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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
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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
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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.
<TABLE>
<CAPTION>
Fiscal Year Ended September 30,
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1999 1998 1997
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<S> <C> <C> <C>
Oil -- Bbls (barrels).............................................. 124,000 20,000 36,000
Gas -- MCF......................................................... 1,971,000 869,000 2,454,000
</TABLE>
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.
<TABLE>
<CAPTION>
Fiscal Year Ended September 30,
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1999 1998 1997
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<S> <C> <C> <C>
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
</TABLE>
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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.
<TABLE>
<CAPTION>
Fiscal Year Ended September 30,
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1999 1998 1997
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Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- ---
<S> <C> <C> <C> <C> <C> <C>
Developmental:
Gross.................................. 5 3 23.0 -- 3.0 --
Net.................................... 2.3 1.2 15.2 -- 1.4 --
</TABLE>
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.
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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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<PAGE>
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.
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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.
<TABLE>
<CAPTION>
1999 1998
--------------------- -----------------------
High Low High Low
--------- ------ ---------- --------
<S> <C> <C> <C> <C>
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
</TABLE>
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-
<PAGE>
Earnings per share have been retroactively restated in accordance with
SFAS 128.
<TABLE>
<CAPTION>
For the Fiscal Years Ended September 30,
----------------------------------------------------------------
(in Thousands, except per share amounts)
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
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
</TABLE>
- -------------
(1) Includes a $19,667 non-recurring gain on sale of assets.
-10-
<PAGE>
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-
<PAGE>
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-
<PAGE>
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:
<TABLE>
<CAPTION>
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)
------------------- -------------------- ------------------- --------------- ----------
<S> <C> <C> <C> <C> <C>
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)
- ----------------------- ====== ====== ======= ======= ====
</TABLE>
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-
<PAGE>
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-
<PAGE>
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:
<TABLE>
<CAPTION>
Year Ended September 30,
-----------------------------------
1999 1998
--------------------- ------------
<S> <C> <C>
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)
==== ====
</TABLE>
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-
<PAGE>
PROVISION FOR INCOME TAXES
The tax provisions for the year ended September 30, 1999 and 1998
consist of the following components:
<TABLE>
<CAPTION>
Year Ended September 30,
------------------------------
1999 1998
------------------ ----------
<S> <C> <C>
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
====== ======
</TABLE>
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-
<PAGE>
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:
<TABLE>
<CAPTION>
September 30
---------------------
1998 1997
---- ----
<S> <C> <C>
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
======= =======
</TABLE>
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-
<PAGE>
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:
<TABLE>
<CAPTION>
Year Ended September 30,
-----------------------------
1998 1997
---- ----
<S> <C> <C>
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
======= ======
</TABLE>
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<PAGE>
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
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<PAGE>
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.
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<PAGE>
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.
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<PAGE>
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.
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<PAGE>
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
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<PAGE>
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.
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<PAGE>
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
not become the acquisition target of another larger oil and
gas company. As a result , the Company's Board of Directors
may decide to pursue other courses of action, including but
not limited to liquidation, sale of assets, merger or other
reorganization.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company has hedged approximately 54% percent of its estimated
consolidated crude oil production (approximately 30,000 barrels per month) and
39% of its estimated natural gas production (approximately 350,000 mcf per
month) through September 30, 2000 using futures contracts. The Company has also
hedged approximately 14% of its anticipated natural gas production for the year
ended September 30, 2001. The average hedged prices (based on NYMEX prices) are
$19.85 per barrel for crude oil and $2.66 per mcf for natural gas. The price the
Company receives for production differs from the NYMEX pricing due to its
location basis differentials. However, management believes that NYMEX pricing is
highly correlated to its production field prices and expects to be able to apply
hedge accounting to these derivative transactions. The Company therefore remains
at risk primarily with respect to its unhedged production. If oil and gas market
prices increase, oil and gas revenues applicable to the unhedged production will
increase. If oil and gas market prices decrease, oil and gas revenues related to
such unhedged production will decrease. Based upon the volumes hedged at
September 30, 1999, future oil and gas sales would increase approximately $555
if NYMEX prices decreased 10%. Conversely, future oil and gas sales would
decrease approximately $448 if NYMEX prices increased 10%. The Company also
remains at risk with respect to differences between the exchange prices on the
New York Mercantile Exchange and the field or spot prices it receives with
respect to its production.
INFLATION AND CHANGING PRICES
Exploration and Production
Oil and gas sales are determined by markets locally and worldwide and
often move inversely to inflation. Whereas operating expenses related to oil and
gas sales may be expected to parallel inflation, such costs have often tended to
move more in response to oil and gas sales prices than in response to inflation.
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NEW ACCOUNTING PRONOUNCEMENTS
In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 130 ("SFAS 130") regarding
reporting comprehensive income, which establishes standards for reporting and
display of comprehensive income and its components. The components of
comprehensive income refer to revenues, expenses, gains and losses that are
excluded from net income under current accounting standards, including foreign
currency translation items, minimum pension liability adjustments and unrealized
gains and losses on certain investments in debt and equity securities. SFAS 130
requires that all items recognized under accounting standards as components of
comprehensive income be reported in a financial statement displayed in equal
prominence with the other financial statements; the total of other comprehensive
income for a period is required to be transferred to a component of equity that
is separately displayed in a statement of financial condition at the end of an
accounting period. SFAS 130 was effective for both interim and annual periods
for companies having fiscal years beginning after December 15, 1997.
Reclassification of financial statements for earlier periods provided for
comparative purposes was required. The Company adopted SFAS 130, effective
October 1, 1998.
In June 1997, FASB issued Financial Accounting Standards Board No. 131
("SFAS 131") regarding disclosures about segments of an enterprise and related
information. SFAS 131 established standards for reporting information about
operating segments in annual financial statements and required the reporting of
selected information about operating segments in interim financial reports
issued to stockholders. It also established standards for related disclosures
about products and services, geographic areas and major customers. SFAS 131 was
effective for companies having fiscal years beginning after December 15, 1997.
The Company adopted SFAS No. 131 as of October 1, 1998. The provisions of SFAS
131 have not materially changed the Company's disclosures and reported financial
information to the present because the Company has presented the required
segment information in its consolidated statements of operations for several
years before SFAS 131 was effective and continue to do so.
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities ("SFAS 133"), was issued by the
Financial Accounting Standards Board in June 1998. SFAS 133 standardizes the
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts. Under the standard, entities are required to carry
all derivative instruments in the statement of financial position at fair value.
The accounting for changes in the fair value (i.e., gains or losses) of a
derivative instrument depends on whether it has been designated and qualifies as
part of a hedging relationship and, if so, on the reason for holding it. If
certain conditions are met, entities may elect to designate a derivative
instrument as a hedge of exposures to changes in fair values, cash flows, or
foreign currencies. If the hedged exposure is a fair value exposure, the gain or
loss on the derivative instrument is recognized in earnings in the period of
change together with the offsetting loss or gain on the hedged item attributable
to the risk being hedged. If the hedged exposure is a cash flow exposure, the
effective portion of the gain or loss on the derivative instrument is reported
initially as a component of other comprehensive income (not included in
earnings) and subsequently reclassified into earnings when the forecasted
transaction affects earnings. Any amounts excluded from the assessment of hedge
effectiveness, as well as the ineffective portion of the gain or loss, is
reported in earnings immediately. Accounting for foreign currency hedges is
similar to the accounting for fair value and cash flow hedges. If the derivative
instrument is not designated as a hedge, the gain or loss is recognized in
earnings in the period of change. SFAS 133 is effective for all fiscal quarters
of fiscal years beginning after June 15, 2000. The Company anticipates that it
will adopt SFAS 133 effective October 1, 2000.
As noted above, the Company has hedged much of its anticipated oil and
gas production for the fiscal year ended September 30, 2000. The Company
currently accounts for its crude oil and natural gas hedges pursuant to
Statement of Financial Accounting Standards No. 80, Accounting for Futures
Contracts ("SFAS 80") and expects to do so until adoption of SFAS 133 is
required. Under SFAS 80 gains and losses from hedging activities are credited or
debited to the item being hedged. For natural gas marketing hedging activities,
the item being hedged was gas purchases. For exploration and production hedges,
the item being hedged is oil and gas sales.
The Company has not yet determined the impact of SFAS 133 on its
financial condition or results of operations.
RISK FACTORS
See above.
-26-
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
<TABLE>
<CAPTION>
Page
----
<S> <C>
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Statements of Operations for the Years Ended September 30, 1999, 1998 and 1997................. 28
Consolidated Balance Sheets as of September 30, 1999 and 1998............................................... 29
Consolidated Statements of Cash Flows for the Years Ended September 30, 1999, 1998 and 1997................. 30
Consolidated Statements of Stockholders' Equity and Other Comprehensive Income for the Years
Ended September 30, 1999, 1998 and 1997............................................................. 32
Notes to the Consolidated Financial Statements.............................................................. 33
INDEPENDENT AUDITORS' REPORT................................................................................ 57
</TABLE>
All other schedules are omitted because they are not applicable or the
required information is shown in the financial statements or notes thereto.
-27-
<PAGE>
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
("000's" Omitted Except Per Share Amounts)
<TABLE>
<CAPTION>
Year Ended September 30,
--------------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Revenues:
Natural gas marketing and transmission:
Gas sales.............................................. $ 50,067 $ 70,001 $ 64,599
Transportation......................................... 7
----------- ------------ -----------
50,067 70,001 64,606
------------ ------------- -----------
Exploration and production:
Oil and gas sales...................................... 6,712 2,373 6,740
Well operations........................................ 478 230 373
----------- ------------ -----------
7,190 2,603 7,113
----------- ------------ -----------
57,257 72,604 71,719
----------- ------------ -----------
Expenses:
Natural gas marketing and transmission:
Gas purchases.......................................... 31,062 43,254 39,966
Operating costs........................................ (16) 472
General and administrative............................. 35 62 776
Transportation......................................... 1,123 1,539 338
Depreciation and amortization.......................... 6,284 9,462 10,639
----------- ------------ -----------
38,504 54,301 52,191
----------- ------------ -----------
Exploration and production:
Oil and gas production................................. 2,388 775 1,940
General and administrative............................. 1,038 992 1,137
Depreciation, depletion and amortization............... 2,046 423 1,611
----------- ------------ -----------
5,472 2,190 4,688
----------- ------------ -----------
Corporate general and administrative..................... 4,112 3,081 3,370
----------- ------------ -----------
48,088 59,572 60,249
----------- ------------ -----------
Operating income............................................. 9,169 13,032 11,470
----------- ------------ -----------
Other income (expense):
Gain on sale of assets................................... 19,667
Interest income.......................................... 1,701 2,271 1,485
Other income (expense)................................... 352 (41) (55)
Interest expense......................................... (2) (1,038)
----------- ------------ -----------
2,053 2,228 20,059
----------- ------------ -----------
Income before provision for income taxes.................... 11,222 15,260 31,529
----------- ------------ -----------
Provision for income taxes:
State.................................................... 79 40 119
Federal.................................................. 2,877 1,164 4,544
----------- ------------ -----------
2,956 1,204 4,663
----------- ------------ -----------
Net income................................................... $ 8,266 $ 14,056 $ 26,866
=========== ============ ============
Net income per share:
Basic.................................................... $ 3.02 $ 3.71 $ 4.66
=========== ============ ==============
Diluted.................................................. $ 2.97 $ 3.66 $ 4.64
=========== ============ ==============
Weighted average number of common and potential dilutive
shares outstanding:
Basic................................................ 2,735,167 3,790,100 5,764,045
========== =========== ===========
Diluted.............................................. 2,782,644 3,837,903 5,795,341
========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements
-28-
<PAGE>
CASTLE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
("000's" Omitted Except Share Amounts)
<TABLE>
<CAPTION>
September 30,
---------------------
1999 1998
---- ----
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents......................................................... $ 22,252 $ 36,600
Restricted cash................................................................... 770 613
Accounts receivable............................................................... 5,172 8,381
Marketable securities............................................................. 4,194 471
Prepaid transportation, net....................................................... 1,123
Prepaid expenses and other current assets......................................... 594 293
Prepaid gas purchases............................................................. 852
Deferred income taxes............................................................. 2,765
Note receivable - Penn Octane Corporation......................................... 1,000
Estimated realizable value of discontinued net refining assets.................... 800 3,623
-------- --------
Total current assets............................................................ 33,782 55,721
Property, plant and equipment, net:
Natural gas transmission.......................................................... 60 62
Furniture, fixtures and equipment................................................. 298 307
Oil and gas properties, net (full cost method)....................................
Proved properties............................................................... 24,765 4,385
Unproved properties not being amortized......................................... 1,862 215
Gas contracts, net.................................................................... 6,285
Other assets.......................................................................... 29 29
-------- --------
Total assets.................................................................... $ 60,796 $ 67,004
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Dividend payable.................................................................. $ 368
Accounts payable.................................................................. 2,918 $ 8,658
Accrued expenses.................................................................. 802 1,663
Net refining liabilities retained................................................. 3,205 5,129
-------- --------
Total current liabilities....................................................... 7,293 15,450
Long-term liabilities................................................................. - 1
-------- --------
Total liabilities............................................................... 7,293 15,451
-------- --------
Commitments and contingencies.........................................................
Stockholders' equity:
Series B participating preferred stock; par value - $1.00;
10,000,000 shares authorized; no shares issued
Common stock; par value - $0.50; 25,000,000 shares authorized;
6,828,646 shares and 6,803,646 shares at September 30, 1999
and 1998, respectively.......................................................... 3,414 3,402
Additional paid-in capital........................................................ 67,365 67,122
Accumulated other comprehensive income - unrealized gains
on marketable securities, net of taxes.......................................... 2,396
Retained earnings................................................................. 41,054 34,836
--------- --------
114,229 105,360
Treasury stock at cost - 4,282,217 shares at September 30, 1999
and 3,862,917 shares at September 30, 1998...................................... (60,726) (53,807)
--------- --------
Total stockholders' equity...................................................... 53,503 51,553
--------- --------
Total liabilities and stockholders' equity...................................... $ 60,796 $ 67,004
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements
-29-
<PAGE>
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
("000's" Omitted Except Share Amounts)
<TABLE>
<CAPTION>
Year Ended September 30,
---------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Cash flows from operating activities:
Net income ............................................................... $ 8,266 $14,056 $ 26,866
-------- ------- --------
Adjustments to reconcile net income to cash provided by operating
activities:
Depreciation, depletion and amortization............................... 8,330 9,885 12,250
Amortization of deferred debt issue costs.............................. 343
Deferred income taxes.................................................. 2,765 968 3,983
Gain on sale of assets................................................. (19,667)
Unrealized gain on marketable securities............................... (481)
Impairment of Penn Octane preferred stock.............................. 423
Changes in assets and liabilities:
(Increase) decrease in restricted cash.............................. (157) (116) 1,246
(Increase) in marketable securities................................. (471)
(Increase) decrease in accounts receivable.......................... 3,209 (2,513) 4,349
Decrease in notes receivable........................................ 10,000
Decrease in prepaid transportation.................................. 1,123 1,539 338
(Increase) decrease in prepaid expenses and other current assets.... (301) 159 (379)
(Increase) decrease in other assets................................. (29) 371
(Increase) decrease in prepaid gas purchases........................ 852 (852)
Increase (decrease) in accounts payable............................. (5,740) 3,043 1,798
Increase (decrease) in accrued expenses............................. (861) 406 (3,351)
(Decrease) in other current liabilities............................. (2,037)
(Decrease) in other long-term liabilities........................... (62)
-------- ------- --------
Total adjustments............................................... 9,162 22,019 (818)
-------- ------- --------
Net cash flow provided by operating activities.................. 17,428 36,075 26,048
-------- ------- --------
Cash flows from investment activities:
Investment in marketable securities....................................... (269) (1,000)
Proceeds from sale of oil and gas assets and pipeline..................... 50,184
Realization from (liquidation of) discontinued net refining assets........ 900 (1,425) (1,860)
Acquisition of AmBrit oil and gas properties.............................. (20,170)
Investment in other oil and gas properties................................ (3,794) (2,212) (1,540)
Investment in pipelines................................................... (63) (59)
Purchase of furniture, fixtures and equipment............................. (98) (182) (4)
Other..................................................................... 42 (359)
-------- ------- --------
Net cash provided by (used in) investing activities............. (23,431) (4,840) 46,362
-------- ------- --------
</TABLE>
(continued on next page)
The accompanying notes are an integral part of these financial statements
-30-
<PAGE>
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
("000's" Omitted Except Share Amounts)
(continued from previous page)
<TABLE>
<CAPTION>
Year Ended September 30,
---------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Cash flows from financing activities:
Acquisition of treasury stock ............................................... (6,919) (28,644) (25,163)
Dividends paid to shareholders .............................................. (1,681) (2,393) (739)
Proceeds of long-term debt................................................... 17,658
Proceeds from exercise of stock options...................................... 255 64 797
Repayment of long-term debt.................................................. (31,664)
Payment of debt issuance costs............................................... (418)
------- ------- --------
Net cash (used in) financing activities................................ (8,345) (30,973) (39,529)
------- ------- --------
Net increase (decrease) in cash and cash equivalents............................ (14,348) 262 32,881
Cash and cash equivalents - beginning of period................................. 36,600 36,338 3,457
------- ------- --------
Cash and cash equivalents - end of period....................................... $22,252 $36,600 $ 36,338
======= ======= ========
Supplemental disclosures of cash flow information are as follows:
Cash paid during the period:
Interest.................................................................. $ 2 $ 1,137
======== ======= ========
Income taxes.............................................................. $ 108 $ 128 $ 863
======== ======= ========
Supplemental schedule of non-cash investing and financing activities............
Sale of oil and gas assets and pipeline:
Prepaid transportation received from purchaser............................ ($ 3,000)
=========
Accrued expenses offset against gain...................................... ($ 2,733)
=========
Other liabilities assumed by purchaser.................................... $ 1,623
=========
Accrued dividends............................................................ $ 368 $ 707
======== ==========
Conversion of Penn Octane Corporation note to marketable securities.......... $ 1,000
========
Unrealized gain on investment in available-for-sale marketable securities.... $ 2,396
========
</TABLE>
The accompanying notes are an integral part of these financial statements
-31-
<PAGE>
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
AND OTHER COMPREHENSIVE INCOME
("000's" Omitted Except Share Amounts)
<TABLE>
<CAPTION>
Years Ended September 30, 1999, 1998 and 1997
--------------------------------------------------------------------
Accumulated
Additional Other
Common Stock Paid-In Comprehensive Comprehensive
Shares Amount Capital Income Income
------ ------ ---------- ------------- -------------
<S> <C> <C> <C> <C> <C>
Balance - October 1, 1996...... 6,693,646 3,347 $66,316
Stock acquired.................
Options exercised.............. 105,000 52 745
Dividends declared ($.30 per share)
Net income.....................
--------- ----- ------
Balance - September 30, 1997... 6,798,646 3,399 67,061
Stock acquired.................
Options exercised.............. 5,000 3 61
Dividends declared ($.45 per share)
Net income.....................
--------- ----- -------
Balance - September 30, 1998... 6,803,646 3,402 67,122
Stock acquired.................
Options exercised.............. 25,000 12 243
Dividends declared ($.75 per share)
Comprehensive income...........
Net income................... $ 8,266
Other comprehensive income:
Unrealized gain on marketable
securities, net of tax.. 2,396 $2,396
--------- ------ ------- ------- ------
Balance - September 30, 1999... 6,828,646 $3,414 $67,365 $10,662 $2,396
========= ====== ======= ======= ======
</TABLE>
The accompanying notes are an integral part of these financial statements
<PAGE>
<TABLE>
<CAPTION>
Years Ended September 30, 1999, 1998 and 1997
---------------------------------------------
Retained Treasury Stock
Earnings ---------------------
(Deficit) Shares Amount Total
----------- --------- -------- --------
<S> <C> <C> <C> <C>
Balance - October 1, 1996...... ($2,952) $66,711
Stock acquired................. 2,085,100 ($25,163) (25,163)
Options exercised.............. 797
Dividends declared ($.30 per share) (1,446) (1,446)
Net income..................... 26,866 26,866
------ --------- -------- --------
Balance - September 30, 1997... 22,468 2,085,100 (25,163) 67,765
Stock acquired................. 1,777,817 (28,644) (28,644)
Options exercised.............. 64
Dividends declared ($.45 per share) (1,688) (1,688)
Net income..................... 14,056 14,056
------- --------- -------- --------
Balance - September 30, 1998... 34,836 3,862,917 (53,807) 51,553
Stock acquired................. 419,300 (6,919) (6,919)
Options exercised.............. 255
Dividends declared ($.75 per share) (2,048) (2,048)
Comprehensive income...........
Net income................... 8,266 8,266
Other comprehensive income:
Unrealized gain on marketable
securities, net of tax.. 2,396
------- --------- -------- -------
Balance - September 30, 1999... $41,054 4,282,217 ($60,726) $53,503
======= ========= ======== =======
</TABLE>
The accompanying notes are an integral part of these financial statements
-32-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
NOTE 1 - BUSINESS AND ORGANIZATION
Business Segments
Castle Energy Corporation ("the Company") is a public company
incorporated in Delaware. Mr. Joseph L. Castle II, Chairman of the Board and
Chief Executive Officer, and his wife own approximately twenty percent (20%) of
the Company's outstanding common stock at September 30, 1999.
The Company's only line of business at September 30, 1999 and at present
is oil and gas exploration and production. The Company's operations are
conducted in the United States and, to a minor extent, in Romania. Prior to
September 30, 1995 several of the Company's subsidiaries or former subsidiaries
were involved in the refining business. These subsidiaries discontinued refining
operations effective September 30, 1995, however several contingencies related
to closure of these refining assets are still outstanding. From December 1992 to
May 31, 1999, several of the Company's subsidiaries were involved in the natural
gas marketing business and from December 1992 to May 1997, another subsidiary
was involved in the gas transmission business. In May 1997, the Company sold its
gas transmission pipeline. All of the related long-term gas sales and gas
purchase contracts expired by their terms on May 31, 1999.
References to the Company mean Castle Energy Corporation, the parent,
and its subsidiaries. Such references are used for convenience and are not
intended to describe legal relationships.
Oil and Gas Exploration and Production
In May 1997, the Company sold the Rusk County, Texas oil and gas
properties which it acquired from Atlantic Richfield Company ("ARCO") to Union
Pacific Resources Company ("UPRC"). The reserves associated with such properties
constituted approximately 84% of the Company's proved oil and gas reserves at
the time (see Note 4).
In June 1999, the Company acquired all of the oil and gas assets of
AmBrit Energy Corp. ("AmBrit"). The AmBrit oil and gas assets included interests
in approximately 180 wells located in eight states. The proved oil and gas
reserves associated with the AmBrit acquisition were estimated to be
approximately 12.5 billion cubic feet of natural gas and 2,000 barrels of crude
oil or approximately one hundred and fifty percent (150%) of the Company's
proved reserves before such acquisition (see Note 4). During fiscal 1999, the
Company entered into two drilling agreements with other exploration and
production companies to participate in the drilling of approximately sixteen
exploratory wells in South Texas. During this period, the Company also entered
into an agreement to participate in the drilling of several wildcat wells in
Romania over a two to three year period. Finally, in November 1999, the Company
entered into an agreement to acquire majority interests in twenty-six wells
located in offshore Louisiana. Such interests, if ultimately acquired as
expected, will represent the Company's first investment in offshore drilling
(see Note 22).
Natural Gas Marketing
In December 1992, the Company acquired a long-term natural gas sales
contract with Lone Star Gas Company ("Lone Star Contract"). The Company also
entered into a gas sales contract and one gas purchase contract with MG Natural
Gas Corp. ("MGNG"), a subsidiary of MG Corp. ("MG"), which, in turn, is a United
States subsidiary of Metallgesellschaft A.G. ("MGAG"), a German conglomerate. In
May 1997, the Company sold its Rusk County, Texas natural gas pipeline to a
subsidiary of UPRC and thus exited the gas transmission business while still
conducting gas marketing operations. Effective May 31, 1999, the aforementioned
gas sales and gas purchases contracts expired May 31, 1999 by their own terms
and were not replaced by other third party gas marketing business. 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.
-33-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
Refining
IRLP
The Company indirectly entered the refining business in 1989 when one of
its subsidiaries acquired the operating assets of an idle refinery located in
Lawrenceville, Illinois (the "Indian Refinery"). The Indian Refinery was
subsequently operated by one of the Company's subsidiaries, Indian Refining I
Limited Partnership ("IRLP"), until September 30, 1995 when it was shut down. On
December 12, 1995, IRLP sold the Indian Refinery assets to American Western
Refining, L.P. ("American Western"). American Western subsequently filed for
bankruptcy and sold the Indian Refinery to an outside party which, we
understand, is in the process of dismantling it.
Powerine
In October 1993, a former subsidiary of the Company purchased Powerine
Oil Company ("Powerine"), the owner of a refinery located in Santa Fe Springs,
California (the "Powerine Refinery") from MG. On September 29, 1995, Powerine
sold substantially all of its refining plant to Kenyen Projects Limited
("Kenyen"). On January 16, 1996, Powerine merged into a subsidiary of Energy
Merchant Corp. ("EMC") and EMC, an unaffiliated entity, acquired the refinery
from Kenyen. EMC subsequently sold the refinery to an outside party which, we
are informed, is seeking financing to restart it.
As a result of the transactions with American Western, Kenyen and EMC,
the Company's refining subsidiaries disposed of their interests in the refining
business. The results of refining operations were shown as discontinued
operations in the Consolidated Statement of Operations for the year ended
September 30, 1995 and retroactively. Discontinued refining operations have not
impacted operations since fiscal 1995. Amounts on the balance sheet reflect the
remaining assets and liabilities that are pending final resolution of related
contingencies.
NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General
The significant accounting policies discussed are limited to those
applicable to the business segments in which the Company operated during the
fiscal years ended September 30, 1997, 1998 and 1999 - natural gas marketing and
transmission and exploration and production. References should be made to
previous Forms 10-K for summaries of accounting principles applicable to the
discontinued refining segment.
Principles of Consolidation
The consolidated financial statements presented include the accounts of
the Company and all of its subsidiaries. All significant intercompany
transactions have been eliminated in consolidation.
Revenue Recognition
Natural Gas Marketing
Revenues are recorded when deliveries are made. Essentially all of
the Company's deliveries were made under two long-term gas sales contracts, the
Lone Star Contract and a gas sales contract with MGNG. These contracts expired
May 31, 1999.
Exploration and Production
Oil and gas revenues are recorded under the sales method when oil and
gas production volumes are delivered to the purchaser. Fees from well operations
are recorded when earned.
-34-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
Cash and Cash Equivalents
The Company considers all highly liquid investments, such as time
deposits and money market instruments, purchased with a maturity of three months
or less, to be cash equivalents.
Natural Gas Transmission
Natural gas transmission assets included gathering systems and pipelines
and were depreciated on a straight-line basis over fifteen years, their
estimated useful life.
Marketable Securities
The Company currently classifies its investment securities as
available-for-sale securities. Pursuant to Statement of Financial Accounting
Standards No. 115 ("SFAS 115"), such securities are measured at fair market
value in the financial statements with unrealized gains or losses recorded in
other comprehensive income until the securities are sold or otherwise disposed
of. At such time gain or loss is included in earnings. Prior to July 1, 1999,
the Company classified its investment securities as trading securities and
included the difference between cost and fair market value in earnings.
Prepaid Gas Purchases
Prepaid gas purchases represented payments made by one of the Company's
subsidiaries for gas that the subsidiary was required to take but did not. All
prepaid gas purchases related to gas purchases from MGNG. Under the terms of the
related gas purchase contracts, the subsidiary was entitled to and did make up
the prepaid gas, i.e., to take it and not pay for it, once it had taken the
required minimum contract volume for the contract year. Prepaid gas purchase
costs were expensed as the subsidiary took delivery of the prepaid gas.
Furniture, Fixtures and Equipment
Furniture, fixtures and equipment are depreciated on a straight-line
basis over the estimated useful life of the assets. Furniture, fixtures and
equipment are depreciated on a straight-line basis over periods of three to ten
years and rolling stock is depreciated on a straight-line basis over four to
five years, the estimated useful lives of these assets.
Oil and Gas Properties
The Company follows the full-cost method of accounting for oil and gas
properties and equipment costs. Under this method of accounting, all productive
and nonproductive costs incurred in the acquisition, exploration and development
of oil and gas reserves are capitalized. Capitalized costs are amortized on a
composite unit-of-production method by country using estimates of proved
reserves. Capitalized costs which relate to unevaluated oil and gas properties
are not amortized until proved reserves are associated with such costs or
impairment of the related property occurs. Management and drilling fees earned
in connection with the transfer of oil and gas properties to a joint venture and
proceeds from the sale of oil and gas properties are recorded as reductions in
capitalized costs unless such sales are material and involve a significant
change in the relationship between the cost and the value of the remaining
proved reserves in which case a gain or loss is recognized. Expenditures for
repairs and maintenance of wellhead equipment are expensed as incurred. Net
capitalized costs, less related deferred income taxes, in excess of the present
value of net future cash inflows (oil and gas sales less production expenses)
from proved reserves, tax-effected and discounted at 10% and the cost of
properties not being amortized, if any, are charged to current expense.
Amortization and excess capitalized costs, if any, are computed separately for
the Company's investment in Romania.
Environmental Costs
The Company is subject to extensive federal, state and local
environmental laws and regulations. These laws, which are constantly changing,
regulate the discharge of materials into the environment and may require the
Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites. Environmental
expenditures are expensed or capitalized depending on their future expected
economic benefit to the Company.
-35-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
Expenditures that relate to an existing condition caused by past operations and
that have no future economic benefits are expensed. Liabilities for expenditures
of a noncapital nature are recorded when environmental assessment and/or
remediation is probable, and the costs can be reasonably estimated.
Impairment of Long-Term Assets
The Company reviews its long-term assets other than oil and gas
properties for impairment whenever events or changes in circumstance indicate
that the carrying amount of an asset may not be recoverable. If the sum of the
expected future cash flows expected to result from the use of the asset and its
eventual disposition is less than the carrying amount of the asset, an
impairment loss is recognized. Measurement of an impairment loss would be based
on the fair market value of the asset. Impairment for oil and gas properties is
computed in the manner described above under "Oil and Gas Properties."
Hedging Activities
Natural Gas Marketing
The Company used hedging strategies to hedge its future natural gas
purchase requirements for its gas sales contracts with Lone Star and MGNG (see
Notes 1 and 14). The Company hedged future commitments using natural gas swaps,
which were accounted for on a settlement basis. Gains and losses from hedging
activities were included in the item being hedged, the cost of gas purchased for
the Lone Star Contract or for the contract with MGNG. In order to qualify as a
hedge, the change in fair market value of the hedging instrument had to be
highly correlated with the corresponding changes in the hedged item.
Exploration and Production
The Company currently uses hedging strategies to hedge a significant
portion of its crude oil and natural gas production. The Company uses futures
contracts to hedge such production. Gains and losses from hedging activities are
deferred and are debited and credited to the item being hedged, oil and gas
sales, when they occur. In order to qualify as a hedge the change in fair market
value of the hedging instrument must be highly correlated with the corresponding
changes in the hedged item. When the hedging instrument ceases to qualify as a
hedge, changes in fair value are charged against or credit to earnings.
Gas Contracts
The purchase price allocated to the Lone Star Contract was capitalized
and amortized over the term of the related contract, 6.5 years.
Gas Balancing
The Company operates pursuant to several natural gas sales contracts
where one interest owner is entitled to sell other interest owners' shares of
natural gas produced if such other owners do not elect to sell their shares of
production. Under the terms of the related joint operating agreements, the
non-selling owners are entitled to make up gas sales from the selling owner's
share of production in the future. The Company records its sales of other
owners' production as deferred revenue and recognizes such deferred revenue when
the other owners make up their gas balancing deficiency from the Company's share
of production. Conversely, the Company records sales of its production by other
owners as deferred assets and recognizes such deferred assets when the Company
makes up its gas balancing deficiency from the other owners' share of
production. Deferred assets and liabilities are recorded at cost at the
production date.
Comprehensive Income
The Company adopted SFAS No. 130, "Reporting Comprehensive Income,"
effective October 1, 1998. Comprehensive income includes net income and all
changes in an enterprise's other comprehensive income including, among other
things, foreign currency translation adjustments, and unrealized gains and
losses on certain investments in debt and equity securities.
-36-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
Stock Based Compensation
Effective July 1, 1996, the Company adopted Statement of Financial
Accounting Standards No. 123, ("SFAS 123"). SFAS 123 allows an entity to
continue to measure compensation costs in accordance with Accounting Principle
Board Opinion No. 25 ("APB 25"). The Company has elected to continue to measure
compensation cost in accordance with APB 25 and to comply with the required
disclosure-only provisions of SFAS 123.
Income Taxes
The Company follows Statement of Financial Accounting Standards No. 109
("SFAS 109"), "Accounting for Income Taxes." SFAS 109 is an accounting approach
that requires the recognition of deferred tax assets and liabilities for the
expected future tax consequences of events that have been recognized in the
Company's financial statements or tax returns. In estimating future tax
consequences, SFAS 109 generally considers all expected future events other than
anticipated enactments of changes in the tax law or tax rates (see Note 18).
SFAS 109 also requires that deferred tax assets, if any, be reduced by a
valuation reserve based upon whether realization of such deferred tax asset is
or is not more likely than not.
Earnings Per Share
Basic earnings per common share are based upon the weighted average
number of common shares outstanding. Diluted earnings per common share are based
upon maximum possible dilution calculated using average stock prices during the
year.
In February 1997, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 128 ("SFAS 128"), "Earnings Per
Share," which established standards for computing and presenting earnings per
share ("EPS") for entities with publicly held common stock. SFAS 128 simplified
the standards for computing EPS previously found in Accounting Principles Board
Opinion No. 15, "Earnings Per Share," and made them comparable to international
EPS standards. It replaces the presentation of primary EPS with a presentation
of basic EPS, and required dual presentations of basic and diluted EPS on the
face of the income statement. SFAS 128 was effective for fiscal years ending
after December 15, 1997, and early adoption was not permitted. The Company has
adopted SFAS 128 for the fiscal year ended September 30, 1998 and has
retroactively restated EPS for fiscal 1997 in accordance with SFAS 128.
An analysis of basic and diluted earnings per share for each of the
three years ended September 30, 1999 is as follows:
<TABLE>
<CAPTION>
Year Ended September 30,
--------------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Weighted shares outstanding at beginning of the year............. 2,940,729 4,713,546 6,693,646
Options exercised................................................ 6,508 3,247 40,512
Stock repurchased................................................ (212,070) (926,693) (970,113)
---------- --------- ---------
Basic shares..................................................... 2,735,167 3,790,100 5,764,045
Assumed option exercise.......................................... 47,477 47,803 31,296
--------- --------- ---------
Diluted shares................................................... 2,782,644 3,837,903 5,795,341
========= ========= =========
</TABLE>
Reclassifications
Certain reclassifications have been made to make the periods presented
comparable.
Use of Estimates
The preparation of financial statements in accordance with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosures of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.
-37-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
New Accounting Pronouncements
In June 1997, FASB issued Statement of Financial Accounting Standards No.
130 ("SFAS 130") regarding reporting comprehensive income, which establishes
standards for reporting and display of comprehensive income and its components.
The components of comprehensive income refer to revenues, expenses, gains and
losses that are excluded from net income under current accounting standards,
including foreign currency translation items, minimum pension liability
adjustments and unrealized gains and losses on certain investments in debt and
equity securities. SFAS 130 requires that all items recognized under accounting
standards as components of comprehensive income be reported in a financial
statement displayed in equal prominence with the other financial statements; the
total of other comprehensive income for a period is required to be transferred
to a component of equity that is separately displayed in a statement of
financial condition at the end of an accounting period. SFAS 130 was effective
for both interim and annual periods for companies having fiscal years beginning
after December 15, 1997. Reclassification of financial statements for earlier
periods provided for comparative purposes was required. The Company adopted SFAS
130, effective October 1, 1998.
In June 1997, FASB issued Financial Accounting Standards Board No. 131
("SFAS 131") regarding disclosures about segments of an enterprise and related
information. SFAS 131 established standards for reporting information about
operating segments in annual financial statements and required the reporting of
selected information about operating segments in interim financial reports
issued to stockholders. It also established standards for related disclosures
about products and services, geographic areas and major customers. SFAS 131 was
effective for companies having fiscal years beginning after December 15, 1997.
The Company adopted SFAS No. 131 as of October 1, 1998. The provisions of SFAS
131 have not materially changed the Company's disclosures and reported financial
information to the present because the Company presented the required segment
information in its consolidated statements of operations for several years
before SFAS 131 was effective and continues to do so.
Statement of Financial Accounting Standards No. 133, Accounting for
Derivative Instruments and Hedging Activities ("SFAS 133"), was issued by the
Financial Accounting Standards Board in June 1998. SFAS 133 standardizes the
accounting for derivative instruments, including certain derivative instruments
embedded in other contracts. Under the standard, entities are required to carry
all derivative instruments in the statement of financial position at fair value.
The accounting for changes in the fair value (i.e., gains or losses) of a
derivative instrument depends on whether it has been designated and qualifies as
part of a hedging relationship and, if so, on the reason for holding it. If
certain conditions are met, entities may elect to designate a derivative
instrument as a hedge of exposures to changes in fair values, cash flows, or
foreign currencies. If the hedged exposure is a fair value exposure, the gain or
loss on the derivative instrument is recognized in earnings in the period of
change together with the offsetting loss or gain on the hedged item attributable
to the risk being hedged. If the hedged exposure is a cash flow exposure, the
effective portion of the gain or loss on the derivative instrument is reported
initially as a component of other comprehensive income (not included in
earnings) and subsequently reclassified into earnings when the forecasted
transaction affects earnings. Any amounts excluded from the assessment of hedge
effectiveness, as well as the ineffective portion of the gain or loss, is
reported in earnings immediately. Accounting for foreign currency hedges is
similar to the accounting for fair value and cash flow hedges. If the derivative
instrument is not designated as a hedge, the gain or loss is recognized in
earnings in the period of change. SFAS 133 is effective for all fiscal quarters
of fiscal years beginning after June 15, 2000. The Company anticipates that it
will adopt SFAS 133 effective October 1, 2000.
The Company has not yet determined the impact of SFAS 133 on its
financial statements or results of operations.
-38-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
NOTE 3 - DISCONTINUED REFINING OPERATIONS
Effective September 30, 1995, the Company's refining subsidiaries
discontinued their refining operations.
An analysis of the assets and liabilities related to the refining
segment for the period October 1, 1996 to September 30, 1999 is as follows:
<TABLE>
<CAPTION>
Estimated
Realizable Value
of Discontinued Net Refining
Net Refining Assets Liabilities Retained
------------------- --------------------
<S> <C> <C>
Balance - October 1, 1996............................................ $6,288 $11,079
Recovery related to the MG SWAP litigation........................... 703
Provision for platinum recovery...................................... (100)
Provision for American Western Note.................................. (2,469)
Cash transactions.................................................... (1,860)
Adjustments to vendor liabilities.................................... (1,722)
Other................................................................ (144)
------- ------
Balance - September 30, 1997......................................... 4,422 7,353
Reduction in estimated platinum recovery............................. (364)
Excess of MG Note over actual recovery in Powerine Arbitration....... (1,300)
Recovery of platinum proceeds........................................ (435)
Adjustment of vendor liabilities..................................... (732)
Cash transactions.................................................... (192)
------- ------
Balance - September 30, 1998......................................... 3,623 5,129
Reduction in estimated MG SWAP litigation recovery................... (129) (129)
Collection of MG SWAP litigation proceeds............................ (575) (575)
Additional recovery in connection with the Powerine Arbitration...... 900
Reduction in estimated recoverable value of note receivable
from American Western........................................ (2,119)
Adjustment of vendor liabilities..................................... (2,119)
Other................................................................ (1)
------- -------
Balance - September 30, 1999......................................... $ 800 $ 3,205
======= =======
</TABLE>
As of September 30, 1999, the estimated realizable value of discontinued
net refining assets consists of $800 of estimated recoverable proceeds from the
American Western note. The estimated value of net refining liabilities retained
consist of vendor liabilities of $1,470 and accrued costs related to
discontinued refining operations of $2,407, offset by cash of $672.
"Estimated realizable value of discontinued net refining assets" is
based on the transactions consummated by the Company with American Western and
transactions consummated by American Western and IRLP subsequently with others
and includes management's best estimates of the amounts expected to be realized
on upon the complete disposal of the refining segment. "Net refining liabilities
retained" includes management's best estimates of amounts expected to be paid
and amounts expected to be realized on the settlement of this net liability. The
amounts the Company ultimately realizes or pays could differ materially in the
near term from such amounts.
See Notes 12 and 13.
-39-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
NOTE 4 - ACQUISITIONS AND DISPOSITIONS
On May 30, 1997, the Company consummated the sale of its Texas oil and
gas properties and pipeline to UPRC and Union Pacific Intrastate Pipeline
Company ("UPIPC"), a wholly-owned subsidiary of UPRC, respectively. The
effective date of the sale was May 1, 1997. The assets sold included
approximately 8,150 net acres, 100 producing oil and gas wells and a 77-mile
pipeline which gathered gas from the producing wells and delivered it to a
pipeline owned by Lone Star. The proved reserves associated with the oil and gas
properties that were sold comprised approximately 84% of the Company's proved
reserves at that time.
The purchase price received by the Company was $54,759 and consisted of
$50,184 cash, $1,575 of the Company's liabilities assumed by UPRC and $3,000 of
prepaid gas transportation expense. The gas transportation prepayment related to
transportation of natural gas that the Company was required to supply to Lone
Star through May 31, 1999. As a result of the sale, the Company realized a gain
of $19,667 in fiscal 1997.
On June 1, 1999, the Company consummated the purchase of all of the oil
and gas properties of AmBrit. The oil and gas properties purchased include
interests in approximately 180 oil and gas wells in Alabama, Louisiana,
Mississippi, Montana, New Mexico, Oklahoma, Texas and Wyoming, as well as
undrilled acreage in several of these states. The effective date of the sale for
purposes of determining the purchase price was January 1, 1999. The adjusted
purchase price after accounting for all transactions between the effective date,
January 1, 1999, and the closing date, May 31, 1999, was $20,170. The entire
adjusted purchase price was allocated to "Oil and Gas Properties - Proved
Properties". Based upon reserve reports initially prepared by the Company's
petroleum reservoir engineers, the proved reserves (unaudited) associated with
the AmBrit oil and gas assets approximated 2,000 barrels of crude oil and 12,500
mcf (thousand cubic feet) of natural gas, which, together, approximate 150% of
the Company's oil and gas reserves before the acquisition. In addition, the
production acquired has increased the Company's consolidated production by
approximately 425%.
The results of operations on a pro-forma basis as though the oil and gas
properties of AmBrit had been acquired as of the beginning of the periods
indicated are as follows:
<TABLE>
<CAPTION>
Year Ended September 30,
-----------------------------------
1999 1998
------------ -------------
(Unaudited) (Unaudited)
<S> <C> <C>
Revenues.............................................................. $ 63,441 $ 81,993
Net income............................................................ $ 7,958 $ 14,208
Net income per share.................................................. $ 2.86 $ 3.70
Shares outstanding (diluted).......................................... 2,782,644 3,837,903
</TABLE>
These proforma results are presented for comparative purposes only and
are not necessarily indicative of the results which would have been obtained had
the acquisition been consummated as presented.
Operations related to the AmBrit oil and gas properties have been
included in the Company's Consolidated Statements of Operations since June 1,
1999, the closing date of the AmBrit acquisition.
Investment in Drilling Joint Ventures
In May 1999, the Company entered into a joint operating agreement with
another exploration and production company to drill up to twelve exploratory
wells in South Texas. The Company's commitment to the joint venture is $5,300
although most of this commitment may be rescinded by the Company if initial
drilling results are not as estimated. Subsequent to September 30, 1999, the
first exploratory well was drilled and resulted in a dry hole (see Note 22). As
of September 30, 1999, the Company's investment in this exploratory program was
$928. Such amount is included in "Oil and Gas Properties Unproved Properties Not
Being Amortized" in the "Consolidated Balance Sheets".
-40-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
In August 1999, the Company entered into another joint operating
agreement with a different exploration and production company to drill four
exploratory wells in South Texas. The total cost to the Company is expected to
approximate $2,200.
Investment in Romanian Concessions
In April 1999, the Company purchased an option to acquire fifty percent
(50%) of three oil and gas concessions granted to a subsidiary of Costilla
Energy Corporation ("Costilla"), by the Romanian government. The Company paid
Costilla $65 for the option. In May 1999, the Company exercised the option. The
Company expects that its minimum obligation for the Romanian concessions will be
approximately $3,000. As of September 30, 1999, the Company's investment in
Romania was $934. Such amount is included in "Oil and Gas Properties - Unproved
Properties Not Being Amortized" in the "Consolidated Balance Sheets".
In November 1999, the Company entered into an agreement to acquire
majority operating interests in twenty-six (26) wells in offshore Louisiana and
additional interests in several wells in Alabama and Pennsylvania (see Note 22).
NOTE 5 - RESTRICTED CASH
Restricted cash consists of the following:
<TABLE>
<CAPTION>
September 30,
---------------------
1999 1998
---- ----
<S> <C> <C>
Drilling deposits in escrow - Romania............................ $551
Funds supporting letters of credit issued for operating bonds.... 219 $218
Other............................................................ 395
---- ----
$770 $613
==== ====
</TABLE>
The drilling deposits in escrow in Romania are to be used only to
conduct exploratory and drilling activities in Romania and cannot be withdrawn
or used for other purposes by the Company. Subsequent to September 30, 1999, the
Company incurred $354 of exploration costs, which were paid from the drilling
deposit escrow account.
NOTE 6 - ACCOUNTS RECEIVABLE
Based upon past customer experiences, the limited number of customer
accounts receivable relationships, and the fact that the Company's subsidiaries
can generally offset unpaid accounts receivable against an outside owner's share
of oil and gas revenues, management believes substantially all receivables are
collectible. Accounts receivable consist of the following:
<TABLE>
<CAPTION>
September 30,
------------------------
1999 1998
---- ----
<S> <C> <C>
Natural gas marketing - trade.................................... $6,870
Exploration and production - trade............................... $3,354 1,343
Margin account - hedging......................................... 1,750
Interest......................................................... 68 168
------ ------
$5,172 $8,381
====== ======
</TABLE>
Accounts receivable due from Lone Star aggregated zero, $6,719 and
$3,441 at September 30, 1999, 1998 and 1997, respectively.
-41-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
NOTE 7 - MARKETABLE SECURITIES
All of the Company's investment in marketable securities consists of
common shares of Penn Octane Corp. ("Penn Octane"), a public company involved in
sales of liquid propane gas to northern Mexico.
At September 30, 1998, the Company accounted for its investment as
trading securities. The 766,667 share increase from September 30, 1998 to
September 30, 1999 resulted because the Company purchased 200,000 registered
Penn Octane common shares on the market and ultimately received 566,667
unregistered common shares in exchange for its $1,000 note after first
converting most of the note to Penn Octane preferred stock. In March 1999, the
Company began to account for its investment as available-for-sale securities.
The Company's investment in Penn Octane common stock was as follows:
September 30,
--------------------
1999 1998
---- ----
Gross cost....................................... $ 1,750 $ 575
Unrealized gain (loss)........................... 2,444 (104)
--------- --------
Book value....................................... $ 4,194 $ 471
========= ========
Shares of Penn Octane common stock owned:
Registered................................. 501,000 301,000
Unregistered............................... 566,667
--------- --------
1,067,667 301,000
========= ========
The fair market value of Penn Octane shares was based on one hundred
percent (100%) of the closing price on September 30, 1999.
In addition to the foregoing, the Company owns options to purchase
225,000 common shares of Penn Octane common stock at $1.75 per share and options
to purchase 166,667 common shares of Penn Octane common stock at $6.00 per
share. The options to purchase 225,000 shares of Penn Octane common stock at
$1.75 per share have no book value but have a market value of $492 at September
30, 1999 based upon the closing market price of Penn Octane common stock at
September 30, 1999.
In November 1999, Penn Octane informed the Company that it was
registering the Company's unregistered shares and options.
NOTE 8 - FURNITURE, FIXTURES AND EQUIPMENT
Furniture, fixtures and equipment are as follows:
September 30,
---------------------
1999 1998
---- ----
Cost:
Furniture and fixtures.......... $603 $532
Automobile and trucks........... 106 76
---- ----
709 608
Accumulated depreciation.............. (411) (301)
---- ----
$298 $307
==== ====
-42-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
NOTE 9 - GAS CONTRACTS
Gas contracts consisted of the following:
September 30,
----------------------
1999 1998
---- ----
Gas contracts............................... $61,151
Less: Accumulated amortization.......... (54,866)
-------
$ 6,285
=======
NOTE 10 - OIL AND GAS PROPERTIES
Oil and gas properties consist of the following:
<TABLE>
<CAPTION>
September 30,
-----------------------
1999 1998
----- ----
<S> <C> <C>
Proved properties........................................... $34,684 $12,367
Less: Accumulated depreciation, depletion and amortization. (9,919) (7,982)
------- -------
24,765 4,385
Unproved properties......................................... 1,862 215
------- -------
$26,627 $ 4,600
======= =======
</TABLE>
Capital costs incurred by the Company in oil and gas activities are as
follows:
<TABLE>
<CAPTION>
Year Ended September 30,
--------------------------------------------------------------
1999
---------------------------------
United 1998 1997
States Romania Total (U.S.) (U.S.)
------ ------- ----- ------ ------
<S> <C> <C> <C> <C> <C>
Acquisition of properties:
Proved properties.............................. $21,029 $21,029 $ 17 $ 274
Unproved properties............................ 928 $934 1,862
Exploration.......................................
Development....................................... 1,073 1,073 2,195 1,266
------- ---- ------- ------ ------
$23,030 $934 $23,964 $2,212 $1,540
======= ==== ======= ====== ======
</TABLE>
Until September 30, 1998, all of the Company's capital costs were
incurred in the United States. As of September 30, 1999, the Company had
incurred $934 in Romania for unproven property acquisition costs.
<PAGE>
Results of operations, excluding corporate overhead and interest
expense, from the Company's oil and gas producing activities are as follows:
<TABLE>
<CAPTION>
Year Ended September 30,
--------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Revenues:
Crude oil, condensate, natural gas liquids and natural gas sales.... $6,712 $2,373 $6,740
------ ------ ------
Costs and expenses:
Production costs.................................................... 2,388 775 1,940
Depreciation, depletion and amortization............................ 1,937 367 1,560
------ ------ ------
Total costs and expenses............................................ 4,325 1,142 3,500
------ ------ ------
Income tax provision.................................................... 859 443 1,166
------ ------ ------
Income from oil and gas producing activities............................ $1,528 $ 788 $2,074
====== ====== ======
</TABLE>
-43-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
The income tax provision is computed at a blended rate (Federal and
state combined) of 36%.
Assuming conversion of oil and gas production into common equivalent
units of measure on the basis of energy content, depletion rates per equivalent
MCF (thousand cubic feet) of natural gas were as follows:
<TABLE>
<CAPTION>
Year Ended September 30,
---------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Depletion rate per equivalent MCF of natural gas.......... $0.71 $0.37 $ 0.58
===== ===== =======
</TABLE>
The significant increase in the depletion rate in fiscal 1999 resulted
primarily from the acquisition of the oil and gas properties of AmBrit in June
1999. The cost per equivalent mcf of natural gas acquired was approximately $.82
versus a cost of $.37 per equivalent mcf of natural gas applicable to the
Company's other oil and gas properties.
The significant decrease in the depletion rate in fiscal 1998 resulted
from the Company's sale of its oil and gas assets to UPRC in May 1997. After the
sale, the cost per cubic foot equivalent of natural gas for the Company's
remaining reserves was significantly less than it was before the sale as a
result of accounting for the sale to UPRC as a disposition under the full cost
method.
NOTE 11 - PROVED OIL AND GAS RESERVES AND RESERVE VALUATION (UNAUDITED)
Reserve estimates are based upon subjective engineering judgements made
by the Company's independent petroleum reservoir engineers, Huntley & Huntley
(fiscal 1999, 1998 and 1997) and Ralph E. Davis Associates, Inc. (fiscal 1999)
and may be affected by the limitations inherent in such estimations. The process
of estimating reserves is subject to continuous revisions as additional
information is made available through drilling, testing, reservoir studies and
production history. There can be no assurance such estimates will not be
materially revised in subsequent periods.
Estimated quantities of proved reserves and changes therein, all of which
are domestic reserves, are summarized below:
<TABLE>
<CAPTION>
Oil (BBLS) Natural Gas (MCF)
---------- -----------------
<S> <C> <C>
Proved developed and undeveloped reserves:
As of October 1, 1996.......................... 462 69,629
Revisions of previous estimates............ 59 5,591
Sale of minerals in place.................. (279) (57,074)
Production................................. (36) (2,454)
---- -------
As of September 30, 1997....................... 206 15,692
Revisions of previous estimates............ 69 501
Production................................. (20) (869)
------ -------
As of September 30, 1998....................... 255 15,324
Acquisitions............................... 2,021 12,529
Revisions of previous estimates............ (122) 2,520
Production................................. (124) (1,971)
----- ------
As of September 30, 1999....................... 2,030 28,402
===== ======
Proved developed reserves:
September 30, 1996............................. 312 34,764
====== ======
September 30, 1997............................. 206 11,480
====== ======
September 30, 1998............................. 162 13,589
====== ======
September 30, 1999............................. 1,788 23,547
===== ======
</TABLE>
Although the Company has recently invested in a Romanian drilling
concession no proved reserves have yet been discovered. As a result, all of the
Company's proved oil and gas reserves are located in the United States.
-44-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
The following is a standardized measure of discounted future net cash
flows and changes therein relating to estimated proved oil and gas reserves, as
prescribed in Statement of Financial Accounting Standards No. 69. The
standardized measure of discounted future net cash flows does not purport to
present the fair market value of the Company's oil and gas properties. An
estimate of fair value would also take into account, among other factors, the
likelihood of future recoveries of oil and gas in excess of proved reserves,
anticipated future changes in prices of oil and gas and related development and
production costs, a discount factor based on market interest rates in effect at
the date of valuation and the risks inherent in reserve estimates.
<TABLE>
<CAPTION>
September 30,
---------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Future cash inflows................................................ $118,794 $40,576 $46,595
Future production costs............................................ (42,934) (14,141) (13,979)
Future development costs........................................... (4,229) (1,283) (2,025)
Future income tax expense.......................................... (8,538) (4,868) (7,045)
-------- ------- -------
Future net cash flows.............................................. 63,093 20,284 23,546
Discount factor of 10% for estimated timing of future cash flows... (21,849) (10,338) (12,779)
-------- ------- -------
Standardized measure of discounted future cash flows............... $ 41,244 $ 9,946 $10,767
======== ======== =======
</TABLE>
The future cash flows were computed using the applicable year-end prices
and costs that related to then existing proved oil and gas reserves in which the
Company has mineral interests. The estimates of future income tax expense are
computed at the blended rate (Federal and state combined) of 36%.
The following were the sources of changes in the standardized measure of
discounted future net cash flows:
<TABLE>
<CAPTION>
September 30,
----------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Standardized measure, beginning of year............................. $ 9,946 $10,767 $24,494
Sale of oil and gas, net of production costs........................ (4,324) (1,598) (4,800)
Net changes in prices............................................... 2,163 (2,498) 1,461
Sale of reserves in place........................................... (17,849)
Purchase of reserves in place....................................... 22,215
Changes in estimated future development costs....................... 2,405 (615) (120)
Development costs incurred during the period that reduced future
development costs................................................ 1,073 2,195 349
Revisions in reserve quantity estimates............................. 1,438 594 4,675
Net changes in income taxes......................................... 745 831 529
Accretion of discount............................................... 995 1,077 2,449
Other, principal changes in timing of production.................... 4,588 (807) (421)
------- ------- -------
Standardized measure, end of year................................... $41,244 $ 9,946 $10,767
======= ======= =======
</TABLE>
<PAGE>
NOTE 12 - ENVIRONMENTAL MATTERS
In December 1995, IRLP sold the Indian Refinery to American Western. As
part of the related purchase and sale agreement, American Western assumed all
environmental liabilities and indemnified the Company 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 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.
-45-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
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. In
January 1996, Powerine merged into a subsidiary of EMC 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 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 clean up costs for this refinery are $80,000 -
$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 fifty years, the
Company would expect that its share of any remediation liability, if any, 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.
NOTE 13 - COMMITMENTS, CONTINGENCIES AND LINE OF CREDIT
Operating Lease Commitments
The Company has the following noncancellable operating lease commitments
and noncancellable sublease rentals at September 30, 1999:
<TABLE>
<CAPTION>
Lease Sublease
Year Ending September 30, Commitments Rentals
- ------------------------- ----------- ---------
<S> <C> <C>
2000........................................................ $ 328 $ 63
2001........................................................ 295 64
2002........................................................ 247 65
2003........................................................ 208 66
2004........................................................ 39
----- ----
1,117 $258
===== ====
</TABLE>
Rent expense for the years ended September 30, 1999, 1998 and 1997 was
$386, $245 and $200, respectively.
-46-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
Severance/Retention Obligations
The Company and one of its subsidiaries have severance agreements with
substantially all of their employees that provide for severance compensation in
the event substantially all of the Company's or the subsidiary's assets are sold
and the employees are terminated as a result of such sale. Such termination
severance commitments aggregated approximate $861 at September 30, 1999. No
severance obligations are outstanding at September 30, 1999.
Letters of Credit
At September 30, 1999, the Company had issued letters of credit of $219
for oil and gas drilling, operating and plugging bonds. The letters of credit
are renewed semi-annually or annually.
Legal Proceedings
Contingent Environmental Liabilities
See Note 12.
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 from the arbitration and sought an additional $2,142 plus interest. In
January 1999, the Company recovered $900 in connection with the $2,142 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 until May 1997. The lawsuit was filed in the Fourth Judicial
District at Rusk County, Texas.
The lawsuit, as initially filed, sought unspecified net production
revenues resulting from reversionary interests on several wells operated by the
subsidiary. Management believes the Company's exposure on the matter, if any, is
less than $50.
Subsequently the plaintiffs expanded their petition claiming amounts due
in excess of $250 based upon their interpretation of other provisions in 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 - MGR&M
In January 1998, IRLP filed suit against MG Refining and Marketing, Inc.
("MGR&M"), a subsidiary of MG, to collect $704 plus interest. The dispute
concerned funds owed to IRLP but not paid by MGR&M. In February 1998, MG
contended that the $704 was not owed to IRLP and that it had liquidated MGR&M.
In April 1999, IRLP recovered $575 of the $704 sought. The difference between
the book value, $704, and the actual recovery, $575, 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).
Powerine/EMC/Litigation
In July 1998, the Company sued Powerine and EMC to recover $330 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
-47-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
whereby Powerine merged into a subsidiary of EMC. In April 1999, the Company
recovered $355 from EMC. The recovery was recorded as other income.
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 million.
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
only 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 possible exposure of the Company and its subsidiary limited
partnerships for all gas sold to Lone Star in the past and in the future, were
they to lose the case on all points, was less than $3,000. 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 future production, thus reducing the exposure of the Company and its
subsidiaries to less than $2,000 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. One of the Company's exploration and production
subsidiaries seeks to recover gas measurement and transportation expenses
charged by the defendants in breach of a certain gas purchase contract. Improper
charges exceed $750 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 the Company's subsidiary 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
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 trail 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 1999, MGNG filed a second lawsuit against the Company and
three of its subsidiaries claiming $772 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 and are entitled to legally offset some or all
of the $772 claimed against amounts owed to Production by MGNG for improper gas
measurement and transportation deductions. The Castle entities have answered
this suit denying MGNG's claims based partially on the right of offset.
-48-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
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.
Hedging Activities
Until June 1, 1999, the Company's natural gas marketing subsidiary
utilized natural gas swaps to reduce its exposure to changes in the market price
of natural gas. Effective May 31, 1999 all natural gas marketing contracts
terminated by their own terms. As a result of these hedging transactions, the
cost of gas purchases increased $609 and $410 for the years ended September 30,
1999 and 1998, respectively, and decreased $624 for the year ended September 30,
1997. As of September 30, 1999, the subsidiary had no natural gas purchase
hedging contracts outstanding.
On June 1, 1999, the Company acquired all of the oil and gas assets of
AmBrit (see Note 4) and thereafter commenced hedging sales of the related oil
and gas production. As of September 30, 1999, the Company had hedged
approximately 54% of its anticipated consolidated crude oil production and
approximately 39% of its anticipated consolidated natural gas production for the
period from October 1, 1999 to September 30, 2000. In addition, at September 30,
1999, the Company had hedged approximately 14% of its anticipated natural gas
production for the fiscal year ended September 30, 2001. The Company has used
futures contracts to hedge such production. The average hedged prices for crude
oil and natural gas, which are based upon futures price on the New York
Mercantile Exchange, are $19.85 per barrel of crude oil and $2.66 per mcf of
gas. The Company anticipates that these futures contracts will be accounted for
as hedges and that differences between the hedged price and the exchange price
will increase or decrease the oil and gas revenues resulting from the sale of
production by the Company. Oil and gas production was not hedged through July
1999 production. As a result of these hedging transactions, oil and gas sales
decreased $149 for the year ended September 30, 1999.
The volumes of oil and gas production hedged and the notional dollar
amounts of the related hedging contracts were as follows:
<TABLE>
<CAPTION>
Fair September 30, 1999
Value -----------------------------------------------------
Amount Dollars Volumes
------ ------- ---------------------------------------
<S> <C> <C> <C>
Future contracts to sell natural gas........... (530) $5,568 2,100,000 MMbtu (British Thermal Units)
Futures contracts to sell crude oil............ (60) 3,933 198,000 Barrels
------ ------
($590) $9,501
====== ======
</TABLE>
At September 30, 1999, the market value of these hedges was an
unrealized loss of $590. At September 30, 1999, the Company had a $1,750 hedging
margin escrow deposit with the broker (see Note 6). To the extent that the
future oil and gas sales prices increase above their levels at September 30,
1999, the Company could be obligated to increase its hedging margin escrow
deposits.
-49-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
Line of Credit
In February 1999, the Company received a $30,000 line of credit from an
energy bank. The line of credit expires in February 2001. The amount that can be
borrowed by the Company will be limited to a borrowing base which is to be
determined annually by the energy bank. The interest rate to be paid by the
Company will depend upon the amount borrowed and the collateral provided but is
not expected to exceed the prime rate. In exchange for receiving the line of
credit, the Company paid a syndication fee of $40 and must pay an additional fee
of 1/2% of each borrowing under the facility.
The Company has not yet used the line of credit.
NOTE 14 - EMPLOYEE BENEFIT PLAN
401-K Plan
On October 1, 1995, the Company adopted a 401(k) plan (the "Plan") for
its employees and those of its subsidiaries. All employees are eligible to
participate. Employees participating in the Plan can authorize the Company to
contribute up to 15% of their gross compensation to the Plan. The Company
matches such voluntary employee contributions up to 3% of employee gross
compensation. Employees' contributions to the Plan cannot exceed thresholds set
by the Secretary of the Treasury. Vesting of Company contributions is immediate.
During the years ended September 30, 1999, 1998 and 1997, the Company's
contributions to the Plan aggregated $37, $23 and $38, respectively.
Post Retirement Benefits
Neither the Company nor its subsidiaries provide any other post
retirement plans for employees.
NOTE 15 - STOCKHOLDERS' EQUITY
From November 1996 until September 30, 1999, the Company's Board of
Directors authorized the Company to purchase up to 4,750,000 of its outstanding
shares of common stock on the open market. As of September 30, 1999, 4,282,217
shares had been repurchased at a cost of $60,726. The repurchased shares are
held in treasury. Subsequent to September 30, 1999, the Company purchased an
additional 203,800 shares at a cost of $3,466 (see Note 22).
On June 30, 1997, the Company's Board of Directors approved a dividend
policy of $.60 per share per year, payable quarterly. The dividend policy
remains in effect until rescinded or changed by the Board of Directors.
Quarterly dividends of $.15 per share have subsequently been paid.
NOTE 16 - STOCK OPTIONS AND WARRANTS
Option and warrant activities during each of the three years ended
September 30, 1999 are as follows (in whole units):
<TABLE>
<CAPTION>
Non- Incentive
Incentive Qualified Plan Other
Options Options Options Options Total
--------- --------- --------- ------- --------
<S> <C> <C> <C> <C> <C>
Outstanding - October 1, 1996............. 2,500 77,500 288,000 20,000 388,000
Issued.................................... 57,000 20,000 77,000
Exercised................................. (2,500) (67,500) (35,000) (105,000)
Cancelled................................. (10,000) (10,000)
Expired................................... (147,500) (15,000) (162,500)
----- ------- -------- ------- --------
Outstanding at September 30, 1997......... 162,500 25,000 187,500
Issued.................................... 55,000 55,000
Exercised................................. (5,000) (5,000)
Repurchased............................... (17,500) (5,000) (22,500)
Expired...................................
----- ------- -------- ------- --------
Outstanding at September 30, 1998......... 195,000 20,000 215,000
</TABLE>
-50-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
<TABLE>
<CAPTION>
Non- Incentive
Incentive Qualified Plan Other
Options Options Options Options Total
--------- --------- --------- ------- -------
<S> <C> <C> <C> <C> <C>
Issued.................................... 15,000 15,000
Exercised................................. (25,000) (25,000)
Repurchased............................... (10,000) (10,000)
Expired...................................
--------- --------- -------- ------- -------
Outstanding at September 30, 1999......... 175,000 20,000 195,000
========= ========= ======== ======= =======
Exercisable at September 30, 1999......... 175,000 20,000 195,000
======= ======= =======
Reserved at September 30, 1999............ 562,500 20,000 582,500
======= ======= =======
Reserved at September 30, 1998............ 562,500 20,000 582,500
========= ========= ======== ======= =======
Reserved at September 30, 1997............ 562,500 25,000 587,500
========= ========= ======== ======= =======
Exercise prices at:
September 30, 1999................ $10.25- $11.375
$17.25
September 30, 1998................ N/A N/A $10.25- $10.75-
$17.25 $11.375
September 30, 1997................ N/A N/A $ 8.44- $11.00-
$14.25 $11.375
Exercise Termination Dates........ N/A N/A 5/17/2003- 4/23/2007 5/17/2003-
1/03/2009 1/03/2009
</TABLE>
In fiscal 1993, the Company adopted the 1992 Executive Equity Incentive
Plan (the "Incentive Plan"). The purpose of the Incentive Plan is to increase
the ownership of common stock of the Company by those non-union key employees
(including officers and directors who are officers) and outside directors who
contribute to the continued growth, development and financial success of the
Company and its subsidiaries, and to attract and retain key employees and reward
them for the Company's profitable performance.
The Incentive Plan provides that an aggregate of 562,500 shares of
common stock of the Company will be available for awards in the form of stock
options, including incentive stock options and non-qualified stock options
generally at prices at or in excess of market prices at the date of grant.
The Incentive Plan also provides that each outside director of the
Company will annually be granted an option to purchase 5,000 shares of common
stock at fair market value on the date of grant.
The Company applies Accounting Principles Board Opinion Number 25 in
accounting for options and warrants and accordingly recognizes no compensation
cost for its stock options and warrants for grants with an exercise price equal
to the current fair market value. The following reflect the Company's pro-forma
net income and net income per share had the Company determined compensation
costs based upon fair market values of options and warrants at the grant date
pursuant to SFAS 123 as well as the related disclosures required by SFAS 123.
-51-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
A summary of the Company's stock option and warrant activity from
October 1, 1996 to September 30, 1999 is as follows:
<TABLE>
<CAPTION>
Weighted
Average
Options Price
--------- --------
<S> <C> <C>
Balance outstanding - October 1, 1996...................... 388,000 $10.59
Issued..................................................... 77,000 10.78
Exercised.................................................. (105,000) 7.60
Cancelled.................................................. (10,000) 8.00
Expired.................................................... (162,500) 11.50
------- ------
Outstanding - September 30, 1997........................... 187,500 11.69
Issued..................................................... 55,000 16.23
Exercised.................................................. (5,000) 12.65
Repurchased................................................ (22,500) 10.43
Expired....................................................
------- ------
Outstanding - September 30, 1998........................... 215,000 12.96
Issued..................................................... 15,000 17.25
Exercised.................................................. (25,000) (10.25)
Repurchased................................................ (10,000) 10.75
Expired....................................................
------- ------
Outstanding - September 30, 1999........................... 195,000 $13.75
======= ======
</TABLE>
At September 30, 1999 exercise prices for outstanding options ranged
from $10.25 to $17.25. The weighted average remaining contractual life of such
options was 6.7 years.
The per share weighted average fair values of stock options issued
during fiscal 1999 , fiscal 1998 and fiscal 1997 were $4.56, $3.92 and $2.84,
respectively, on the dates of issuance using the Black-Scholes option pricing
model with the following weighted average assumptions: expected dividend yield -
3.5% in 1999, 3.6% in 1998 and 4.3% in 1997; risk free interest rate - 6.32% in
1999, 5.03% in 1998 and 5.81% in 1997; expected life of 10 years in 1999, 1998
and 1997 and volatility factor of .22 in 1999, .24 in 1998 and .30 in 1997.
The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the fair value estimate, in
management's opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of its employee stock options.
Pro-forma net income and earnings per share had the Company accounted
for its options under the fair value method of SFAS 123 is as follows:
<TABLE>
<CAPTION>
Year Ending September 30,
------------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Net income as reported............................................... $8,266 $14,056 $26,866
Adjustment required by FAS 123....................................... (152) (132) (214)
------ ------- -------
Pro-forma net income................................................. $8,114 $13,924 $26,652
====== ======= =======
Pro-forma net income per share:
Basic............................................................. $ 2.97 $ 3.67 $ 4.62
====== ======= =======
Diluted........................................................... $ 2.92 $ 3.63 $ 4.60
====== ======= =======
</TABLE>
-52-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
NOTE 17 - INCOME TAXES
Provisions for (benefit of) income taxes consist of:
<TABLE>
<CAPTION>
September 30,
------------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Provision for (benefit of) income taxes:
Current:
Federal....................................................... $ 193 $ 223 $ 862
State......................................................... (2) 13 37
Deferred:
Federal....................................................... 2,209 1,653 13,506
State......................................................... 68 47 362
Adjustment to the valuation allowance for deferred taxes:
Federal....................................................... 475 (712) (9,824)
State......................................................... 13 (20) (280)
------ ------ --------
$2,956 $1,204 $ 4,663
====== ====== ========
</TABLE>
Deferred tax assets (liabilities) are comprised of the following at
September 30, 1999 and 1998:
<TABLE>
<CAPTION>
September 30,
----------------------
1999 1998
---- ----
<S> <C> <C>
Operating losses and tax credit carryforwards....................................... $3,775 $5,781
Depletion accounting................................................................ (1,044) (890)
Amortization (gas contracts)........................................................ 439
Discontinued net refining operations................................................ 866 543
------ ------
3,597 5,873
Valuation allowance................................................................. (3,597) (3,108)
------ ------
- $2,765
====== ======
Deferred tax assets - current....................................................... $2,765
Deferred tax assets - non-current...................................................
------ ------
$2,765
====== ======
</TABLE>
In 1999, the Company increased its valuation allowance by $489 to
$3,597 because all of the taxable income expected from the Lone Star Contract,
upon which the net deferred tax asset was previously based, had been received by
September 30, 1999 and utilization of the Company's net operating losses was not
anticipated given the Company's large exploratory and wildcat drilling
commitments, the expiration of the Lone Star Contract, contingent environmental
liabilities and other factors. In fiscal 1998, the Company reduced its valuation
reserve by $732 to $3,108 based upon the decreased probability of additional
losses related to discontinued refining operations. In fiscal 1997, the Company
reduced its valuation reserve by $10,104 to $3,840 in anticipation of future
taxable income from the Lone Star Contract.
The Company has not recorded a net deferred tax asset at September 30,
1999 because realization of such net deferred tax asset is not more likely than
not given the expiration of the Lone Star Contract, oil/gas price risk,
operational risks, drilling risks and reserve risks.
-53-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
The income tax provision (benefit) differs from the amount computed by
applying the statutory federal income tax rate to income (loss) before income
taxes as follows:
<TABLE>
<CAPTION>
Year Ended September 30,
------------------------------------
1999 1998 1997
---- ---- ----
<S> <C> <C> <C>
Tax at statutory rate.................................................... $3,928 $5,341 $11,035
State taxes, net of federal benefit...................................... 51 26 315
Reversal of tax estimates and contingencies.............................. (151) (3,463)
Statutory depletion and tax credits...................................... (1,330) 4,312
Increase (decrease) in valuation allowance............................... 489 (732) (10,104)
Other.................................................................... (31) 32 (895)
------ ------ --------
$2,956 $1,204 $ 4,663
====== ====== ========
</TABLE>
At September 30, 1999, the Company had the following tax carryforwards
available:
<TABLE>
<CAPTION>
Federal Tax
----------------------------------
Alternative
Minimum
Regular Tax
------- -----------
<S> <C> <C>
Net operating loss...................................................... $1,396 $22,620
Alternative minimum tax credits......................................... $3,273 N/A
Statutory depletion..................................................... $9,992 -
Investment tax credit................................................... $ 28 N/A
</TABLE>
The net operating loss and investment tax credit carryforwards expire
from 2000 through 2008.
On September 9, 1994, the Company experienced a change of ownership for
tax purposes. As a result of such change of ownership, the Company's net
operating loss became subject to an annual limitation of $7,845. Such annual
limitation, however, was increased by the amount of net built-in gain at the
time of the change of ownership. Such net built-in gain aggregated $219,430.
During the fiscal years ended September 30, 1999, 1998 and 1997 the Company used
$4,367, $10,295 and $45,499, respectively, of its net operating loss
carryforwards, including $37,278 of built-in gains.
The Company also has approximately $50,000 in individual state tax loss
carryforwards available at September 30, 1999. Such carryforwards are primarily
available to offset taxable income apportioned to certain states in which the
Company has no operations and currently has no plans for future operations. As a
result it is probable most of such state tax carryforwards will expire unused.
NOTE 18 - RELATED PARTIES
Sale of Subsidiaries
On March 31, 1993, the Company entered into an agreement to sell to
Terrapin Resources, Inc. ("Terrapin") its oil and gas partnership management
businesses for $1,100 ($800 note bearing interest at 8% per annum and $300 cash)
which approximated book value. The closing of the stock purchase transaction
occurred on June 30, 1993. Terrapin is wholly-owned by an officer and director
of the Company. In December 1994, the note was repaid.
In conjunction with the sale of its partnership management business,
the Company and one of its exploration and production subsidiaries entered into
two management agreements with Terrapin to manage its exploration and production
operations. The second agreement was amended in 1996 to include corporate
accounting functions.
-54-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
In June 1997, the Company purchased, for $692, one of the Terrapin
management agreements in conjunction with the sale of the Company's Rusk County,
Texas oil and gas properties to UPRC. The remaining contract with Terrapin was
month to month.
In September 1997, Terrapin granted the Company an option to acquire
its accounting software and computer equipment. The option price was one dollar
plus assumption of Terrapin's office and equipment rentals and employee
obligations. Effective June 30, 1998, the Company exercised the option and hired
most of Terrapin's employees.
Management fees incurred to Terrapin for the years ended September 30,
1999, 1998 and 1997 aggregated zero, $292 and $561, respectively.
In June 1999, the Company repurchased 24,700 shares of the Company's
common stock from the officer. Such shares were repurchased at the closing stock
price on the date of sale less $.125, resulting in a payment of $434 to the
officer. The shares were repurchased pursuant to the Company's share repurchase
program.
NOTE 19 - BUSINESS SEGMENTS
As of September 30, 1995, the Company had disposed of its refining
segment of the energy business (see Note 3) and operated in only two business
segments - natural gas marketing and transmission and exploration and
production. In May 1997, the Company sold its pipeline (natural gas
transmission) to a subsidiary of UPRC (see Note 4). As a result, the Company was
no longer in the natural gas transmission segment but continued to operate in
the natural gas marketing and exploration and production segments. On May 31,
1999, the Company's long-term gas sales and gas supply contracts expired by
their own terms and the Company exited the natural gas marketing business.
<TABLE>
<CAPTION>
Year Ended September 30, 1999
----------------------------------------------------------------------------------------
Natural Gas Oil & Gas Eliminations
Marketing Exploration and
and and Refining Corporate
Transmission Production (Discontinued) Items Consolidated
------------ ----------- -------------- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues........................... $50,067 $ 7,190 $57,257
Operating income (loss)............ $11,563 $ 1,718 ($ 4,112) $ 9,169
Identifiable assets................ $79,026 $67,720 ($87,208) $59,538
Capital expenditures............... $24,065 $24,065
Depreciation, depletion and
amortization.................... $ 6,284 $ 2,046 $ 8,330
</TABLE>
<TABLE>
<CAPTION>
Year Ended September 30, 1998
----------------------------------------------------------------------------------------
Natural Gas Oil & Gas Eliminations
Marketing Exploration and
and and Refining Corporate
Transmission Production (Discontinued) Items Consolidated
------------ ----------- -------------- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues........................... $70,001 $ 2,603 $72,604
Operating income (loss)............ $15,700 $ 413 ($ 3,081) $13,032
Identifiable assets................ $62,424 $49,724 ($45,144) $67,004
Capital expenditures............... $ 2,457 $ 2,457
Depreciation, depletion and
amortization.................... $ 9,462 $ 423 $ 9,885
</TABLE>
-55-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
<TABLE>
<CAPTION>
Year Ended September 30, 1997
----------------------------------------------------------------------------------------
Natural Gas Oil & Gas Eliminations
Marketing Exploration and
and and Refining Corporate
Transmission Production (Discontinued) Items Consolidated
------------ ----------- -------------- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues........................... $68,029 $ 7,113 ($3,423) $71,719
Operating income (loss)............ $12,415 $ 2,425 ($3,370) $11,470
Identifiable assets................ $41,667 $48,666 ($7,616) $82,717
Capital expenditures............... $ 59 $ 1,544 $ 1,603
Depreciation, depletion and
amortization.................... $10,639 $ 1,611 $12,250
</TABLE>
For the years ended September 30, 1999, 1998 and 1997, sales by the
Company's natural gas marketing subsidiary to Lone Star Gas Company under the
Lone Star Contract aggregated $46,802, $64,619 and $59,695, respectively. These
amounts constituted approximately 82%, 89% and 83%, respectively, of
consolidated revenues for the years ended September 30, 1999, 1998 and 1997,
respectively. The Lone Star contract terminated in May 1999.
At the present time, the Company's consolidated revenues consist
primarily of oil and gas sales. Approximately three purchasers of the Company's
oil and gas production, each of which accounts for over 10% of the Company's
consolidated reserves, currently account for approximately 60% of consolidated
revenues and are expected to comprise a similar percentage of oil and gas sales
for fiscal 2000.
NOTE 20 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS
Cash and Cash Equivalents -- Cash and cash equivalent, the carrying
amount is a reasonable estimate of fair value.
Marketable securities are related solely to the Company's investment in
Penn Octane common stock and are recorded at fair market value. Market value is
computed to equal the closing share price at year end times the number of shares
held by the Company.
Hedges -- At September 30, 1999, the Company had hedged approximately 198
barrels of crude oil and 2,100 MMbtu of gas that it expects to produce before
December 31, 2000. The book value of such hedges is zero and the fair market
value of the hedges based upon their market value was an unrealized loss of $590
at September 30, 1999 (See Note 13).
Other Current Assets and Current Liabilities - the Company believes that
the book values of other current assets and current liabilities approximate the
market values.
NOTE 21 - QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
First Second Third Fourth
Quarter Quarter Quarter Quarter
(December 31) (March 31) (June 30) (September 30)
------------- ---------- --------- --------------
<S> <C> <C> <C> <C>
Fiscal 1999:
Revenues................................... $20,936 $22,365 $9,668 $4,288
Operating income before interest and
income taxes............................ $ 3,455 $ 4,825 $ 145 $ 744
Net income................................. $ 2,511 $ 3,938 $ 900 $ 917
Net income per share (diluted)............. $ .84 $ 1.37 $ .34 $ .35
</TABLE>
-56-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("000's" Omitted Except Share and Per Share Amounts)
<TABLE>
<CAPTION>
First Second Third Fourth
Quarter Quarter Quarter Quarter
(December 31) (March 31) (June 30) (September 30)
------------- ---------- --------- --------------
<S> <C> <C> <C> <C>
Fiscal 1998:
Revenues................................. $20,979 $18,504 $17,464 $15,657
Operating income before interest and
income taxes.......................... $ 3,752 $ 3,369 $ 3,525 $ 2,386
Net income............................... $ 2,822 $ 2,542 $ 6,864 $ 1,828
Net income per share (diluted)........... $ .60 $ .61 $ 2.02 $ .60
</TABLE>
The sums of the quarterly per share amounts for fiscal 1999 ($2.90) and
fiscal 1998 ($3.83) differ from the annual per share amounts of $2.97 in fiscal
1999 and $3.66 in fiscal 1998 primarily because the stock purchases made by the
Company were not made in equal amounts and at corresponding times each quarter.
NOTE 22 - SUBSEQUENT EVENTS
Subsequent to September 30, 1999, the Company repurchased an additional
203,800 shares of its common stock at a cost of $3,466.
Subsequent to September 30, 1999, CECI acquired additional outside
interests in several Alabama wells which it operates for $372. In addition, the
Company entered into three agreements to acquire additional oil and gas
interests in operated wells in Alabama and Pennsylvania and to acquire majority
interests in twenty-six (26) offshore Louisiana wells. The adjusted purchase
price for these acquisitions, assuming closings as planned, is expected to
approximate $3,075 and will be financed from working capital.
Subsequent to September 30, 1999, the first well drilled in one of the
Company's South Texas drilling ventures resulted in a dry hole. The Company is
planning to participate in the drilling of at least two additional wells.
-57-
<PAGE>
Independent Auditors' Report
The Board of Directors
Castle Energy Corporation:
We have audited the accompanying consolidated balance sheets of Castle Energy
Corporation and subsidiaries as of September 30, 1999 and 1998, and the related
consolidated statements of operations, stockholders' equity and other
comprehensive income, and cash flows for each of the years in the three year
period ended September 30, 1999. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Castle Energy
Corporation and subsidiaries as of September 30, 1999 and 1998, and the results
of their operations and their cash flows for each of the years in the three year
period ended September 30, 1999 in conformity with generally accepted accounting
principles.
KPMG LLP
Houston, Texas
December 14, 1999
-58-
<PAGE>
PART III
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE**
None
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT**
ITEM 11. EXECUTIVE COMPENSATION**
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT**
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS**
- --------------
** The information required by Item 10, 11, 12 and 13 is incorporated by
reference to the Registrant's Proxy Statement for its 2000 Annual Meeting
of Stockholders.
-59-
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. and 2. Financial Statements and Financial Statement Schedules
Financial statements and schedules filed as part of this Report on Form 10-K
are listed in Item 8 of this Form 10-K.
3. Exhibits
The Exhibits required by Item 601 of Regulation S-K and filed herewith or
incorporated by reference herein are listed in the Exhibit Index below.
Exhibit Number Description of Document
-------------- -----------------------
3.1 Restated Certificate of Incorporation(15)
3.2 Bylaws(10)
4.1 Specimen Stock Certificate representing Common Stock(8)
4.2 Rights Agreement between Castle Energy Corporation and
American Stock Transfer and Trust Company as Rights
Agent, dated as of April 21, 1994(10)
10.33 Castle Energy Corporation 1992 Executive Equity
Incentive Plan(8)
10.34 First Amendment to Castle Energy Corporation 1992
Executive Equity Incentive Plan, effective
May 11, 1993(8)
10.120 Option Agreement dated July 10, 1997 between Terrapin
Resources, Inc. and Castle Energy Corporation(19)
10.121 Closing Agreement, dated May 30, 1997 by and among
Castle Energy Corporation, Castle Texas Production
L.P., Union Pacific Resources Company and Castle
Exploration Company, Inc. (25)
10.122 Purchase and Sale Agreement by and among Castle Energy
Corporation and Castle Texas Pipeline L.P. and Union
Pacific Intrastate Pipeline Company, dated May 16, 1997
(20)
10.123 Purchase and Sale Agreement by and among Castle Energy
Corporation and Castle Texas Production L.P. and Union
Pacific Resources Company dated May 16, 1997 (20)
10.124 Asset Purchase Agreement dated February 27, 1998 by and
between Castle Energy Corporation and Alexander Allen,
Inc. (21)
10.125 Rollover and Assignment Agreement, dated December 1,
1998 between Penn Octane Corporation and Certain
Lenders, including Castle Energy Corporation (22)
10.126 Purchase and Sale Agreement by and between AmBrit
Energy Corp. and Castle Exploration Company, Inc.,
effective January 1, 1999 (23)
10.127 Agreement to Exchange $.9 Million Secured Notes Into
Senior Preferred Stock of Penn Octane Corporation dated
March 3, 1999 (23)
10.128 Credit Agreement by and among Castle Exploration
Company, Inc. and Comerica Bank-Texas, effective May
28, 1999 (24)
10.129 Purchase and Sale Agreement by and between Costilla
Redeco Energy LLC and Castle Exploration Company, Inc.,
effective May 31, 1999 (24)
10.130 Letter dated July 22, 1999 between Penn Octane
Corporation and Castle Energy Corporation
10.131 Letter dated July 29, 1999 between Penn Octane
Corporation and Castle Energy Corporation
10.132 Castle Energy Corporation Severance Benefit Plan
11.1 Statement re: Computation of Earnings Per Share
21 List of subsidiaries of Registrant
-60-
<PAGE>
Exhibit Number Description of Document
-------------- -----------------------
23.2 Consent of Ralph E. Davis Associates, Inc.
23.3 Consent of Huntley & Huntley, Inc.
23.4 Consent of KPMG LLP
27 Financial Data Schedule
(b) Reports on Form 8-K
The Company filed one report on Form 8-K during the last quarter of
the Company's fiscal year ended September 30, 1999. That report is dated June
15, 1999. The report concerned the acquisition of AmBrit's oil and gas
properties. A subsequent amendment to this report, dated August 11, 1999,
containing proforma financial statements, was subsequently filed.
- ------------------
(8) Incorporated by reference to the Registrant's Form S-1 (Registration
Statement), dated September 29, 1993
(10) Incorporated by reference to the Registrant's Form 10-Q for the second
quarter ended March 31, 1994
(15) Incorporated by reference to the Registrant's Form 10-K for the fiscal
year ended September 30, 1994
(19) Incorporated by reference to the Registrant's Form 10-K for the fiscal
year ended September 30, 1997.
(20) Incorporated by reference to the Registrant's Form 8-K dated May 30, 1997
(21) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
March 31, 1998
(22) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
December 31, 1998
(23) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
March 31, 1999
(24) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
June 30, 1999
(25) Incorporated by reference to the Registrant's Form 10-K for the fiscal
year ended September 30, 1998
-61-
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
CASTLE ENERGY CORPORATION
Date: December 6, 1999 By:/s/JOSEPH L. CASTLE II
-----------------------------------
Joseph L. Castle II
Chairman of the Board
and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed by the following persons on behalf of the registrant
in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
<S> <C> <C>
/s/JOSEPH L. CASTLE II
- --------------------------- Chairman of the Board and Chief December 6, 1999
Joseph L. Castle II Executive Officer
Director
/s/MARTIN R. HOFFMANN
- --------------------------- Director December 6, 1999
Martin R. Hoffmann
/s/JOHN P. KELLER
- ---------------------------- Director December 6, 1999
John P. Keller
/s/RICHARD E. STAEDTLER
- ---------------------------- Senior Vice President December 6, 1999
Richard E. Staedtler Chief Financial Officer
Chief Accounting Officer
Director
/s/SIDNEY F. WENTZ
- --------------------------- Director December 6, 1999
Sidney F. Wentz
</TABLE>
-62-
<PAGE>
DIRECTORS AND OFFICERS
BOARD OF DIRECTORS
(November 30, 1999)
JOSEPH L. CASTLE II RICHARD E. STAEDTLER
Chairman & Chief Executive Officer Chief Financial Officer and Chief
Accounting Officer
MARTIN R. HOFFMANN SIDNEY F. WENTZ
Of Counsel to Washington, D.C. Former Chairman of The Robert Wood
Office of Skadden, Arps, Slate, Johnson Foundation
Meagher & Flom
JOHN P. KELLER
President, Keller Group, Inc.
OPERATING OFFICERS
JOSEPH L. CASTLE II RICHARD E. STAEDTLER
Chief Executive Officer Chief Financial Officer
Chief Accounting Officer
TIMOTHY M. MURIN
President - Exploration and
Production
<PAGE>
PRINCIPAL OFFICES
One Radnor Corporate Center 531 Plymouth Road, Suite 525
Suite 250 Plymouth Meeting, PA 19462
100 Matsonford Road
Radnor, PA 19087
12731 Power Plant Road 61 McMurray Road, Suite 204
Tuscaloosa, AL 35406 Pittsburgh, PA 15241-1633
P.O. Box 425
Acme, PA 15610-0425
PROFESSIONALS
Counsel Independent Reservoir Engineers
Duane, Morris & Heckscher LLP Huntley & Huntley, Inc.
One Liberty Place, 42nd Floor Corporate One II, Suite 100
Philadelphia, PA 19103-7396 4075 Monroeville Blvd.
Monroeville, PA 15146
Independent Accountants Ralph E. Davis Associates, Inc.
3555 Timmons Lane, Suite 1105
KPMG LLP Houston, Texas 77027
700 Louisiana
Houston, Texas 77002
Registrar and Transfer Agent
American Stock Transfer & Trust Company
40 Wall Street, 46th Floor
New York, New York 10005
<PAGE>
POCC Exhibit 10.130
Penn Octane Corporation
- --------------------------------------------------------------------------------
July 22, 1999
Mr. Joseph Castle
President
Castle Energy Corporation
One Radnor Corporate Center, Suite 250
100 Matsonford Road
Radnor, PA 19087
Via Facsimile
- -------------
Dear Joe:
This letter will confirm Castle Energy Corporation's ("CEC") decision
to convert $100,000 of the principal amount of note receivable due June 30,
1999, from Penn Octane Corporation into new shares of common stock of Penn
Octane Corporation. The conversion rate shall be one (1) share for each $1.50 of
principal amount of indebtedness (total of 66,667 shares). The anticipated date
of closing is July 29, 1999. Any interest accrued and unpaid as of July 29, 1999
shall be paid on July 29, 1999.
Please acknowledge your agreement with the above by signing below and
returning a faxed copy to 562 929-1921.
Regards,
/s/IAN T. BOTHWELL
------------------
Ian T. Bothwell
Accepted and Agreed to this 26th day of July, 1999
By:/s/Joseph Castle
-------------
Name: Castle
cc: J.B. Richter
R. Staedtler
<PAGE>
POCC Exhibit 10.131
Penn Octane Corporation
- --------------------------------------------------------------------------------
July 29, 1999
Mr. Joseph Castle
President
Castle Energy Corporation
One Radnor Corporate Center, Suite 250
100 Matsonford Road
Radnor, PA 10987
Via Facsimile
- -------------
Dear Joe:
This letter will confirm that the issues surrounding the Certificate of
Designation, Powers, Preferences and Rights of the Series B Convertible
Redeemable Preferred Stock (the "Preferred Stock"), including those regarding
anti-dilution, arising in connection with the $900,000 preferred stock
transaction between Castle Energy Corporation and Penn Octane Corporation in
March 1999, have been resolved between parties based on the following changes:
1. The conversion rate of the Preferred Stock will be increased from
4 shares of common stock of Penn Octane Corporation for each share
of Preferred Stock to 5 shares of common stock of Penn Octane
Corporation for each share of Preferred Stock (subject to
adjustment as more fully described in the Certificate of
Designation), and
2. The annual dividend rate on the Preferred Stock will be reduced to
$1.00 per share from $1.20 per share.
Based on the above, we will modify the latest draft Certificate of
Designation for these changes and immediately file the Certificate with the
State of Delaware.
Please acknowledge your agreement with the above by signing below and
returning a faxed copy to 562 929-1921.
Regards,
/s/ IAN T. BOTHWELL
-------------------
Ian T. Bothwell
Accepted and Agreed to this 30th day of July, 1999
By: /s/ Joseph Castle
-----------------
Name: Jos. L. Castle
<PAGE>
Exhibit 10.132
CASTLE ENERGY CORPORATION
SEVERANCE BENEFIT PLAN
<PAGE>
CASTLE ENERGY CORPORATION
SEVERANCE BENEFIT PLAN
This Castle Energy Corporation Severance Benefit Plan is designed to
provide severance benefits to a select group of management employees of Castle
Exploration Company, Inc. and its affiliates in the event their employment is
involuntarily terminated without cause.
Article 1: Definitions
As used herein the following terms have the meanings set forth in this
Article 1, unless a different meaning is plainly required by the context.
1.1 "Board" means the Board of Directors of the Company.
1.2 "Cause" means conduct detrimental to the Employer and its
employees, including:
1.2.1 fraud, embezzlement, misappropriation or other criminal
conduct;
1.2.2 neglect of duties or responsibilities as an employee;
1.2.3 falsification of Employer records or reports;
1.2.4 deliberate or reckless action which causes actual or
potential injury or loss to the Employer or its employees;
1.2.5 material violation of Employer policies or rules; or
1.2.6 illegal acts on Employer property or in representing the
Employer.
1.3 "Compensation" means the cash compensation, including bonuses, paid
to an Eligible Employee for his services to the Employer. "Compensation" shall
be determined before reduction for any employee contributions to savings or
health benefit plans maintained by the Employer.
1.4 "Compensation Committee" means the Compensation Committee of the
Board.
1.5 "Company" means Castle Energy Corporation, a Delaware corporation.
1.6 "Eligible Employee" means an individual designated by the
Compensation Committee as eligible to participate in this Plan and whose name
appears in Exhibit A.
1.7 "Employer" means the Company, Castle Exploration Company, Inc., and
any of its affiliates. For purposes of Sections 1.3, 2.1 and 4.3, Employer means
1
<PAGE>
all of these entities; for purposes of Section 1.2 and 3.4, Employer means any
of them; and for purposes of Section 3.1, it means only those that have actually
employed the Eligible Employee.
1.8 "Plan" means the Castle Energy Corporation Severance Benefit Plan
set forth in this document, as it may be amended from time to time.
1.9 "Plan Year" means each calendar year that the Plan is in effect.
1.10 "Severance Benefit" means the benefit payable under Article 3.
1.11 "Severance Date" means the date selected by the Employer on which
an Eligible Employee's employment termination becomes effective.
1.12 "Termination Event" means (i) a reduction of at least 30% in the
Eligible Employee's then current Compensation from the Employer; or (ii) the
permanent assignment of the Eligible Employee to an office that is situated
beyond a radius of 50 miles from the office to which the Eligible Employee is
currently assigned.
Article 2: Eligibility for Severance Benefits
2.1 An Eligible Employee whose employment with the Employer has been
involuntarily terminated shall be entitled to receive a Severance Benefit,
provided:
2.1.1 his employment is not terminated for Cause;
2.1.2 he does not voluntarily resign before his Severance Date;
2.1.3 he executes and returns to the Company a written general
release, in form and substance satisfactory to the Company, of any and all
claims against the Employer and all related parties with respect to all matters
arising out of his employment by the Employer or his employment termination; and
2.1.4 he agrees to perform up to 125 hours of post-severance
service for the Employer as described in Section 3.4.
2.2 For purposes of Section 2.1, an Eligible Employee's employment with
the Employer shall be considered to have been involuntarily terminated if the
Eligible Employee resigns within 45 days after a Termination Event occurs.
Article 3: Payment of Severance Benefits
3.1 Amount and Form of Benefits. Except as otherwise provided in
Section 3.3, an Eligible Employee who satisfies the requirements of Section 2.1
and 3.4 shall receive from his Employer a Severance Benefit in an amount equal
2
<PAGE>
to his Compensation for the twelve month period ending on his Severance Date.
The Severance Benefit shall be paid in seven unequal monthly installments: the
first installment shall equal 50% of the Severance Benefit, each of the next
five installments shall equal 8.33% thereof and the last installment shall equal
the remaining 8.35%.
3.2 Timing of Payments. Payment of an Eligible Employee's Severance
Benefit shall commence as soon as administratively feasible following his
Severance Date and the Company's receipt of the executed written release
required by Section 2.1.3, but in no case more than one month after the release
is executed.
3.3 Termination of Payments. An Eligible Employee shall cease to
participate in the Plan and any remaining Severance Benefit payments shall cease
upon discovery of Cause, whether or not such discovery occurs before the
Eligible Employee's Severance Date.
3.4 Post Severance Services of Eligible Employees. During the period
over which the Severance Benefit is paid and as a condition of continuing to
receive those payments, the Eligible Employee shall assist the Employer by
performing up to 125 hours of service on matters with which the Eligible
Employee had been involved while an active employee, if requested by the
Employer. The scheduling of this work shall be done by the Employer after taking
into account the Eligible Employee's personal schedule and work requirements. If
the Employer requires more than 125 hours of service from an Eligible Employee,
the Employer shall pay the Eligible Employee the reasonable hourly rate agreed
upon by the parties for each hour in excess of 125. The Employer may request all
or a portion of the 125 hours as soon as it has paid the first installment
pursuant to Section 3.1.
Article 4: General Provisions
4.1 Plan Administration. The Plan shall be administered by the Company,
which shall be the Plan's "named fiduciary" and "administrator" as those terms
are used in the Employee Retirement Income Security Act of 1974, as amended. As
administrator, the Company shall have the power to interpret and construe any
ambiguous or disputable provisions of the Plan and to decide related questions
that may arise in connection with the operation of the Plan, including the
determination of disputed facts and application of Plan provisions to
unanticipated circumstances. The Company may consult with an attorney,
accountant, actuary or other experts and rely upon their opinions as it deems
necessary and proper. The decision, determination or action of the Company with
respect to any questions arising out of or in connection with the
administration, operation and interpretation of the Plan shall be conclusive and
binding upon all persons having or claiming an interest in the Plan.
4.2 Funding of the Plan. This Plan shall be unfunded, and the payment
of benefits hereunder shall be made from the general assets of the Company.
3
<PAGE>
4.3 Right to Amend or Terminate Plan. The Board may amend the Plan from
time to time or terminate the Plan at any time; provided, however, that no
amendment or termination shall reduce the benefits to which an Eligible Employee
is entitled hereunder during the four year period beginning on the date that the
Eligible Employee is so designated by the Board.
4.4 Benefit Claims Procedures. In the event a claim by a terminated
Eligible Employee relating to the amount of his benefit or its method of payment
is denied, such person will be given written notice by the Company of such
denial, which notice will set forth the reason for the denial. The terminated
Eligible Employee may, within 60 days after receiving the notice, request a
review of such denial by filing a notice in writing with the Company. The
Company in its discretion may request a meeting with the terminated Eligible
Employee to clarify any matters it deems pertinent. The Company will render a
written decision within 60 days after receipt of such request stating the
reasons for its decision. If the Company is unable to respond within 60 days, an
additional 60 days may be taken by the Company to respond. The terminated
Eligible Employee will be notified if this additional time is necessary by the
end of the initial 60-day period.
4.5 Nonalienation of Severance Benefits. No Eligible Employee shall
have the right to alienate, anticipate, pledge, assign or in any way create a
lien upon any benefit payable hereunder, and no benefit shall be assignable in
anticipation of payment either by voluntary or involuntary acts, or by operation
of law.
4.6 No Right to Employment. Nothing herein shall be deemed to give any
Eligible Employee the right to be retained in the service of the Employer or to
interfere with the rights of the Employer to discharge any Eligible Employee at
any time.
4.7 Exclusive Severance Benefit. This Plan supersedes and is in lieu of
any other severance arrangements that an Eligible Employee has with the
Employer.
4.8 Payment Due Persons Under Disability. If the Company determines
that any person to whom a payment is due hereunder is unable to care for his
affairs by reason of physical or mental incapacity, the Company shall have the
power to direct that the benefit payment due to such person be made to another
for his benefit without any responsibility to see to the application of such
payment. Any payment so made shall, as to the amount of such payment, operate as
a complete discharge of the Company therefor.
4.9 Records, Reporting and Disclosure. The Company shall keep all
records necessary for the proper operation of the Plan. Such records shall be
made available to each Eligible Employee for examination during business hours
except that an Eligible Employee shall examine only such records as pertain
exclusively to such examining Eligible Employee and to the Plan text. The
Company shall prepare and shall file as required by law or regulation all
reports, forms, documents and other items required by the Employee Retirement
Income Security Act of 1974, as amended, the Internal Revenue Code of 1986, as
amended, and each other relevant statute, including without limitation those
4
<PAGE>
relating to withholding of income taxes, Social Security taxes and other amounts
which may be similarly reportable.
4.10 Lost Payees. A Severance Benefit shall be deemed forfeited if the
Company, after reasonable efforts, is unable to locate a terminated Eligible
Employee to whom a Severance Benefit is due. Such Severance Benefit shall be
reinstated if application is made therefor by the terminated Eligible Employee
while this Plan is in operation but in no event more than one year after the
Severance Benefit first becomes due and payable.
4.11 Expenses. All expenses of administering the Plan shall be paid by
the Employer.
4.12 Gender. Whenever used herein, unless the context otherwise
indicates, words in the masculine form shall be deemed to refer to females as
well as males.
4.13 Titles and Headings. The titles of Articles and headings of
Sections in this Plan are for convenience of reference only and in case of any
conflict the text of the Plan, rather than such titles and headings, shall
control.
4.14 Governing Law. This Plan shall be construed and enforced according
to the internal laws of the Commonwealth of Pennsylvania, to the extent not
preempted by federal law.
IN WITNESS WHEREOF, and as evidence of its adoption of this Plan, the
Company, on behalf of itself and the other adopting Employer, has caused the
same to be executed by its duly authorized officers and its corporate seal to be
affixed hereto as of August 19, 1999.
Attest: CASTLE ENERGY CORPORATION
/s/SUSAN PYLE By: /s/JOSEPH L. CASTLE
- ---------------------- ----------------------
Secretary President
5
<PAGE>
Exhibit A
Eligible Employees
under the
Castle Energy Corporation Severance Benefit Plan
Richard E. Staedtler
Timothy M. Murin
Susan Pyle
Mary Cade
6
<PAGE>
Exhibit 11.1
1 of 2
Castle Energy Corporation
Statement of Computation of Earnings Per Share
(Dollars in thousands, except per share amounts)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended September 30,
----------------------------------------------------------------------
1999 1998
--------------------------------- -----------------------------
Basic Diluted Basic Diluted
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
I. Weighted Shares Outstanding, Net of Treasury
Stock Outstanding - Beginning of Period:
Stock, net 2,591,329 2,591,329 3,014,029 3,014,029
Purchase of treasury stock (weighted) (16,594) (16,594) (42,148) (42,148)
---------- ---------- ---------- ----------
2,574,735 2,574,735 2,971,881 2,971,881
II. Weighted Equivalent Shares:
Options and warrants assumed exercised 40,922 56,661
---------- ---------- ---------- ----------
III. Weighted Average Shares and Equivalent Shares 2,574,735 2,615,657 2,971,881 3,028,542
========== ========== ========== ==========
IV. Net Income $ 917 $ 917 $ 1,828 $ 1,828
========== ========== =========== ==========
V. Net Income Per Share $ .36 $ .35 $ .62 $ .60
========== ========== ========== ==========
</TABLE>
<PAGE>
Exhibit 11.1
2 of 2
Castle Energy Corporation
Statement of Computation of Earnings Per Share
(Dollars in thousands, except per share amounts)
(Unaudited)
<TABLE>
<CAPTION>
Twelve Months Ended September 30,
------------------------------------------------------------------------
1999 1998
--------------------------------- ---------------------------------
Basic Diluted Basic Diluted
---------- ---------- ---------- ----------
<S> <C> <C> <C> <C>
I. Weighted Shares Outstanding, Net of Treasury
Stock Outstanding - Beginning of Period: 2,940,729 2,940,729 4,713,546 4,713,546
Options and warrants exercised 6,508 6,508 3,247 3,247
Stock repurchased (212,070) (212,070) (926,693) (926,693)
II. Weighted Equivalent Shares:
Options and warrants assumed exercised 47,477 47,803
---------- ---------- ---------- ----------
III. Weighted Average Shares and Equivalent Shares 2,735,167 2,782,644 3,790,100 3,837,903
========== ========== ========== ==========
IV. Net Income $ 8,266 $ 8,266 $ 14,056 $ 14,056
========== ========== ========== ==========
V. Net Income Per Share (Diluted) $ 3.02 $ 2.97 $ 3.71 $ 3.66
========== ========== ========== ==========
</TABLE>
<PAGE>
Exhibit 21
CASTLE ENERGY CORPORATION
Listing of Parent and Subsidiaries
As of November 22, 1999
<TABLE>
<CAPTION>
Relationship Company's
to Ownership
Entity Company Business Percentage
- -------------------------------------- ------------ ---------------------------------- ----------
<S> <C> <C> <C>
Parent
Castle Energy Corporation Parent Holding Company N/A
Refining
Indian Oil Company Subsidiary Inactive 100%
Indian Refining I. L.P. Subsidiary- Inactive 100%
Limited
Partnership
Indian Refining & Marketing I. Inc. Subsidiary General Partner of IRLP - Inactive 100%
Natural Gas Marketing
Castle Pipeline Company Subsidiary General Partner - Pipeline 100%
Partnership - Inactive
Castle Texas Pipeline L.P. Subsidiary Natural Gas Transmission - Inactive 100%
Limited
Partnership
CEC Marketing Company Subsidiary General Partner - Gas Marketing 100%
Partnership - Inactive
CEC Marketing Resources Company Subsidiary Limited Partner - Gas Marketing 100%
Partnership - Inactive
CEC Gas Marketing L.P. Subsidiary- Gas Marketing - Inactive 100%
Limited
Partnership
Exploration and Production
Castle Production Company Subsidiary General Partner - Production 100%
Partnership - Inactive
Castle Production Resources Company Subsidiary Limited Partner - Production 100%
Partnership - Inactive
Castle Texas Production L.P. Subsidiary- Oil and Gas Production - Inactive 100%
Limited
Partnership
Castle Exploration Company, Inc. Subsidiary Oil and gas development, drilling 100%
and well operations - United States
Redeco Petroleum Company Limited Subsidiary Oil and gas development, drilling 100%
and well operations - Romania
Passive Investment
CEC, Inc. Subsidiary Passive Activities 100%
</TABLE>
<PAGE>
Exhibit 23.2
RALPH E. DAVIS ASSOCIATES, INC.
CONSULTANTS - PETROLEUM AND NATURAL GAS
3555 TIMMONS LANE, SUITE 1105
HOUSTON, TEXAS 77027
(713) 626-8955
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the use of our name and the reference to our
reports dated October 22, 1999 in the Form 10-K of Castle Energy Corporation for
the year ended September 30, 1999.
RALPH E. DAVIS ASSOCIATES, INC.
/s/ALLEN C. BARRON
-------------------------------
Allen C. Barron, P.E.
Vice President
Houston, Texas
December 3, 1999
<PAGE>
Exhibit 23.3
HUNTLEY & HUNTLEY, INC.
GEOLOGISTS AND ENGINEERS
L.G. HUNTLEY 1912-1970 ESTABLISHED 1912 340 MANSFIELD AVENUE
J.R. WYLIE, JR. 1927-1974 PITTSBURGH, PA 15220
R.S. STEWART 1948-1988 ----
T. BARTHOLOMEW, II AREA CODE 412
1988-1994 920-0800
Fax Number
(412)380-4003
Mr. Richard E. Staedtler
Chief Financial Officer
Castle Energy Corporation
One Radnor Corporate Center, Suite 250
Radnor, PA 19087
Dear Mr. Staedtler:
We hereby consent to the use of our name and reference to our report
dated October 21, 1998 in the Form 10-K of Castle Energy Corporation for the
year ended September 30, 1998.
Sincerely,
By:/s/KEITH N. MANGINI
-----------------------------
President
December 3, 1999
<PAGE>
Exhibit 23.4
INDEPENDENT AUDITORS' CONSENT
The Board of Directors
Castle Energy Corporation:
We consent to incorporation by reference in the registration statement (No.
33-88760) on Form S-8 of Castle Energy Corporation of our report dated December
14, 1999, relating to the consolidated balance sheets of Castle Energy
Corporation and subsidiaries as of September 30, 1999 and 1998, and the related
consolidated statements of operations, stockholders' equity and other
comprehensive income, and cash flows for each of the years in the three year
period ended September 30, 1999, which report appears in the September 30, 1999,
annual report on Form 10- K of Castle Energy Corporation.
KPMG LLP
Houston, Texas
December 21, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial data extracted from the Company's
consolidated financial statements for the fiscal year ended September 30, 1999
included in Item 8 Financial Statements and financial statement schedules and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> SEP-30-1999
<PERIOD-END> SEP-30-1999
<CASH> 22,252,000
<SECURITIES> 3,761,000
<RECEIVABLES> 5,172,000
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 33,349,000
<PP&E> 37,315,000
<DEPRECIATION> 10,330,000
<TOTAL-ASSETS> 60,363,000
<CURRENT-LIABILITIES> 7,285,000
<BONDS> 0
0
0
<COMMON> 3,414,000
<OTHER-SE> 49,664,000
<TOTAL-LIABILITY-AND-EQUITY> 60,363,000
<SALES> 57,257,000
<TOTAL-REVENUES> 57,257,000
<CGS> 31,052,000
<TOTAL-COSTS> 48,088,000
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 11,222,000
<INCOME-TAX> 2,956,000
<INCOME-CONTINUING> 8,266,000
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 8,266,000
<EPS-BASIC> 3.02
<EPS-DILUTED> 2.97
</TABLE>
