 2,053 2,230 21,097(1) 3,884 966
------- ------- -------- -------- ---------
Income from continuing operations before income
taxes.............................................. 11,222 15,260 31,529 13,815 11,783
Provision for (benefit of) income taxes related to
continuing operations.............................. 2,956 1,204 4,663 (11,259) 37,823
------- ------- -------- -------- ---------
Income (loss) from continuing operations .............. 8,266 14,056 26,866 25,074 (26,040)
Income from discontinued refining operations net of
applicable income taxes............................ 40,937
------- ------- -------- -------- ---------
Net income............................................. $ 8,266 $14,056 $ 26,866 $ 25,074 $ 14,897
======= ======= ======== ======== =========
Dividends.............................................. $ 2,048 $ 1,688 $ 1,446
======= ======= ========
Net income (loss) per share (diluted):
Continuing operations.............................. $ 2.97 $ 3.66 $ 4.64 $ 3.73 ($ 3.84)
Discontinued operations............................ 6.04
------- ------- -------- -------- ---------
$ 2.97 $ 3.66 $ 4.64 $ 3.73 $ 2.20
======= ======= ======== ======== =========
Dividends per share.................................... $ .75 $ .45 $ .30
======= ======= ========
Balance Sheet Data:
Working capital (deficit)........................... $26,489 $40,271 $ 46,384 ($ 4,452) ($ 12,474)
Property, plant and equipment, net, including oil
and gas properties............................... 26,985 4,969 2,998 36,223 40,406
Total assets........................................ 60,363 67,004 82,717 101,230 116,904
Long-term debt, including current maturities........ 14,006 35,946
Stockholders' equity................................ 53,503 51,553 67,765 66,711 41,637
- -------------
(1) Includes a $19,667 non-recurring gain on sale of assets.
-10-
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
("000's" Omitted Except Share Amounts)
- --------------------------------------------------------------------------------
RESULTS OF OPERATIONS
GENERAL
From August 1989 to September 30, 1995, two of the Company's
subsidiaries conducted refining operations. By December 12, 1995, the Company's
refining subsidiaries had sold all of their refining assets. In addition,
Powerine merged into a subsidiary of EMC and was no longer a subsidiary of the
Company. The Company's other refining subsidiary, IRLP, owns no refining assets
and is in the process of liquidation. As a result, the Company has accounted for
its refining operations as discontinued operations in the Company's financial
statements as of September 30, 1995 and retroactively. Accordingly, discussion
of results of operations has been confined to the results of continuing
operations and the anticipated impact, if any, of liquidation of the Company's
remaining inactive refining subsidiary and contingent environmental liabilities
of the Company or its refining subsidiaries.
As noted above, the Company sold its Rusk County, Texas oil and gas
properties and pipeline to UPRC and its subsidiary, respectively, in May 1997.
The oil and gas reserves sold approximated 84% of the Company's proved oil and
gas reserves at the date of sale. As a result operations applicable to the
assets sold impacted consolidated operations for eight months in fiscal 1997 and
not at all thereafter.
Also, as noted above, CECI acquired the oil and gas properties of AmBrit
on June 1, 1999. The oil and gas reserves associated with the acquisition were
estimated at approximately 12.5 billion cubic feet of natural gas and 2,000
barrels of crude oil or roughly 150% of the reserves owned by the Company before
the acquisition. Furthermore, as a result of the acquisition, the Company's
production of oil and gas increased by approximately 425%. This acquisition
impacted consolidated operations for the last four months of fiscal 1999 only.
Gas sales and purchases ceased effective May 31, 1999 by virtue of the
scheduled termination of its subsidiaries' gas sales and gas purchase contracts
with Lone Star and MGNG. The Company has not replaced these contracts because it
sold its pipeline assets to a subsidiary of UPRC in May 1997 and because it is
unlikely that similar profitable long-term contracts can be negotiated since
most gas purchasers buy gas on the spot market. Although the Company is
currently seeking additional natural gas marketing operations, it is currently
operating exclusively in the exploration and production segment of the energy
industry.
As a result natural gas marketing operations impacted consolidated operations
for all of fiscal 1997 and fiscal 1998 but only the first eight months of fiscal
1999.
Fiscal 1999 vs Fiscal 1998
NATURAL GAS MARKETING
Gas sales from natural gas marketing decreased $19,934 or 28.5% from
fiscal 1998 to 1999. Gas sales in each fiscal year consist of the following:
September 30,
----------------------
1999 1998
---- ----
Gas sales to Lone Star.......................... $46,802 $64,619
Gas sales to MGNG............................... 3,265 4,904
Gas sales to third parties...................... 478
------- -------
$50,067 $70,001
======= =======
-11-
Gas sales to Lone Star and MGNG decreased from fiscal 1999 to fiscal
1998 because both of the relevant gas sales contracts terminated May 31, 1999 by
their own terms. The natural gas volumes sold during the period October 1, 1998
to May 31, 1999 were the remaining contractual volumes required under the
related long-term gas sales contracts with Lone Star and MGNG. The gas prices
received by the Company's natural gas marketing subsidiary were essentially
fixed both years so that the decreases in sales under both the Lone Star
Contract and the contract with MGNG were caused by decreased volumes delivered.
Gas Purchases
Gas purchases decreased $12,192 or 28.2% from fiscal 1998 to fiscal
1999. Gas purchases in each of the fiscal years consist of the following:
September 30
--------------------
1999 1998
---- ----
Gas purchases - Lone Star Contract............. $27,277 $36,898
Gas purchases - MGNG Contract.................. 3,785 5,897
Gas purchases - sales to third parties......... 459
------- -------
$31,062 $43,254
======= =======
Gas purchases decreased because the related long-term gas supply
contracts with MGNG terminated and the Company ceased buying gas supplies on the
spot market on May 31, 1999, the same day that the Lone Star Contract
terminated. The gas price paid by the Company under such long-term gas supply
agreement with MGNG was essentially fixed for approximately ninety percent (90%)
of volumes purchased . The gas price paid for the remaining ten percent (10%) of
gas supplies was based upon a market index price. The gross margin percentage
(natural gas purchases as a percentage of natural gas sales) was essentially the
same both years - 61.9% in fiscal 1999 and 61.8% in fiscal 1998.
General and Administrative
General and administrative costs decreased $27 from $62 for the year
ended September 30, 1998 to $35 for the year ended September 30, 1999. The
decrease was attributable to the termination of a natural gas hedging consulting
arrangement on May 31, 1999, the date the Company's long-term gas contracts
terminated.
Transportation
Transportation expense decreased $416 or 27% from $1,539 for the year
ended September 30, 1998 to $1,123 for the year ended September 30, 1999.
Transportation expense is based upon and thus proportional to deliveries made to
Lone Star and represents the amortization of a $3,000 prepaid transportation
asset received by one of the Company's subsidiaries in the sale of the Castle
Pipeline to a subsidiary of UPRC in May 1997. Deliveries to Lone Star were
approximately 37% greater during the year ended September 30, 1998 than during
the year ended September 30, 1999 because deliveries to Lone Star ceased on May
31, 1999. By May 31, 1999, the $3,000 allocated to prepaid transportation had
been completely amortized.
Amortization
Amortization of gas contracts decreased $3,178 or 33.6% from fiscal 1998
to fiscal 1999. The decrease is entirely attributable to the termination of the
Lone Star Contract on May 31, 1999. For fiscal 1998 twelve months' of
amortization are included in operations versus only eight months of amortization
in fiscal 1999.
Both the Lone Star Contract and the MGNG Contract expired May 31, 1999.
During the year ended September 30, 1999, the operating income from these
contracts was $11,563 or 126.1% of consolidated operating income. For the year
ended September 30, 1998, the operating income from these contracts was $15,700
or approximately 120.5% of consolidated operating income for the period. The
Company has not replaced these contracts because it sold its pipeline assets to
a subsidiary of UPRC in May 1997 and because it is unlikely that similar
profitable long-term contracts can be negotiated since most gas purchasers buy
gas on the spot market. Although the Company is currently seeking additional
natural gas marketing operations, it is currently operating exclusively in the
exploration and production segment of the energy industry.
-12-
The Company is currently seeking to replace some or all of the operating
income contribution of its former natural gas marketing operations with
operating income from additional exploration and production properties and other
energy assets. In that respect, the Company acquired the oil and gas assets of
AmBrit, has entered into two drilling ventures in South Texas and has acquired a
50% interest in a drilling concession in Romania. In addition, subsequent to
September 30, 1999, the Company acquired outside interests in wells it operates
for $372 and entered into agreements to acquire other oil and gas properties
(see above and Note 22 included in the consolidated financial statements
included in Item 8 of this Form 10-K.) The Company is also currently reviewing
several other possible exploration and production, pipeline and natural gas
marketing acquisitions. There can, however, be no assurance the Company will
succeed in these efforts.
EXPLORATION AND PRODUCTION
On June 1, 1999, the Company purchased all of AmBrit's oil and gas
properties for $20,170 net of purchase price adjustments. AmBrit's oil and gas
properties consist primarily of proved developed producing reserves. The current
production from the AmBrit properties is approximately 425% that of the
Company's other properties. In addition, the oil and gas reserves associated
with the acquisition are estimated to be approximately 150% of the Company's
other reserves. Therefore, as a result of this acquisition, the Company's
exploration and production operations have increased significantly since June 1,
1999. In order to facilitate comparisons of financial data we have separately
disclosed changes applicable to the acquisition of the AmBrit properties and
those applicable to the Company's other exploration and production operations.
The results are as follows:
Less Amounts
Applicable Effect Of
To Acquisition Non AmBrit Properties Change
of AmBrit ----------------------------------- On
Consolidated Properties Year Ended Operating
Year Ended June 1, 1999- September 30, Year Ended Income:
September 30, September 30, 1999 as September 30, Increase
1999 1999 Adjusted 1998 (Decrease)
------------------- -------------------- ------------------- --------------- ----------
Revenues
- --------
Oil and gas sales.............. $6,712 $3,943 $2,769 $2,373 $396
Well operations................ 478 126 352 230 122
-------- -------- -------- ------- -----
7,190 4,069 3,121 2,603 518
Expenses
- --------
Oil and gas.................... (2,388) (1,438) (950) (775) (175)
General and administrative..... (1,038) (22) (1,016) (992) (24)
Depreciation, depletion and
amortization................ (2,046) (1,214) (832) (423) (409)
------- ------ ------- -------- ----
Operating Income (loss).......... $1,718 $1,395 $ 323 $ 413 ($ 90)
- ----------------------- ====== ====== ======= ======= ====
Although the Company has also invested in two exploration ventures in
South Texas and a drilling concession in Romania, production from such ventures,
if any, has not yet commenced. No proved reserves have been associated with any
of these ventures.
Revenues
Oil and Gas Sales
Oil and gas sales on non-AmBrit properties increased $396 or 16.7%
from fiscal 1998 to fiscal 1999. Most of the increase is attributable to a 13%
increase in production. Although oil and gas prices have recently increased
significantly, they were lower during much of the year ended September 30, 1999.
At September 30, 1999, the Company had hedged 54% of its anticipated oil
production and 39% of its anticipated gas production for the year ended
September 30, 2000. The crude oil was hedged at an average New York Mercantile
Exchange ("NYMEX") price of $19.85 per barrel and the natural gas was hedged at
an average price of $2.66 per mcf. The price the
-13-
Company receives for its production differs from the NYMEX pricing due to its
location basis differentials. However, management believes the NYMEX pricing is
highly correlated to its production field prices and expects to be able to apply
hedge accounting to these derivative transactions. To the extent that futures
NYMEX oil and gas prices average less than the prices at which the Company has
hedged production, the Company's future oil and gas sales will increase above
that which results from the sale of production at market prices. Conversely, to
the extent that futures NYMEX prices exceed the average prices at which the
Company has hedged its production, the Company's future oil and gas sales will
decrease below that which results from the sale of production at market prices.
At September 30, 1999, the Company had not hedged 46% and 61% of its
anticipated crude oil and natural gas production, respectively. As a result, the
Company remains exposed to oil and gas price risk on this unhedged production.
As a result of the acquisition of the AmBrit oil and gas properties, the
Company expects that its revenues from oil and gas sales will increase
significantly in the future.
Well Operations
Revenue from non-AmBrit well operations increased $122 or 53% from
fiscal 1998 to fiscal 1999. The increase was primarily caused by the
non-recurring recovery of operating fees in 1999 that had been written off in
prior years.
Expenses
Oil and Gas Production
Oil and gas production expenses increased $175 or 22.6% from fiscal
1998 to fiscal 1999. The increase in oil and gas production expenses results
from operating expenses related to eight new wells drilled in fiscal 1999 in
which the Company has an interest and the general maturing of the Company's oil
and gas properties and the tendency for older, depleting properties to carry a
higher production expense burden than recently drilled properties.
In fiscal 1999 oil and gas production expense comprised 34.3% of oil
and gas sales versus 32.7% of oil and gas sales in fiscal 1998. For the period
July 1, 1999 to September 30, 1999, oil and gas production expenses related to
the AmBrit properties comprised 36.5% of related oil and gas sales from AmBrit
properties. Since oil and gas production expenses generally increase as wells
deplete, the Company expects that the oil and gas production expense percentage
(oil and gas production expense as a percentage of oil and gas sales) will
increase in the future given fixed oil and gas prices. Such increase may,
however, be offset by a lower percentage of oil and gas production expenses to
oil and gas sales for the Company's interests in new wells which the Company
expects to be drilled.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization from non-AmBrit properties
increased $409 or 96.7% from fiscal 1998 to fiscal 1999. Approximately 80% of
the increase is attributable to a higher depletion rate per equivalent mcf
produced. The higher depletion rate results from the acquisition of the AmBrit
properties and the accounting requirement under full cost accounting that
depreciation, depletion and amortization be computed on a consolidated basis by
country - not on a separate property or field basis. Prior to the acquisition of
the AmBrit properties, the Company's amortization rate per equivalent mcf
produced was $.37 whereas after the acquisition the Company's rate was
approximately $.71 per equivalent mcf produced.
The remaining 20% of the increase in depreciation, depletion and
amortization was caused by a 13% increase in production.
CORPORATE GENERAL AND ADMINISTRATIVE EXPENSE
Corporate general and administrative expenses increased $1,031 or
33.5% from fiscal 1998 to fiscal 1999. Most of the increase was caused by
increased consulting fees applicable to due diligence for possible acquisitions.
Increased employee bonuses and increased legal costs also contributed to the
increase.
-14-
OTHER INCOME (EXPENSE)
Interest Income
Interest income decreased $570 or 25.1% from fiscal 1998 to fiscal
1999. The decrease is primarily attributable to a decrease in the average
balance of unrestricted cash outstanding during the periods being compared. In
June 1999, the Company paid $20,170 (net of purchase price) for AmBrit's oil and
gas properties. In addition, during the year ended September 30, 1999, the
Company spent $6,919 to acquire shares of its common stock.
Other Income (Expense)
The composition of other income (expense) is as follows:
Year Ended September 30,
-----------------------------------
1999 1998
--------------------- ------------
Write down of investment in Penn Octane Corporation preferred
stock............................................................ ($423)
Market price adjustment of investment in Penn Octane Corporation
common stock..................................................... 431
Litigation recovery - EMC............................................. 355
Miscellaneous......................................................... (11) ($41)
----- ----
$352 ($41)
==== ====
The $423 write down of the Company's investment in the preferred stock
of Penn Octane Corporation ("Penn Octane"), a public company selling liquid
propane gas to northern Mexico, was based upon the Company's calculation of the
loss that would be incurred if the Company converted its shares of Penn Octane
preferred stock and sold the resulting common shares (unregistered) at a
discount to the market price given the thin capitalization of Penn Octane and
low trading volumes in its stock. Subsequently, the Company converted all of its
Penn Octane preferred stock to Penn Octane common stock.
The market price adjustment relates to the Company's investment in Penn
Octane common stock. Until June 30, 1999, the Company classified Penn Octane
securities as trading securities because all except 50,000 of the 551,000 common
shares owned by the Company were registered and the Company did not expect to
hold its Penn Octane investment for the long term. According to current
generally accepted accounting principles, such securities were valued at fair
market value with unrealized gains or losses included in earnings. The $431
favorable market adjustment resulted from the increase in the market price of
Penn Octane common stock as of June 30, 1999.
Effective June 30, 1999, the Company reclassified its investment in Penn
Octane common stock as available-for-sale securities because the Company was not
actively buying and selling Penn Octane securities. At September 30, 1999, the
market value of the Company's investment in Penn Octane stock exceeded the
Company's cost by $2,444. This unrealized gain, less $40 of estimated income
taxes, has been recorded as other comprehensive income pursuant to SFAS 130.
At September 30, 1999, the Company owned 1,067,667 shares of Penn Octane
common stock representing approximately 8.5% of outstanding stock at September
30, 1999.
The $355 litigation recovery was a non-recurring gain related to the
Powerine/EMC Litigation occurring in the second fiscal quarter of 1999 for which
there was no counterpart during the year ended September 30, 1998.
-15-
PROVISION FOR INCOME TAXES
The tax provisions for the year ended September 30, 1999 and 1998
consist of the following components:
Year Ended September 30,
------------------------------
1999 1998
------------------ ----------
1. Increase in net deferred tax asset using 36% Federal and state blended tax
rate.................................................................... ($3,788)
2. Utilization of deferred tax asset, net of related valuation reserves, using
36% blended Federal and state tax rate.................................. $2,765 4,992
3. A tax provision of 2% on all net income in excess of that required to
realize the net deferred tax asset. (This 2% rate represents alternative
minimum Federal corporate taxes the Company must pay despite having
tax carryforwards and credits available to offset regular Federal corporate
tax)....................................................................
71
4. Other (primarily revisions of previous estimates)....................... 120
------
$2,956 $1,204
====== ======
The tax provision for the year ended September 30, 1998, consists
primarily of a tax provision of $4,992 (utilization of deferred tax asset) and
an offsetting reversal of tax estimates and contingencies of $3,788. The Company
evaluated its need for a deferred tax valuation allowance at September 30, 1998
based upon positive evidence confirming the Company's ability to generate
sufficient taxable income to utilize the deferred tax asset available and
recorded a deferred tax asset, net of valuation reserves, of $3,788.
The tax provision for the year ended September 30, 1999, consists of
utilization of the $2,765 of remaining net deferred tax assets at September 30,
1998, $71 of Federal alternative minimum taxes on net income in excess of that
required to fully utilize the $2,765 net deferred tax asset using a 36% blended
tax rate and $120 of other taxes related to revisions to the prior year's
taxable income. The fiscal 1999 blended Federal and state income tax rate was
26%, which is lower than the statutory rate due to the utilization of statutory
depletion and tax credits. The Company did not record a net deferred tax asset
at September 30, 1999 because it determined that future taxable income was less
certain given the Company's large exploratory and wildcat drilling programs, the
expiration of the Lone Star Contract, contingent environmental liabilities and
other factors.
EARNINGS PER SHARE
Since November 1996, the Company has repurchased 4,486,017 or 66% of
its common shares. As a result of these share acquisitions, earnings per share
are higher than they would be if no shares had been repurchased.
Fiscal 1998 vs Fiscal 1997
NATURAL GAS MARKETING AND TRANSMISSION
Gas sales from natural gas marketing increased $5,402 or 8.4% from
fiscal 1997 to 1998. Gas sales in each fiscal year consist of the following:
September 30,
--------------------------
1998 1997
---- ----
Gas sales to Lone Star................... $64,619 $59,695
Gas sales to MGNG........................ 4,904 4,904
Gas sales to third parties............... 478
------- -------
$70,001 $64,599
======= =======
-16-
Lone Star Contract
Natural gas sales under the Lone Star Contract increased $4,924 or 8.2%
from fiscal 1997 to fiscal 1998. Under the Company's long-term gas sales
contract with Lone Star, the price received for gas is essentially fixed through
May 31, 1999. The variance in gas sales, therefore, is almost entirely
attributable to the volumes of gas delivered. Although the volumes sold to Lone
Star annually are essentially fixed (the Lone Star Contract has a take-or-pay
provision), the Lone Star Contract year is from February 1 to January 31 whereas
the Company's fiscal year is from October 1 to September 30. Furthermore,
although the volumes to be taken by Lone Star in a given contract year are
fixed, there is no provision requiring equal monthly or daily volumes and
deliveries accordingly vary with Lone Star's seasonal and peak demands. Such
variances have been significant. As a result, Lone Star deliveries, although
fixed for a contract year, may be skewed and not proportional for the Company's
fiscal periods.
For fiscal 1998, sales to Lone Star were approximately $735 more than
those which would have resulted if daily deliveries had been fixed and equal. At
September 30, 1998, the remaining volumes to be delivered under the Lone Star
Contract were approximately 8.4% greater than those that would be delivered if
daily deliveries were fixed and equal.
MGNG Contract
Gas sales to MGNG remained the same in fiscal 1998 as in fiscal 1997
because the gas sales contract with MGNG requires a fixed daily volume of gas at
a fixed price and the MGNG contract was in force for all of the periods being
compared.
Gas Purchases
Gas purchases increased $3,288 or 8.2% from fiscal 1997 to fiscal 1998.
Gas purchases in each of the fiscal years consist of the following:
September 30
---------------------
1998 1997
---- ----
Gas purchases - Lone Star Contract...................................................... $36,898 $34,686
Gas purchases - MGNG Contract........................................................... 5,897 5,280
Gas purchases - sales to third parties.................................................. 459
------- -------
$43,254 $39,966
======= =======
Gas purchases for the Lone Star Contract increased $2,212 or 6.4% from
fiscal 1997 to fiscal 1998. For fiscal 1997 gas purchases comprised 58.1% of gas
sales versus 57.1% of gas sales for fiscal 1998. From 1997 to 1998 the gross
margin increased $2,712 or 10.8%. During the same periods the gross margin
percentage ((gas sales - gas purchases) as a percentage of gas sales) increased
1.0% from 41.9% for fiscal 1997 to 42.9% for fiscal 1998.
The decrease in gas purchases as a percentage of gas sales and the
concomitant increase in gross margin percentage for the Lone Star Contract
resulted primarily from non-recurring favorable adjustments of gas purchase
costs in fiscal 1998 and the replacement of high price gas contracts expiring in
April 1997 with lower market price contracts.
Gas purchases for the contract with MGNG increased $617 or 11.7% from
fiscal 1997 to fiscal 1998. The gas sales volumes sold to MGNG for each of the
two years being compared were equal; hence the increase is entirely attributable
to increased market prices for gas, net of hedging effects.
Gas purchased for third parties increased from zero in fiscal 1997 to
$459 in fiscal 1998. The gas sales to third parties in fiscal 1998 resulted
because Lone Star limited its daily gas purchases to 103% of volumes nominated
and the Company had to sell the excess gas elsewhere. The restriction of daily
sales to 103% of volumes nominated did not, however, affect annual volumes that
Lone Star was required to take under the Lone Star Contract.
In August 1998, the Company hedged all of its remaining unhedged gas
requirements. As a result of such hedging, the Company had fixed its price
exposure on its gas sales contract with MGNG through May 31, 1999, the
termination date for the contract.
-17-
Operating Costs
Operating costs decreased to a recovery of $16 for the year ended
September 30, 1998 from $472 for the year ended September 30, 1997 because the
Texas pipeline was sold to UPRC in May 1997 and as of June 1, 1997 the Company
no longer incurred operating costs to operate the Texas pipeline.
General and Administrative
General and administrative expenses decreased $714 from $776 for the
year ended September 30, 1997 to $62 for the year ended September 30, 1998. Most
general and administrative expenses incurred during the year ended September 30,
1997 related to the Texas pipeline, which was sold in May 1997. The remaining
administrative expenses consist primarily of consulting fees for on-going gas
marketing operations.
Transportation
Transportation expense increased $1,201 from $338 for the year ended
September 30, 1997 to $1,539 for the year ended September 30, 1998. During the
period October 1, 1996 to May 31, 1997, one of the Company's subsidiaries owned
and operated the Texas pipeline and all transportation revenues were for
intercompany transportation and were accordingly eliminated in consolidation of
the Company's financial statements. On May 30, 1997, the Company sold the Texas
pipeline to a subsidiary of UPRC. In both 1997 and 1998, transportation expense
consisted entirely of the amortization of a $3,000 prepaid transportation asset.
Amortization is based upon and thus proportional to deliveries made to Lone
Star. In fiscal 1997, four months' transportation expense was recorded versus
twelve months' transportation expense in fiscal 1998.
Depreciation and Amortization
Depreciation and amortization decreased $1,177 or 11.1% from fiscal 1997
fiscal 1998. The decrease is attributable to the sale of the Texas pipeline to a
subsidiary of UPRC in May 1997. As a result of the sale, the Company no longer
owned or depreciated the Texas pipeline.
EXPLORATION AND PRODUCTION
As noted above, the Company sold its Texas oil and gas properties to
UPRC in May 1997. The reserves sold represented approximately 84% of the
Company's proved oil and gas reserves and 60%-65% of the Company's oil and gas
production at the time of sale. Comparison of fiscal 1998 oil and gas sales,
production expenses, general and administrative expenses and depletion,
depreciation and amortization to those in fiscal 1997 is thus not meaningful.
Accordingly, exploration and production operations comparisons and analysis have
been limited to operations from those oil and gas properties which were not sold
to UPRC. The related operating results for such properties are as follows:
Year Ended September 30,
-----------------------------
1998 1997
---- ----
Revenues:
Oil and gas sales................................................ $2,373 $3,111
Well operations.................................................. 230 287
-------- ------
2,603 3,398
------- ------
Expenses:
Oil and gas production........................................... 775 528
General and administrative....................................... 992 745
Depreciation, depletion and amortization......................... 423 653
-------- ------
2,190 1,926
------- ------
Operating income.................................................... $ 413 $1,472
======= ======
-18-
Revenues
Oil and Gas Sales
Oil and gas sales decreased $738 or 23.7% from fiscal 1997 to fiscal
1998. The decrease is attributable to decreased oil and gas prices and decreased
production. Many of the Company's oil and gas reserves are mature reserves and
such decreased production is expected. Although the Company has participated in
drilling twenty-three new wells and several reworks on existing wells from July
1997 through September 30, 1998, production from such new drilling activities
has only recently begun impacting operations. The Company is also reviewing
possible investments in other oil and gas drilling programs and oil and gas
property acquisitions, including several requiring substantial investment. As a
result, the Company expects that, if it is successful in making acquisitions,
its oil and gas sales will eventually increase given stable oil and gas sales
prices. However, there can be no assurance that wells expected to be drilled
will actually be drilled, that such drilling will be successful or that the
Company will be successful in making acquisitions or that oil and gas sales will
increase.
Well Operations
Revenue from well operations decreased $57 or 19.9% from fiscal 1997 to
fiscal 1998. The decrease is attributable to the Company's resignation as
operator on certain Appalachian wells in fiscal 1997 where a non-operator
offered to operate the wells at a cost significantly less than that being
incurred by the Company in performing such operations. The related well
operations revenues were not replaced.
Expenses
Oil and Gas Production
Oil and gas production expenses increased $247 or 46.8% from fiscal
1997 to fiscal 1998. The increase in oil and gas production expenses results
from the general maturing of the Company's oil and gas properties and the
tendency for older, depleting properties to carry a higher production expense
burden than recently drilled properties. Furthermore, oil and gas production
expenses, especially non-capitalized repairs, do not generally occur evenly each
year and are best compared on a cumulative rather than on an annual basis. There
can be no assurance, however, that such will be the case.
General and Administrative
General and administrative costs increased $247 or 33.2% from fiscal
1997 to the fiscal 1998. The net increase was primarily attributable to higher
employee costs and bonuses, higher consulting fees and increased legal costs.
The increase was offset to a minor extent by tax refunds and vendor settlements
in fiscal 1998 for which there was no counterpart in fiscal 1997.
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization decreased $230 or 35.2% from
fiscal 1997 to the fiscal 1998. The decrease is attributable to slightly
decreased production and significantly lower depletion rate per unit of
production. The lower depletion rate results primarily from the Company's sale
of 84% of its proved oil and gas reserves to UPRC.
OTHER INCOME (EXPENSE)
Gain on Sale of Assets
In May 1997, the Company's subsidiaries sold their Texas oil and gas
assets and pipeline to UPRC, resulting in a $19,667 gain. There was no
counterpart in fiscal 1998.
Interest Income
Interest income increased $786 or 52.9% from fiscal 1997 to fiscal 1998.
The increase is primarily attributable to an increase in the average balance of
invested unrestricted cash. For the year ended September 30, 1997, $800 of
interest income was attributable to a note receivable from MG related to the
Powerine Arbitration and $685 resulted from the investment of excess cash. For
the year ended September 30, 1998, $31 was attributable to interest on the MG
note, $94 was attributable
-19-
to interest on a note from Penn Octane Corporation ("Penn Octane"), a public
company involved in liquid petroleum and compressed natural gas business, and
the remaining $2,146 was attributable to the investment of excess cash. Interest
on the MG note ceased on October 14, 1997.
Interest Expense
Interest expense decreased $1,036 from $1,038 for the year ended
September 30, 1997 to $2 for the year ended September 30, 1998 because the
Company repaid all of its long-term debt in May 1997 with a portion of the
proceeds from the sale of its Texas oil and gas properties and pipeline to UPRC.
Penn Octane Note
In October 1997, the Company invested $1,000 in a promissary note of
Penn Octane. The note bears interest at 10% payable quarterly and was due on
June 30, 1998. At June 30, 1998, Penn Octane did not repay the note. In May of
1998, Penn Octane was awarded a judgement against a bank and such judgement is
in excess of the $1,000 owed to the Company by Penn Octane. In December 1998,
Penn Octane assigned its interest in the bank judgement to the extent of the
Company's note to the Company in return for an extension of the note until June
30, 1999. The Company also received 225,000 warrants to purchase the common
stock of Penn Octane for one dollar and seventy-five cents per share as
consideration for the extension. The bank owing the judgement has appealed it
and such appeal may not be resolved for a year or more. As a result, there can
be no assurance that the judgement will be upheld upon appeal or that the bank
will ultimately pay the judgement won by Penn Octane to the Company. If the note
is not repaid by its extended due date, the Company intends to reduce the Penn
Octane note to its estimated realizable value, if any.
GAMXX
On February 27, 1998, the Company entered into an agreement with
Alexander Allen, Inc. ("AA") concerning amounts owed to the Company by AA and
its subsidiary, GAMXX Energy, Inc. ("GAMXX"). The Company had made loans to
GAMXX through 1991 in the aggregate amount of approximately $8,000. When GAMXX
was unable to obtain financing, the Company recorded a one hundred percent loss
provision on its loans to GAMXX in 1991 and 1992 while still retaining its
lender's lien against GAMXX.
Pursuant to the terms of the GAMXX Agreement, the Company is to receive
$1,000 cash in settlement for its loans when GAMXX closes on its financing.
GAMXX expected such closing not later than May 31, 1998 but such closing has not
yet occurred.
The Company has carried its loans to GAMXX at zero the last six years.
The Company will record the $1,000 proceeds as "other income" if and when it
collects such amount. There can be no assurance that GAMXX will close on its
financing.
PROVISION FOR INCOME TAXES
As a result of the tax benefit recorded in fiscal 1996, the Company
expected to provide for income taxes at a 36% blended statutory rate for the
remainder of the Lone Star Contract for book purposes. During this period the
Company expected to pay income taxes, however, at a 2% effective rate,
consisting of Federal alternative minimum tax.
The Company's tax provision for fiscal 1997 consists of two components:
a. The tax provision on pre-tax accounting income, exclusive of the
$19,667 gain on the sale of assets, aggregates $4,270 and
essentially represents the partial utilization of the $7,716
deferred tax asset recorded at September 30, 1996 at an effective
rate of 36% of earnings. If future events change the Company's
estimate concerning the probability of utilizing its tax assets,
appropriate adjustments will be made when such a conclusion is
reached.
b. The tax provision on the $19,667 gain equals the Company's expected
tax liability for the income related to the sale and aggregates
$393. The tax rate used in such calculation was 2%, the Federal
alternative minimum tax rate. The Company is not yet subject to a
higher tax rate due to its tax carryforwards. A tax provision of 36%
was not provided for the gain because a related deferred tax asset
was not previously provided since the Company did not anticipate
selling the properties and had previously taken the properties off
the market.
-20-
The tax provision for the year ended September 30, 1998 consists
primarily of a tax provision of $4,992 (utilization of deferred tax asset) and
an offsetting reversal of tax estimates and contingencies of $3,463. The Company
evaluated its need for a deferred tax valuation allowance at September 30, 1998
based upon recent positive evidence confirming the Company's ability to utilize
its tax carryforwards.
EARNINGS PER SHARE
Since November 1996, the Company has reacquired 3,486,017 shares of its
common stock. As a result of these share acquisitions, earnings per outstanding
share have been higher than would be the case if no shares had been repurchased
LIQUIDITY AND CAPITAL RESOURCES
All statements other than statements of historical fact contained in
this report are forward-looking statements. Forward- looking statements in this
report generally are accompanied by words such as "anticipate," "believe,"
"estimate," or "expect" or similar statements. Although the Company believes
that the expectations reflected in such forward-looking statements are
reasonable, no assurance can be given that such expectations will prove correct.
Factors that could cause the Company's results to differ materially from the
results discussed in such forward-looking statements are disclosed in this
report, including without limitation in conjunction with the expected cash
sources and expected cash obligations discussed below. All forward-looking
statements in this Form 10-K are expressly qualified in their entirety by the
cautionary statements in this paragraph. Furthermore, this statement constitutes
a Year 2000 Readiness Disclosure Statement and the statements contained herein
are subject to the Year 2000 Information and Readiness Disclosure Act ("Act").
In case of a dispute, this document and information contained herein are
entitled to protection of the Act.
During the year ended September 30, 1999, the Company generated $17,567
from operating activities. During the same period the Company invested $23,964
in oil and gas properties and $6,919 to reacquire shares of its common stock. In
addition, it paid $1,681 in stockholder dividends. At September 30, 1999, the
Company had $22,252 of unrestricted cash, $26,489 of working capital and no
long-term debt.
Discontinued Refining Operations
Although the Company's former and present subsidiaries have exited the
refining business and third parties have assumed environmental liabilities, if
any, of such subsidiaries, the Company and several of its subsidiaries remain
liable for contingent environmental liabilities (see Item 3 and Note 12 to the
financial statements included in Item 8 of this Form 10-K).
Expected Sources and Uses of Funds
As of November 22, 1999, the estimated future cash expenditures of the
Company for the next two fiscal years consist of the following:
a. Investments in Oil and Gas Properties and Other Energy Sector
Ventures
Subsequent to September 30, 1999, the Company spent $372 to acquire
outside interests in gas wells it operated in Alabama. During this
period the Company also entered into agreements to purchase
additional outside interests in the Alabama wells, to purchase
majority interests in several Pennsylvania wells and to purchase
majority interests in 26 Louisiana offshore wells. The total cost
to the Company, after purchase price adjustments, and assuming all
three transactions are consummated, is approximately $3,075. In
addition, the Company anticipates the following exploration and
drilling expenditures over the next two fiscal years:
1. Development drilling on existing acreage............ $ 4,000
2. South Texas exploratory drilling ventures........... 6,500
3. Romanian concession ................................ 2,000
-------
$12,500
=======
If the initial drilling results in the South Texas drilling
ventures are less favorable than anticipated, the Company expects
to be able to reduce this drilling commitment by approximately
$3,000. Conversely, if the initial results are better than expected
the Company may participate in the drilling of more wells than
budgeted above. If the initial wildcat Romanian wells are
successful, the Company may also increase its investment in that
country significantly and could conceivably spend $10,000-$15,000
if new oil and gas fields are discovered.
-21-
In addition, the Company is currently pursuing several other
possible material investments in the energy sector. These possible
investments include drilling ventures, the acquisition of oil and
gas properties and oil and gas companies, as well as the
acquisition of pipelines and gas marketing operations. Although
most of these possible investments involve domestic properties,
some involve investments overseas. Although the Company has
concluded several transactions and believes it can conclude an
additional transaction or several transactions on terms favorable
to the Company, there can be no assurance that such will be the
case. Oil and gas prices have recently increased significantly and
many potential sellers have decided not to sell or have not been
forced to sell by their lenders. In addition, several sellers have
raised the price for the oil/gas properties they are selling given
currently high oil and gas prices and acquisition of such
properties at such high prices would not be in the Company's best
interest. In addition, several large oil and gas companies have
significantly more resources than the Company and other parties may
be willing to pay more than the Company for a given acquisition.
b. Repurchase of Company Shares - as of November 22, 1999, the Company
had repurchased 4,486,017 of its shares of common stock at a cost
of $64,192. The Company's Board of Directors previously authorized
the repurchase of up to 4,750,000 shares to provide an exit vehicle
for investors who want to liquidate their investment in the
Company. The decision whether to repurchase additional shares
and/or to increase the repurchase authorization above 4,750,000
shares will depend upon the market price of the Company's stock,
tax considerations, the number of stockholders seeking to sell
their shares and other factors.
c. Recurring Dividends - the Company's Board of Directors adopted a
policy of paying a $.60 per share annual dividend ($.15 per share
quarterly) in June of 1997. The Company expects to continue to pay
such dividend until the Board of Directors, in its sole discretion,
changes such policy.
At September 30, 1999, the Company had available the following sources
of funds:
Unrestricted cash - September 30, 1999............................. $22,252
Line of credit - energy bank....................................... 30,000
Marketable securities.............................................. 3,761
-------
$56,013
=======
In addition, the Company anticipates significant future cash flow from
exploration and production operations.
The estimated sources of funds are subject to most of the risks
enumerated below. The realization from the sale of the Company's investment in
Penn Octane is dependent on the market value of such stock and the Company's
ability to liquidate its Penn Octane stock investment at or near market values.
Since Penn Octane is thinly capitalized and traded, liquidation of a large
volume of Penn Octane stock without significantly lowering the market price may
be impossible.
The Company thus expects that it can fund all of its present drilling
commitments from its own unrestricted cash. The Company can also use its
unrestricted cash and future cash flow, as well as up to $30,000 from it line of
credit, to acquire additional oil and gas properties and to conduct additional
drilling. As a result, the Company believes it has available the financing to
make additional future acquisitions of up to approximately $40,000-$57,000 while
still funding its existing drilling commitments. The Company has also negotiated
with several potential industry partners who may provide financing if the
Company decides to make an acquisition for prices in excess of these amounts.
The Company's future operations are subject to the following risks:
1. Contingent Environmental Liabilities
Although the Company has never itself conducted refining operations
and its refining subsidiaries have exited the refining business and
the Company does not anticipate any required expenditures related to
discontinued refining operations, interested parties could seek
redress from the Company for environmental liabilities. In the past,
government and other plaintiffs have often named the most
financially capable parties in such cases regardless of the
existence or extent of actual liability. As a result there exists
the possibility that the Company could be named for any
environmental claims related to discontinued refining operations of
its present and former refining subsidiaries.
-22-
The Company was informed that the EPA has investigated offsite acid
sludge waste found near the Indian Refinery and was also remediating
surface contamination in the Indian Refinery property. Neither the
Company nor IRLP has been named with respect to these two actions.
In October 1998, the EPA named the Company and two of its
subsidiaries as potentially responsible parties for the expected
clean-up of the Indian Refinery. In addition, eighteen other parties
were named including Texaco Refining and Marketing, Inc., the
refinery operator for over 50 years. The Company subsequently
responded to the EPA indicating that it was neither the owner nor
operator of the Indian Refinery and thus not responsible for its
remediation. In November 1999, the Company received a request for
information from the EPA concerning the Company's involvement in the
ownership and operation of the Indian Refinery. The Company expects
to respond to the EPA information request in the second quarter of
fiscal 2000. Estimated undiscounted clean-up costs for the Indian
Refinery are $80,000 to $150,000 according to third parties. If the
Company were found liable for the remediation of the Indian
Refinery, it could be required to pay a percentage of the clean-up
costs. Since the Company's subsidiary only operated the Indian
Refinery five years whereas Texaco and others operated it over 50
years, the Company would expect that its share of any remediation
liability would be proportional to its years of operation although
such may not be the case. Although the Company does not believe it
has any liabilities with respect to the environmental liabilities of
the refineries, a court of competent jurisdiction may find
otherwise. A decision by the U.S. Supreme Court in June 1998 in a
comparable case supports the Company's position.
The above estimate of expected cash resources and cash obligations
assumes no expenditure for legal defense costs related to the Indian
Refinery. If the Company is sued and related legal proceedings
continue longer than expected (environmental litigation often
continues 3-5 years or more) and/or the Company is found liable for
a portion of the environmental remediation of either the Indian
Refinery or Powerine Refinery, estimated cash resources will be
decreased and such decrease could be significant.
2. IRLP Vendor Liabilities:
IRLP owes its vendors approximately $5,000. Its only major asset was
a $5,388 note due from the purchaser of the Indian Refinery,
American Western. We have recently been informed that IRLP has
agreed to settle its $5,388 note for approximately $800 in exchange
for a covenant of the EPA not to sue IRLP. Assuming such a
settlement is consummated, IRLP will be able to pay its creditors
only a small portion of the amounts owed to them.
3. Larry Long Litigation:
The above cash flow assumes the Company will not have to pay any
claim related to the Larry Long litigation. Although the sale of the
Company's Texas oil and gas properties and pipeline to UPRC have
significantly reduced the Company's exposure, there can be no
assurance that the plaintiffs will not file new lawsuits, having
already amended their original complaint three times. In such case,
the Company would be exposed to the continuing legal costs of
defending the amended petitions, and, if it is determined that
settlement is in the Company's best interest, the cost to settle the
lawsuit.
4. Public Market for the Company's Stock:
Although there presently exists a market for the Company's stock,
such market is volatile and the Company's stock is thinly traded.
Such volatility may adversely affect the market price and liquidity
of the Company's common stock.
In addition, the Company, through its stock repurchase program, has
repurchased 4,486,017 or 66% of its outstanding common stock since
November of 1996 and has effectively become the major market maker
in the Company's stock. If the Company ceases repurchasing shares
the market value of the Company's stock may be adversely affected.
5. Year 2000
The Company has completed a study of the Year 2000 issue and related
risks. As a result of the study, the Company has replaced its oil
and gas and general ledger software with new software which is Year
2000 compliant. Total costs to purchase and install the new system
were $122. The Company commenced using the new software in the first
quarter of fiscal 1999 and has encountered no significant problems
to date. The
-23-
Company has also made inquiries to outside parties who
process transactions of the Company, e.g., payroll,
commercial banks, transfer agent, reserve engineers, etc.
While most outside parties have confirmed they are Year 2000
compliant, a few have not done so to the Company's
satisfaction. The Company is continuing to pursue the vendors
whose responses appear to provide insufficient assurance.
The most important systems operated by the Company are its
revenue distribution, joint interest billing and general
ledger systems. The Company installed new systems because the
new systems are Year 2000 compliant. If a Year 2000 problem
nevertheless occurred, the Company could process transactions
for several months manually or using small computers but only
with increased administrative costs. Nevertheless, in many
cases, the Company is not the operator of a given well or
purchaser of oil and gas production. In those cases the
Company is dependent upon the operator and/or gas/oil
purchaser for accurate volumetric, cost and sales information
and for payments. Although the Company has made Year 2000
inquiries of such operators and purchasers and generally
received satisfactory responses, there can be no assurance
that such operators and purchasers will actually be Year 2000
compliant. If such is the case, the Company could find a
portion of its production revenue held in escrow until Year
2000 compliance was achieved or resulting litigation settled.
The related legal cost and resulting administrative confusion
could be substantial. The Company has made contingency plans
in the event of non-compliance of its systems, but can do
little in the case of non-compliance by outside operators and
oil/gas purchasers. If outside operators and/or purchasers
experience major Year 2000 disruptions, the Company's cash
flow would be negatively impacted. If such outside operators
and/or purchasers were unable to record production and
disburse payments, the Company's share of production proceeds
could be tied up for several months until the disruptions are
fixed and retroactive processing is completed. Since three
oil and gas purchasers buy in excess of 60% of the Company's
current production, the impact on the Company of any one or
more of the three experiencing Year 2000 problems could be
substantial. Although most operators and purchasers have
provided some written assurance that they are or will be Year
2000 compliant, such may not be the case.
The Company and its subsidiaries are not aware of any
material Year 2000 operational risks with respect to wells it
operates.
6. Foreign Operating Risks
Since the Company anticipates spending a minimum of
approximately $3,000 drilling a Romanian concession of which
$934 was incurred by September 30, 1999, the Company's
interests are subject to certain foreign country risks over
which the Company has no control - including political risk,
currency risk, the risk of additional taxation and the
possibility that foreign operating requirements and
procedures may reduce or eliminate estimated profitability.
7. Exploration and Production Reserve Risk
The Company is currently participating in several drilling
ventures. Most of these ventures involve exploratory drilling
where the probability of discovering commercial oil and gas
reserves is less than fifty percent (50%). The drilling
investment is essentially a sunk cost. Reserve risk is the
possibility that the reserves discovered, if any, will not
approximate those the Company has estimated before drilling.
If commercial reserves are not found the Company's future
operations and cash flow will be adversely affected.
8. Exploration and Production Price Risk
The Company has hedged approximately 54% of its anticipated
crude oil production and 39% of its anticipated natural gas
production for the year ended September 30, 2000 at prices
which are expected to provide profitable margins. The Company
has not hedged any of its anticipated oil and gas production
beyond December 2000 because the cost to do so appears
excessive when compared to the risk involved. As a result of
the Company remains exposed to future oil and gas price
changes with respect to approximately 46% of its estimated
crude oil production and 61% of its anticipated natural gas
production through September 2000 and virtually all of its
anticipated oil and gas production thereafter. Such exposure
could be considerable given the volatility of oil and gas
prices. For example, from February 1999 to October 1999,
crude oil prices essentially doubled. In the past crude oil
prices and gas prices have shown general volatility over
short periods of time.
-24-
9. Exploration and Production Operating Risk
All of the Company's current oil and gas properties are
onshore properties with relatively low operating risk. As
noted above, the Company acquired a fifty percent (50%)
interest in a Romanian oil and gas concession in fiscal 1999
and is currently involved in seismic and other pre-drilling
activities in that country. In addition, in May 1999, the
Company entered into an agreement to acquire majority
interests in twenty-six (26) offshore Louisiana wells for
which the Company will be the operator. The operating risks
associated with the Romanian drilling concession and the
Louisiana offshore wells expected to be acquired are
significantly greater than those associated with the
operation of onshore wells. Operations in Romania may, for
example, be impacted by the lack of rig availability or
access to operating supplies, equipment, skilled operating
personnel or by excessive governmental regulations. Although
the Company will not operate any Romanian wells it is
affected by and bears fifty percent (50%) of the costs
related to the such operating activities. In Louisiana, where
the Company expects to become operator, operations will be
impacted by the inherent difficulties of producing crude oil
in offshore waters including but not limited to the necessity
of transporting crude oil by barge and operating the
producing wells from a drilling platform rather than from dry
land.
10. Other Risks
In addition to the specific risks noted above, the Company is
subject to general business risks, including insurance claims
in excess of insurance coverage, tax liabilities resulting
from tax audits and the risks associated with the increased
litigation that appears to affect most corporations.
11. Future of the Company
The oil and gas industry is a dynamic constantly changing
industry. In the last five years the rate of mergers and
acquisitions within the industry has accelerated
significantly as companies seek to consolidate operations,
shed unprofitable operations and reduce administrative costs.
Although the Company has recently acquired the oil and gas
assets of AmBrit and invested in other oil and gas
acquisitions, there can be no assurance that the Company will