<PAGE>
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, 2000
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
(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
(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--
$.50 par value and related Rights
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X].
As of November 24, 2000, there were 6,672,884 shares of the registrant's
Common Stock ($.50 par value) outstanding. The aggregate market value of voting
stock held by non-affiliates of the registrant as of such date was $35,667,765
(5,095,395 shares at $7.00 per share).
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the 2001 Annual Meeting of
Stockholders are incorporated by reference in Items 10, 11, 12 and 13
<PAGE>
CASTLE ENERGY CORPORATION
1999 FORM 10-K
TABLE OF CONTENTS
Item Page
PART I
1. and 2. Business and Properties........................................... 1
3. Legal Proceedings................................................. 6
4. Submission of Matters to a Vote of Security Holders............... 9
PART II
5. Market for the Registrant's Common Equity and Related Stockholder
Matters........................................................... 10
6. Selected Financial Data........................................... 10
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations............................................. 12
8. Financial Statements and Supplementary Data....................... 26
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.............................................. 58
PART III
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
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.. 60
<PAGE>
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.
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 two 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 Union Pacific
Resources Corporation ("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. The Company is currently operating
exclusively in the exploration and production segment of the energy industry.
From inception to the present, the Company continues to operate in the
exploration and production business. During the fiscal years ended September 30,
2000 and 1999, the Company invested $11,226,000 and $23,964,000 respectively, in
oil and gas property acquisition, exploration and development, including
$2,279,000 in Romania. The Company is currently participating in the drilling of
a third wildcat well in Romania and expects to drill two more wildcat wells in
Romania in the next year. As of September 30, 2000, the Company's exploration
and production subsidiaries owned interests in 584 producing oil and gas wells
located in fourteen states. Of these interests, 507 were working interests,
where the Company is responsible for operating costs applicable to the well and
77 were royalty interests where the Company bears no expense burden. The
subsidiaries operate approximately half of the wells that are working interests.
At September 30, 2000, the Company's exploration and production assets included
proved reserves of approximately 44 billion cubic feet of natural gas and
approximately 4,700,000 barrels of oil.
In July 2000, the Company engaged Energy Spectrum Advisors of Dallas,
Texas to advise the Company concerning strategic alternative including the
possible sale of its oil and gas assets. In December 2000, several companies
submitted bids for the Company's domestic oil and gas assets. The total of the
highest bids for all of the Company's properties aggregated approximately
$48,000,000 with an effective date of October 1, 2000. The Company's Board of
Directors decided not to sell its oil and gas assets at the prices offered. At
the present time, the Company is again seeking acquisitions in the energy
sector, including oil and gas properties, gas marketing and pipeline operations
and other investments.
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In August 2000, the Company purchased thirty-five percent (35%) of the
stock of Networked Energy LLC ("Network") for $500,000. Network is a private
company engaged in the planning and operation of energy facilities that supply
power, heating and cooling services directly to retail customers.
In October 1996, the Company commenced a program to repurchase shares of
its common stock at stock prices beneficial to the Company. At November 24,
2000, 4,831,020 shares representing approximately 69% of previously outstanding
shares had been repurchased and the Company's Board of Directors has authorized
the purchase of up to 436,946 additional shares.
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"), Castle
Texas Oil and Gas Limited Partnership ("CTOGLP"), Castle Texas Exploration
Limited Partnership ("CTELP") and Petroleum Reserve Corporation ("PRC"), a
division of the Company. From December 3, 1992 to May 30, 1997 Castle Texas
Production Limited Partnership ("CTPLP"), 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, CPTLP sold these wells and related
undrilled acreage to 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.
In November and December of 1999, CECI acquired additional outside
interests in several Alabama and Pennsylvania wells, which it operates, for
$2,579,000.
In April 1999, the Company purchased an option to acquire a fifty
percent (50%) interest in three oil and gas concessions granted to a subsidiary
of Costilla Energy Corporation ("Costilla"), by the Romanian government. The
Company paid Costilla $65,000 for the option. In May 1999, the Company exercised
the option. As of September 30, 2000, the Company had participated in the
drilling of two wildcat wells and was in the process of drilling a third wildcat
well in Romania. Neither of the first two wells has been completed as a producer
although the Company intends to further test the second well and may decide to
complete such well if economic reserves are indicated. As of September 30, 2000,
the Company's gross investment in Romania was $2,279,000 but the Company has
provided an impairment reserve of $832,000 because one of the non-producing
wells drilled was in a concession where the Company does not plan to drill any
more wells. The Company expects that its minimum future obligation for the
Romanian concessions will be at least $1,300,000.
In fiscal 1999, the Company entered into two drilling ventures to
participate in the drilling of up to sixteen exploratory wells in south Texas.
During fiscal 2000, the Company participated in the drilling of nine exploratory
wells pursuant to the related joint venture operating agreements. Eight wells
drilled resulted in dry holes and one well was completed as a producer. The
Company has no further drilling obligations under these joint ventures. The
total cost incurred to participate in the drilling of these nine exploratory
wells was approximately $5,299,000.
In December 1999, a wholly-owned subsidiary of the Company purchased
majority interests in twenty-six offshore Louisiana wells from Whiting Petroleum
Company ("Whiting"), a public company engaged in oil and gas exploration and
development. The adjusted purchase price was $881,600.
In September 2000, the subsidiary sold its interests in the offshore
Louisiana wells to Delta Petroleum Company ("Delta"), a public company engaged
in oil and gas exploration and production. The preliminary purchase price
consisted of $1,147,000 cash plus 382,289 shares of Delta's common stock. The
Company does not anticipate any material adjustment to the preliminary purchase
price.
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Properties
Proved Oil and Gas Reserves
The following is a summary of the Company's oil and gas reserves as of
September 30, 2000. 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, 2000
were as follows:
Net MCF (1) of gas:
Proved developed.......................................... 35,815,000
Proved undeveloped........................................ 8,488,000
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Total..................................................... 44,303,000
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Net barrels of oil:
Proved developed.......................................... 2,963,000
Proved undeveloped........................................ 1,772,000
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Total..................................................... 4,735,000
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(1) Thousand cubic feet
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, 2000, including production from acquired properties since the date
of acquisition.
Fiscal Year Ended September 30,
---------------------------------------------
2000 1999 1998
---- ---- ----
Oil -- Bbls (barrels)............ 279,000 124,000 20,000
Gas -- MCF....................... 3,547,000 1,971,000 869,000
Average Sales Price and Production Cost Per Unit
The following table sets forth the average sales price per barrel of oil
and MCF of gas produced by the Company, including hedging adjustments, 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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2000 1999 1998
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<S> <C> <C> <C>
Average Sales Price per Barrel of Oil................ $27.94 $18.36 $15.46
Average Sales Price per MCF of Gas................... $ 2.87 $ 2.25 $ 2.38
Average Production Cost per Equivalent MCF(1)........ $ 1.19 $ .70 $ 0.55
</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.
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The average sales price per barrel of crude oil decreased $4.64 per
barrel for the year ending September 30, 2000 and 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 each of
the years ended September 30, 2000 and 1999 as a result of hedging. Oil and gas
sales were not hedged in fiscal 1998 nor were they hedged after July 2000.
Average production cost per equivalent mcf has been recalculated to
include income from well operations as an offset to oil and gas production
expense.
Productive Wells and Acreage
The following table presents the oil and gas properties in which the
Company held an interest as of September 30, 2000. 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, Texas and Wyoming.
As of
September 30, 2000
--------------------------
Gross(2) Net (3)
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Productive Wells:(1)
Gas Wells.......................................... 487 181
Oil Wells.......................................... 97 45
Acreage:
Developed Acreage.................................. 123,371 26,698
Undeveloped Acreage................................ 85,686 30,728
In addition, one of the Company's subsidiaries has a fifty percent
interest in approximately 3,100,000 gross undeveloped acres in Romania
(approximately 1,550,000 net acres).
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(1) A "productive well" is a producing well or a well capable of
production. Fifty-nine 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.
(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, 2000 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.
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<TABLE>
<CAPTION>
Fiscal Year Ended September 30,
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2000
----------------------------------------
United States Romania 1999 1998
------------------- ------------------ ----------------- ------------------
Productive Dry Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- --- ---------- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Developmental:
Gross......................... 9 -- -- 5 3 23.0 --
Net........................... 4.5 -- -- 2.3 1.2 15.2 --
Exploratory:
Gross......................... 1 8 -- 2* -- -- -- --
Net........................... .5 3.75 -- 1* -- -- -- --
</TABLE>
All wells drilled by the Company in fiscal 1999 and fiscal 1998 were
drilled in the United States.
* One well, in which the Company has a fifty percent (50%) interest,
has been temporarily classified as dry but the Company intends to
test other producing zones and may complete and produce such well if
further testing warrants completion.
A subsidiary of the Company is currently participating in a wildcat
drilling program in Romania, where it owns a fifty percent (50%) interest in
three drilling concessions granted by the Romanian government. The subsidiary is
currently participating in the drilling of a third wildcat well in Romania and
expects to participate in two more wildcat wells thereafter.
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.
From January 1, 2000 to September 30, 2000, the Company operated nine
wells in offshore Louisiana and, as a result, was subject to the environmental
regulations governing offshore wells. In September 2000, the Company sold its
interests in these wells to Delta and is thus no longer subject to the
regulations governing offshore operations, although one of the Company's
subsidiaries still has several letters of credit outstanding to the benefit of
prior owners of such properties and expects such letters of credit to remain
outstanding until June 2001.
<PAGE>
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 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 but does not cover gradual seepage and pollution .
Management believes that its current insurance coverage is adequate.
EMPLOYEES AND OFFICE FACILITIES
As of November 24, 2000, the Company, through its subsidiaries, employed
28 personnel. Until June 30, 1998, the Company outsourced all of its
administrative, land and accounting functions. Effective July 1, 1998, the
Company exercised
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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 established an Oklahoma City
office in February of 2000.
The Company leases certain offices as follows:
Office Location Function
--------------- --------
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, Legal and International Operations
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 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. ("Texaco"), 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 responded to the EPA information request in
January 2000.
On August 7, 2000, the Company received notice of a claim against it and
two of its inactive refining subsidiaries from Texaco and its parent. In its
claim, Texaco demanded that the Company and its former subsidiaries indemnify
Texaco for all liability resulting from environmental contamination at and
around the Indian Refinery. In addition, Texaco demanded that the Company assume
Texaco's defense in all matters relating to environmental contamination at and
around the Indian Refinery, including lawsuits, claims and administrative
actions initiated by the EPA as well as indemnify Texaco for costs that Texaco
has already incurred addressing environmental contamination at the Indian
Refinery. Finally, Texaco also claimed that the Company and its two inactive
subsidiaries are liable to Texaco under the Federal Comprehensive Environmental
Response Compensation and Liability Act as owners and operators of the Indian
Refinery.
The Company and its special counsel believe that Texaco's claims are
utterly without merit and the Company intends to vigorously defend itself
against Texaco's claims and any lawsuits that may follow.
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
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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 and received 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. 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.
In May 2000, the Company settled this lawsuit for $120,000.
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
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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.
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
apparently 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.
In April 2000, Larry Long withdrew as a named plaintiff and in September
2000, the Company and the remaining plaintiff agreed to settle the case for a
payment of $250,000 by the Company. The parties are currently finalizing the
settlement agreement, subject to court approval.
MGNG Litigation
On May 4, 1998, CTPLP filed a lawsuit against MGNG and MG Gathering
Company ("MGC"), two subsidiaries of MG, in the district court of Harris County,
Texas. CTPLP sought to recover gas measurement and transportation expenses
charged by the defendants in breach of a certain gas purchase contract. Improper
charges exceeded $750,000 before interest. In October of 1998, MGNG and MGC
filed a suit in Harris County, Texas. This suit sought indemnification from two
of the Company's subsidiaries in the event CTPLP won its lawsuit against MGNG
and MGC. The MG entities 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 parties participated in mediation but were not able to resolve the
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 CTPLP by MGNG for
improper gas measurement and transportation deductions. The Castle entities
answered this suit denying MGNG claims based partially on the legal right of
offset.
In September 2000, the parties agreed to settle the cases. Under the
terms of the proposed settlement the amount claimed by MGNG under a gas supply
contract was reduced by $325,000, CTPLP agreed to pay MGNG the reduced amount of
$447,000, and the parties agreed to sign mutual releases. The parties are
currently in the process of finalizing the settlement agreements.
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 negotiations, the Company believes that
revenue attributable to the ORRI should be released to CECI in the near future.
As of September 30, 2000, approximately $250,000 attributable to CECI's share of
the ORRI revenue was suspended.
-8-
<PAGE>
Long Trusts Litigation
In November 2000, the Company and three of its subsidiaries were
defendants in a jury trial in Rusk County, Texas. The plaintiffs in the case,
the Long Trusts, are non-operating working interest owners in wells previously
operated by CTPLP. The wells were among those sold to UPRC in May 1997. The Long
Trusts claimed that CTPLP did not allow them to sell their share of gas
production from March 1, 1996 to January 31, 1997 as required by applicable
joint operating agreements, and they sued CTPLP and the other defendants,
claiming (among other things) breach of contract, breach of fiduciary duty,
conversion and conspiracy. The plaintiffs sought actual damages, exemplary
damages, pre-judgment and post-judgment interest, attorney's fees and court
costs. CTPLP counterclaimed for approximately $150,000 of unpaid joint interests
billings, attorneys' fees and court costs.
After a three-week trial, the District Court submitted 36 questions to
the jury which covered all of the claims and counterclaims in the lawsuit. The
jury's answers supported the plaintiffs' claims against the Company and its
subsidiaries, CTPLP's counterclaim against the plaintiffs and two of the
affirmative defenses asserted by the defendants. The Company and its
subsidiaries are preparing motions to have the District Court disregard certain
jury findings and to render judgment on other findings. Plaintiffs are
presumably similarly engaged. Because certain of the plaintiffs' theories are
mutually exclusive and because certain jury findings are duplicative, it is
difficult to determine the amount of any judgment that the plaintiffs will seek
to have entered. The plaintiffs may seek to have the Court award them as much as
$2,900,000 plus interest on certain items. The defendants will seek to have the
Court award them approximately $700,000 plus interest on certain items.
Special counsel to the Company does not consider an unfavorable outcome
to this lawsuit probable. The Company's management and legal counsel believe
that several of the plaintiffs' primary legal theories are contrary to
established Texas law and that the Court's charge to the jury was fatally
defective. They further believe that any judgment for plaintiffs based on those
theories or on the jury's answers to certain questions in the charge cannot
stand and will be reversed on appeal. Nevertheless, the Company and its
subsidiaries may be required to post a bond to cover the total amount of damages
awarded to the plaintiffs in any judgment and to maintain that bond until the
resolution of any appeals (which may take several years).
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 2000.
-9-
<PAGE>
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:
On December 29, 1999, the Company's Board of Directors declared a stock
split in the form of a 200% stock dividend applicable to all stockholders of
record on January 12, 2000. The additional shares were paid on January 31, 2000
and the Company's shares first traded at post split prices on February 1, 2000.
The stock split applied only to the Company's outstanding shares on January 12,
2000 (2,337,629 shares) and did not apply to treasury shares (4,491,017 shares)
on that date. As a result of the stock split 4,675,258 additional shares were
issued. All share changes have been recorded retroactively in these data and
elsewhere in this Form 10-K.
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, 2000.
2000 1999
------------------- -----------------
High Low High Low
------ ------- ----- -----
First Quarter (December 31)............ $ 9.67 $ 5.50 $6.46 $5.63
Second Quarter (March 31).............. $10.56 $ 4.81 $5.96 $5.25
Third Quarter (June 30)................ $ 6.50 $ 4.63 $6.42 $5.00
Fourth Quarter (September 30).......... $ 7.75 $ 6.25 $6.08 $5.50
The final sale of the Company's Common Stock as reported by the NNM on
November 24, 2000 was at $7.00.
Dividends:
On June 30, 1997, the Company's Board of Directors adopted a policy of
paying regular quarterly cash dividends of $.05 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 24, 2000, 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, 2000, the Company
consummated a number of transactions affecting the comparability of the
financial information set forth below. 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, 2000. The information should be read in conjunction with the
consolidated financial statements and notes thereto included in Items 8 of this
Form 10-K.
-10-
<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)
2000 1999 1998 1997 1996
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Revenues:
Natural gas marketing and transmission........... $50,067 $70,001 $64,606 $59,471
Exploration and production....................... $17,959 7,190 2,603 7,113 9,224
Gross Margin:
Natural gas marketing and transmission........... 19,005 26,747 24,640 25,238
Exploration and production....................... 11,765 4,802 1,828 5,173 7,179
Earnings before interest, taxes, depreciation, and
amortization and impairment of unproven
properties.......................................
Natural gas marketing and transmission........... 17,847 25,162 23,054 23,162
Exploration and production....................... 9,727 3,764 836 4,036 5,944
Corporate general and administrative expenses........ (3,717) (4,112) (3,081) (3,370) (3,499)
Depreciation, depletion and amortization and
impairment of unproven properties................ (4,041) (8,330) (9,885) (12,250) (13,717)
Interest expense..................................... (2) (1,038) (1,959)
Interest income and other income..................... 809 2,053 2,230 21,097(1) 3,884
------- ------- ------- ------- -------
Income from continuing operations before income
taxes............................................ 2,778 11,222 15,260 31,529 13,815
Provision for (benefit of) income taxes related to
continuing operations............................ (2,291) 2,956 1,204 4,663 (11,259)
------- ------- ------- ------- -------
Net income........................................... $ 5,069 $ 8,266 $14,056 $26,866 $25,074
======= ======= ======= ======= =======
Dividends............................................ $ 1,363 $ 2,048 $ 1,688 $ 1,446
======= ======= ======= =======
Net income per share (diluted)....................... $ .71 $ .99 $ 1.22 $ 1.55 $ 1.24
======= ======= ======= ======= =======
Dividends per share.................................. $ .20 $ .25 $ .15 $ .10
======= ======= ======= =======
</TABLE>
<TABLE>
<CAPTION>
September 30,
----------------------------------------------------------------------
2000 1999 1998 1997 1996
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Balance Sheet Data:
Working capital (deficit)......................... $22,304 $26,489 $40,271 $46,384 ($4,452)
Property, plant and equipment, net, including oil
and gas properties............................. 30,978 26,985 4,969 2,998 36,223
Total assets...................................... 63,295 60,796 67,004 82,717 101,230
Long-term debt, including current maturities...... 14,006
Stockholders' equity.............................. 54,276 53,503 51,553 67,765 66,711
</TABLE>
Share data have been retroactively restated to reflect the 200% stock
dividend which was effective January 31, 2000.
------------
(1) Includes a $19,667 non-recurring gain on sale of assets.
-11-
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
("$000's" Omitted Except Per Unit 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.
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, 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 marketing 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 although it continues to seek similar gas marketing acquisitions. As a
result, natural gas marketing operations impacted consolidated operations for
all of fiscal 1998, the first eight months of fiscal 1999 and none of fiscal
2000.
Fiscal 2000 vs Fiscal 1999
OIL AND GAS SALES
Oil and gas sales increased $11,247 or 67.6% from fiscal 1999 to fiscal
2000. An analysis of the increase is as follows:
Year Ended September 30,
--------------------------------------
2000 1999 Increase
--------- --------- ---------
Production (Net):
Barrel of crude oil........... 279,000 124,000 155,000
Mcf of natural gas............ 3,547,000 1,971,000 1,576,000
Equivalent net of natural gas. 5,221,000 2,715,000 2,506,000
Oil and Gas Sales:
Before hedging................ $19,487 $ 6,862 $12,625
Effect of hedging............. (1,528) (150) (1,378)
--------- --------- ---------
Net of hedging................ $ 17,959 $ 6,712 $11,247
========= ========= =========
Average Price/MCFE:
Before hedging..................... $ 3.73 $ 2.53 $ 1.20
Effect of hedging.................. (0.29) (0.06) (0.23)
--------- --------- ---------
Net................................ $ 3.44 $ 2.47 $ .97
========= ========= =========
-12-
<PAGE>
Year Ended September 30,
------------------------------------
2000 1999 Increase
----- ------- --------
Analysis of Increase Before Hedging:
Price (2,715,000 mcfe x $1.20/mcfe).... $ 3,258
Volume (2,506,000 mcfe x $3.73/mcfe)... 9,347
Rounding............................... 20
-------
$12,625
=======
Analysis of Increase After Hedging:
Price (2,715,000 mcfe x $.97/mcfe)..... $ 2,634
Volume (2,506,000 mcfe x $3.44/mcfe)... 8,621
Rounding............................... (8)
-------
$11,247
=======
The increase in production volumes is primarily attributable to the
acquisition of the AmBrit properties on June 1, 1999. As a result of this
acquisition, the production volumes attributable to the AmBrit properties
contributed twelve months of oil and gas sales for the year ended September 30,
2000 versus only four months of oil and gas sales for the year ended September
30, 1999.
For the year ended September 30, 2000, net production averaged 764
barrels of crude oil a day and 9,718 mcf of natural gas per day. A year ago the
Company had anticipated that such volumes would attain approximately 1,000
barrels of crude oil and approximately 13,000 mcf of natural gas per day. The
Company has not attained 1,000 net barrels a day of crude oil or 13,000 net mcf
of natural gas per day because it drilled eight dry holes out of nine
exploratory wells drilled in two exploratory drilling ventures in the United
States and because both of its wildcat wells drilled in Romania also resulted in
unproductive wells although the Company expects to further test one well.
At the present time, natural gas spot prices are averaging in excess of
$9.00/mcf - record prices. Since approximately sixty-eight percent (68%) of the
Company's production, based upon energy content, is derived from natural gas and
since the Company has not hedged any of its natural gas production, the Company
expects that its gas sales will increase significantly if such high prices
continue and the Company does not decide to hedge any of its anticipated
production.
Oil and Gas Production Expenses
Oil and gas production expenses increased $4,284 or 224% from fiscal
1999 to fiscal 2000. The increase is primarily attributable to the acquisition
of the AmBrit properties in June 1999. For the year ended September 30, 2000 oil
and gas production expenses, net of income from well operations, were $1.19 per
equivalent mcf sold versus only $.70 per equivalent mcf sold for the year ended
September 30, 1999. The increase results primarily from two factors. The Company
is not the operator for most of the wells it acquired from AmBrit and, as a
result, must pay the operator of such wells monthly administrative reimbursement
fees pursuant to the terms of the governing joint operating agreements. Some of
these fees are substantial and the aggregate amount of such fees is much greater
than that payable on the Company's non-AmBrit properties. A second factor
contributing to the increase is the fact that the average age of the Company's
producing properties is increasing - especially given the unsuccessful results
of the Company's exploratory drilling programs. Mature wells typically carry a
higher production expense burden than do newer wells that have not yet been
significantly depleted.
GENERAL AND ADMINISTRATIVE COSTS
General and administrative costs increased $1,000 or 96.3% from fiscal
1999 to fiscal 2000. The increase is primarily attributable to the Company's
establishment of an Oklahoma City office in February 2000, increased legal,
consulting and reservoir engineering fees and increased employee costs. Also,
see "Corporate General and Administrative Expenses" below.
-13-
<PAGE>
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization increased $1,163 on 56.8% from
fiscal 1999 to fiscal 2000. The components of depreciation, depletion and
amortization were as follows:
<TABLE>
<CAPTION>
Year Ended September 30,
------------------------------------
2000 1999 Increase
------ ------ --------
<S> <C> <C> <C>
Depreciation and amortization of furniture and fixtures and equipment....... $ 219 $ 109 $ 110
Depreciation, depletion and amortization of oil and gas properties.......... 2,990 1,937 1,053
------ ------ ------
$3,209 $2,046 $1,163
====== ====== ======
</TABLE>
Depreciation and amortization of furniture and fixtures and equipment
increased $110 from fiscal 1999 to fiscal 2000 primarily because of depreciation
related to new vehicles purchased in late fiscal 1999 and early fiscal 2000 and
because of amortization of computer software commencing in the first quarter of
fiscal 2000.
For the year ended September 30, 2000, the depletion rate per equivalent
mcf was $.57 in fiscal 2000 versus $.71 in fiscal 1999. The net decrease is the
result of offsetting factors. The depletion rate indirectly decreased because of
substantially higher energy prices at September 30, 2000 versus those at
September 30, 1999. As a result of such higher prices, the Company's net
economic oil and gas reserves increased substantially from 1999 to 2000 and
related depreciation, depletion and amortization decreased substantially because
more equivalent mcfs of gas were allocated to essentially the same depletable
costs. This decrease was offset by the Company's expenditure of approximately
$7,600 in the acquisition of drilling acreage and drilling of eight dry holes in
the United States and two unproductive wells in Romania. These expenditures
increased the depletion rate because the related costs of these drilling
ventures were added to the Company's amortization base without a concomitant
increase in oil and gas reserves to be depleted.
IMPAIRMENT OF UNPROVED PROPERTIES
The Company recorded an impairment reserve for unproved property in
fiscal 2000 because the Company drilled an unproductive well on one of its three
Romanian concessions and does not plan to drill any additional wells on that
concession hence it provided a reserve for the costs allocated to that
concession.
CORPORATE GENERAL AND ADMINISTRATIVE EXPENSES
Corporate, general and administrative expenses decreased $395 or 9.6%
from fiscal 1999 to fiscal 2000. The decrease is primarily attributable to
decreased insurance and legal costs. The $395 decrease in corporate, general and
administrative expenses was, however, offset by an increase of $1,000 in
exploration and production general and administrative expenses. (See above.) A
significant portion of the general and administrative expenses allocated to
corporate overhead in fiscal 1999 have been allocated to exploration and
production general and administrative costs in fiscal 2000 and are expected to
be so allocated in the future.
OTHER INCOME (EXPENSE)
Interest income decreased $917 or 53.9% from fiscal 1999 to fiscal 2000.
The decrease is primarily attributable to a decrease in the average balance of
cash outstanding during the periods being compared.
-14-
<PAGE>
The composition of other income (expense) for the years ended September
30, 2000 and 1999 is as follows:
<TABLE>
<CAPTION>
Year Ended September 30,
------------------------
2000 1999
---- ----
<S> <C> <C>
Litigation recovery (costs)......................................................... ($45) $355
Write-down of investment in Penn Octane Corporation preferred stock................. (423)
Market price adjustment of investment in Penn Octane Corporation common
stock......................................................................... 431
Miscellaneous....................................................................... 70 (11)
---- ------
$25 $352
=== ====
</TABLE>
PROVISION FOR INCOME TAXES
The tax provision (benefit) for the years ended September 30, 2000 and
1999 consist of the following components:
<TABLE>
<CAPTION>
Year Ended September 30,
--------------------------
2000 1999
------- ------
<S> <C> <C> <C>
1. Increase in net deferred tax asset using 36% Federal and state blended tax
rate..................................................................... ($2,256)
2. Utilization of deferred tax asset, net of related valuation reserves, using
36% blended Federal and state tax rate................................... $2,765
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)........................ (35) 120
------- ------
($2,291) $2,956
====== ======
</TABLE>
The tax provision for the year ended September 30, 2000, consists
primarily of deferred taxes of $948 related to timing differences originating in
fiscal 2000 and the reversal of a $3,204 valuation reserve from fiscal 1999. The
reversal of the valuation reserve resulted because of positive evidence that the
Company will be able to generate sufficient taxable income in the future to
utilize its deferred tax asset. Such positive evidence consists primarily of the
increased value of the Company's oil and gas reserves as a result of
substantially higher oil and gas prices.
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 4,831,020 or 69% of its
common shares. As a result of these share acquisitions, earnings per share are
significantly higher than they would be if no shares had been repurchased.
-15-
<PAGE>
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
======= =======
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.
-16-
<PAGE>
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.
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 for the year ended September 30, 1999). 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 AmBrot 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
Expenses
Oil and gas.................... (1,910) (1,312) (598) (545) (53)
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.
-17-
<PAGE>
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 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 future 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.
Expenses
Oil and Gas Production
Oil and gas production expenses increased $53 or 9.7% 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. This increase
was offset by increased income from well operations.
In fiscal 1999, oil and gas production expense comprised 21.6% of oil
and gas sales versus 23% of oil and gas sales in fiscal 1998. 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.
-18-
<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.
-19-
<PAGE>
PROVISION FOR INCOME TAXES
The tax provision 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.
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.
During the year ended September 30, 2000, the Company generated $6,701
from operating activities. During the same period the Company invested $11,226
in oil and gas properties and $5,208 to reacquire shares of its common stock. In
addition, it paid $1,363 in stockholder dividends. At September 30, 2000, the
Company had $11,525 of unrestricted cash, $22,304 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
-20-
<PAGE>
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 consolidated financial statements
included in Item 8 of this Form 10-K).
Expected Sources and Uses of Funds
As of September 30, 2000, the estimated future cash expenditures of the
Company for the next two fiscal years consisted of the following:
a. Investments in Oil and Gas Properties
1. Development drilling on existing acreage.......... $ 9,915
2. Romanian concession - three wildcat wells......... 1,300
3. Dividends......................................... 2,669
-------
$13,884
=======
If subsequent wildcat Romanian wells are successful, the Company
may increase its investment in that country significantly and could
conceivably spend $10,000-$15,000 if new oil or gas fields are
discovered.
In July 2000, the Company engaged Energy Spectrum Advisors of
Dallas, Texas to advise the Company concerning strategic
alternatives, including the possible sale of its domestic oil and
gas assets. In December 2000, several companies submitted bids for
the Company's oil and gas assets. The total of the highest bids for
all of the Company's properties aggregated approximately $48,000
with an effective date of October 1, 2000. The Company's Board of
Directors decided not to sell its oil and gas assets at the prices
offered. As a result, the Company is again seeking acquisitions in
the energy sector, including oil and gas properties, gas marketing
and pipeline operations and other investments. Given current high
oil and gas prices and resultant seller price expectations, there
can be no assurance that the Company will be able to acquire energy
sector assets at prices it considers favorable. If the Company is
able to acquire energy sector assets at favorable prices, its
expenditures will exceed the estimated future expenditures listed
above.
b. Repurchase of Company Shares - as of November 24, 2000, the
Company had repurchased 4,831,020 shares of its common stock
(13,813,054 shares without taking into account the 200% stock
dividend which was effective January 31, 2000) at a cost of
$66,234. The Company's Board of Directors has authorized the
repurchase of up to 436,946 additional shares to provide an exit
vehicle for investors who want to liquidate their investment in the
Company. The decisions whether to repurchase such additional shares
and/or to increase the repurchase authorization above the current
level 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 $.20 per share annual dividend ($.05 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.
d. Required Escrow Fund - Litigation - the Company may have to escrow
as much as $2,900 for a lengthy period - perhaps several years - as
it appeals a jury verdict in the Long Trusts' litigation. (See Note
21 to the consolidated financial statements included in Item 8 to
this Form 10-K.)
At September 30, 2000, the Company had available the following sources
of funds:
Unrestricted cash - September 30, 2000....................... $11,525
Line of credit - energy bank................................. 30,000
Marketable securities........................................ 10,985
-------
$52,510
=======
The Company's line of credit expires in February 2001 but the Company is
currently in the process of extending its line of credit.
In addition, the Company anticipates significant future cash flow from
exploration and production operations.
-21-
<PAGE>
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
the common stock of Penn Octane and Delta are dependent on the market value of
such stock and the Company's ability to liquidate its Penn Octane and Delta
stock investments at or near market values. Since Penn Octane and Delta are
thinly capitalized and traded, liquidation of a large volume of Penn Octane
and/or Delta stock without significantly lowering the market price may be
impossible. (See Note 21 to the consolidated financial statements included in
Item 8 to this Form 10-K.)
The Company thus expects that it can fund all of its present drilling
commitments from its own unrestricted cash and expected cash flow from operating
activities. The Company can also use its $30,000 line of credit (until February
2001) and future cash flow from production to acquire additional oil and gas
properties and/or to conduct additional drilling.
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.
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, 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 responded to the EPA in January 2000
and has received no further correspondence for the EPA. On August 7,
2000, the Company received notice of a claim against it and two of
its inactive refining subsidiaries from Texaco and its parent. In
its claim, Texaco demanded that the Company and its former
subsidiaries indemnify Texaco for all liability resulting from
environmental contamination at and around the Indian Refinery. In
addition, Texaco demanded that the Company assume Texaco's defense
in all matters relating to environmental contamination at and around
the Indian Refinery, including lawsuits, claims and administrative
actions initiated by the EPA as well as indemnify Texaco for costs
that Texaco has already incurred addressing environmental
contamination at the Indian Refinery. Finally, Texaco also claimed
that the Company and its two inactive subsidiaries are liable to
Texaco under the Federal Comprehensive Environmental Response
Compensation and Liability Act as owners and operators of the Indian
Refinery.
The Company and its special counsel believe that Texaco's claims are
utterly without merit and the Company intends to vigorously defend
itself against Texaco's claims and any lawsuits that may follow.
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 contingent environmental liabilities or
legal defense costs related to the Indian Refinery. If the Company
is sued and related
-22-
<PAGE>
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. The Company has 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. To date it is the Company's
understanding that IRLP and the EPA have still not consummated an
agreement to settle the note for $800.
3. 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 4,831,020 or 69% 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.
4. Foreign Operating Risks
Since the Company anticipates spending a minimum of approximately
$3,600 drilling five wildcat wells on three Romanian concessions, of
which $2,279 was incurred by September 30, 2000, 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.
5. Exploration and Production Reserve Risk
The Company is currently participating in drilling a third wildcat
well in Romania and anticipates drilling at least two more wildcat
wells there. This drilling involves exploratory drilling where the
probability of discovering commercial oil and gas reserves is less
than twenty percent (20%). 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.
6. Exploration and Production Price Risk
The Company has not hedged any of its anticipated future oil and gas
production because the cost to do so appears excessive when compared
to the risk involved. As a result, the Company remains exposed to
future oil and gas price changes with respect to all of its
anticipated future oil and gas production. Such exposure could be
considerable given the volatility of oil and gas prices. For
example, from February 1999 to November 2000, crude oil prices
essentially increased 250% and natural gas prices also increased to
record levels. Current oil and gas prices are higher than they have
been in fifteen years. In the past crude oil prices and gas prices
have shown general volatility over short periods of time and the
high oil and gas prices currently being realized could decrease and
decrease significantly.
7. 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
drilling a third wildcat well in that country. The first two wells
drilled did not result in any commercial wells. The operating risks
associated with the Romanian drilling concession are
-23-
<PAGE>
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 such operating activities.
8. 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
appear to affect most corporations.
9. Future of the Company
The oil and gas industry is a dynamic and 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
hired an outside advisor to sell its oil and gas properties, the
prices offered by would-be buyers were significantly lower than the
Company's expectations and the Company's Board of Directors decided
not to sell the Company's properties at the price offered,
approximately $48,000. As noted previously, the Company has now
decided to seek energy sector acquisitions, including oil and gas
assets, for its own account given the low bids it received for its
own properties. There can, however, be no assurance that the Company
will be successful in this pursuit. The price expectations of
would-be sellers may be higher than the price the Company is willing
to pay and other larger companies with more capital resources may
outbid the Company. Also, as noted previously, the Company has
recently invested $500 in Network, a private company engaged in the
operation of energy facilities that supply power, heating and
cooling services directly to retail customers. If Network is
successful in its endeavors, the Company may make additional
investments in Network and/or similar energy related ventures.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company has not hedged its anticipated oil and gas production and
thus remains at risk with respect to the prices it receives for such production.
If oil and gas prices increase, the Company's oil and gas revenues will
increase. Conversely, if oil and gas prices decrease, the Company's oil and gas
revenues will also decrease. Gas prices are currently higher than they have been
in fifteen years and average oil prices are remaining at levels in excess of
what they have been for many years. There can be, however, no assurance that
such prices will remain at such levels given recent oil and gas price
volatility.
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.
NEW ACCOUNTING PRONOUNCEMENTS
Statement of Financial Accounting Standards No. 133, as amended,
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 such instrument
has been designated and qualifies as part of a hedging relationship and, if so,
depends 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
-24-
<PAGE>
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. The Company adopted FAS 133 effective October
1, 2000.
At October 1, 2000, the Company had not freestanding derivative
instruments in place and had no embedded derivative instruments. Based upon the
Company's application of SFAS 133, its adoption had no impact on its results of
operations or financial condition.
RISK FACTORS
See above.
-25-
<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, 2000, 1999 and 1998.......... 27
Consolidated Balance Sheets as of September 30, 2000 and 1999........................................ 28
Consolidated Statements of Cash Flows for the Years Ended September 30, 2000, 1999 and 1998.......... 29
Consolidated Statements of Stockholders' Equity and Other Comprehensive Income for the Years
Ended September 30, 2000, 1999 and 1998...................................................... 31
Notes to the Consolidated Financial Statements....................................................... 32
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.
-26-
<PAGE>
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
("$000's" Omitted Except Per Share Amounts)
<TABLE>
<CAPTION>
Year Ended September 30,
---------------------------------------------------
2000 1999 1998
---------- ---------- -----------
<S> <C> <C> <C>
Revenues:
Natural gas marketing and transmission:
Gas sales............................................. $ 50,067 $ 70,001
----------- -----------
Exploration and production:
Oil and gas sales..................................... $ 17,959 6,712 2,373
---------- ---------- -----------
17,959 56,779 72,374
---------- ---------- -----------
Expenses:
Natural gas marketing and transmission:
Gas purchases......................................... 31,062 43,254
Operating costs....................................... (16)
General and administrative............................ 35 62
Transportation........................................ 1,123 1,539
Depreciation and amortization......................... 6,284 9,462
---------- -----------
38,504 54,301
---------- -----------
Exploration and production:
Oil and gas production................................ 6,194 1,910 545
General and administrative............................ 2,038 1,038 992
Depreciation, depletion and amortization.............. 3,209 2,046 423
Impairment of foreign unproved properties............. 832
---------- ---------- -----------
12,273 4,994 1,960
---------- ---------- -----------
Corporate general and administrative.................... 3,717 4,112 3,081
---------- ---------- -----------
15,990 47,610 59,342
---------- ---------- -----------
Operating income............................................ 1,969 9,169 13,032
---------- ---------- -----------
Other income (expense):
Interest income......................................... 784 1,701 2,271
Other income (expense).................................. 25 352 (41)
Interest expense........................................ (2)
---------- ---------- -----------
809 2,053 2,228
---------- ---------- -----------
Income before provision for (benefit of) income taxes...... 2,778 11,222 15,260
---------- ---------- -----------
Provision for (benefit of) income taxes:
State................................................... (64) 79 40
Federal................................................. (2,227) 2,877 1,164
---------- ---------- -----------
(2,291) 2,956 1,204
---------- ---------- -----------
Net income.................................................. $ 5,069 $ 8,266 $ 14,056
========== ========== ===========
Net income per share:
Basic................................................... $ .73 $ 1.01 $ 1.24
========== ========== ===========
Diluted................................................. $ .71 $ .99 $ 1.22
========== ========== ===========
Weighted average number of common and potential dilutive
shares outstanding:
Basic 6,939,350 8,205,501 11,370,300
========== ========== ===========
Diluted............................................. 7,102,803 8,347,932 11,513,709
========== ========== ===========
</TABLE>
The accompanying notes are an integral part of these financial statements
-27-
<PAGE>
CASTLE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
("$000's" Omitted Except Per Share Amounts)
<TABLE>
<CAPTION>
September 30,
-------------------------
2000 1999
-------- --------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents......................................................... $ 11,525 $ 22,252
Restricted cash................................................................... 1,742 770
Accounts receivable............................................................... 3,758 5,172
Marketable securities............................................................. 10,985 4,194
Prepaid expenses and other current assets......................................... 251 594
Estimated realizable value of discontinued net refining assets.................... 800 800
Deferred income taxes............................................................. 2,256
-------- --------
Total current assets............................................................ 31,317 33,782
Property, plant and equipment, net:
Natural gas transmission.......................................................... 55 60
Furniture, fixtures and equipment................................................. 258 298
Oil and gas properties, net (full cost method)....................................
Proved properties............................................................... 29,218 24,765
Unproved properties not being amortized......................................... 1,447 1,862
Investment in Networked Energy LLC.................................................... 500
Note receivable - Penn Octane Corporation............................................. 500
Other assets.......................................................................... 29
-------- --------
Total assets.................................................................... $ 63,295 $ 60,796
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Dividend payable.................................................................. $ 333 $ 368
Accounts payable.................................................................. 2,433 2,869
Accrued expenses.................................................................. 265 802
Accrued taxes on appreciation of marketable securities............................ 2,628 49
Stock subscription payable........................................................ 150
Net refining liabilities retained................................................. 3,204 3,205
-------- --------
Total current liabilities....................................................... 9,013 7,293
Long-term liabilities................................................................. 6 -
-------- --------
Total liabilities............................................................... 9,019 7,293
-------- --------
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;
11,503,904 shares issued at September 30, 2000 and 1999......................... 5,752 5,752
Additional paid-in capital........................................................ 67,365 67,365
Accumulated other comprehensive income - unrealized gains on marketable
securities, net of taxes........................................................ 4,671 2,396
Retained earnings................................................................. 42,422 38,716
-------- --------
120,210 114,229
Treasury stock at cost - 4,791,020 shares at September 30, 2000 and 4,282,217
shares at September 30, 1999.................................................... (65,934) (60,726)
-------- --------
Total stockholders' equity...................................................... 54,276 53,503
-------- --------
Total liabilities and stockholders' equity...................................... $ 63,295 $ 60,796
======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements
-28-
<PAGE>
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
("$000's" Omitted Except Per Share Amounts)
<TABLE>
<CAPTION>
Year Ended September 30,
------------------------------------------
2000 1999 1998
------- ------- -------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income ............................................................... $ 5,069 $ 8,266 $14,056
------- -------- -------
Adjustments to reconcile net income to cash provided by operating
activities:
Depreciation, depletion and amortization............................... 3,209 8,330 9,885
Impairment of foreign unproved properties.............................. 832
Deferred income taxes (benefit)........................................ (2,256) 2,765 968
Unrealized gain on marketable securities............................... (481)
Impairment of Penn Octane preferred stock.............................. 423
Changes in assets and liabilities:
Decrease in restricted cash......................................... (972) (157) (116)
(Increase) in marketable securities................................. (471)
(Increase) decrease in accounts receivable.......................... 1,414 3,209 (2,513)
Decrease in notes receivable........................................ 10,000
Decrease in prepaid transportation.................................. 1,123 1,539
(Increase) decrease in prepaid expenses and other current assets.... 343 (301) 159
(Increase) decrease in other assets................................. 29 (29)
(Increase) decrease in prepaid gas purchases........................ 852 (852)
Increase (decrease) in accounts payable............................. (436) (5,740) 3,043
Increase (decrease) in accrued expenses............................. (537) (861) 406
Increase in other long-term liabilities............................. 6
------- -------- -------
Total adjustments............................................... 1,632 9,162 22,019
------- -------- -------
Net cash flow provided by operating activities.................. 6,701 17,428 36,075
------- -------- -------
Cash flows from investment activities:
Investment in note receivable - Penn Octane Corporation................... (500)
Investment in marketable securities....................................... (269) (1,000)
Proceeds from sale of oil and gas assets.................................. 1,427
Realization from (liquidation of) discontinued net refining assets........ 900 (1,425)
Acquisition of AmBrit oil and gas properties.............................. (20,170)
Investment in other oil and gas properties................................ (11,226) (3,794) (2,212)
Investment in pipelines................................................... (63)
Investment in Networked Energy LLC........................................ (350)
Purchase of furniture, fixtures and equipment............................. (173) (98) (182)
Other..................................................................... (35) 42
------- -------- -------
Net cash used in investing activities........................... (10,857) (23,431) (4,840)
------- -------- -------
</TABLE>
(continued on next page)
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 Per Share Amounts)
(continued from previous page)
<TABLE>
<CAPTION>
Year Ended September 30,
----------------------------------------
2000 1999 1998
------- ------- -------
<S> <C> <C> <C>
Cash flows from financing activities:
Acquisition of treasury stock ............................................... (5,208) (6,919) (28,644)
Dividends paid to shareholders .............................................. (1,363) (1,681) (2,393)
Proceeds from exercise of stock options ..................................... 255 64
------- ------- -------
Net cash (used in) financing activities................................ (6,571) (8,345) (30,973)
------- ------- -------
Net increase (decrease) in cash and cash equivalents............................ (10,727) (14,348) 262
Cash and cash equivalents - beginning of period................................. 22,252 36,600 36,338
------- ------- -------
Cash and cash equivalents - end of period....................................... $11,525 $22,252 $36,600
======= ======= =======
Supplemental disclosures of cash flow information are as follows:
Cash paid during the period:
Interest.................................................................. $ 2
======= ======= =======
Income taxes.............................................................. $ 188 $ 108 $ 128
======= ======= =======
Accrued dividends............................................................ $ 333 $ 368
======= =======
Conversion of Penn Octane Corporation note to marketable securities.......... $ 1,000
=======
Unrealized gain on investment in available-for-sale marketable securities.... $ 2,275 $ 2,396
======= =======
Exchange of oil/gas properties for Delta Petroleum Company common
stock..................................................................... $ 1,937
=======
</TABLE>
The accompanying notes are an integral part of these financial statements
-30-
<PAGE>
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
AND OTHER COMPREHENSIVE INCOME
("$000's" Omitted Except Per Share Amounts)
<TABLE>
<CAPTION>
Years Ended September 30, 2000, 1999 and 1998
-----------------------------------------------------------------------------
Accumulated
Common Stock Additional Other Retained
--------------------- Paid-In Comprehensive Comprehensive Earnings
Shares Amount Capital Income Income (Deficit)
---------- ------ ------- ------------- ------------- ---------
<S> <C> <C> <C> <C> <C> <C>
Balance - October 1, 1997...... 6,798,646 3,399 67,061 22,468
Stock acquired.................
Options exercised.............. 5,000 3 61
Dividends declared ($.45 per share) (1,688)
Net income..................... 14,056
---------- ------ ------- -------
Balance - September 30, 1998... 6,803,646 3,402 67,122 34,836
Stock acquired.................
Options exercised.............. 25,000 12 243
Dividends declared ($.25 per share) (2,048)
Comprehensive income...........
Net income................... $ 8,266 8,266
Other comprehensive income:
Unrealized gain on marketable
securities, net of tax.. 2,396 $2,396
--------
$ 10,662
---------- ------ ------- ======== ------ -------
Balance - September 30, 1999... 6,828,646 3,414 67,365 2,396 41,054
Stock split ratio activity applied 4,675,258 2,338 (2,338)
---------- ------ ------- ------ -------
Balance-September 30, 1999 - rest 11,503,904 5,752 67,365 2,396 38,716
Stock acquired.................
Dividends declared ($.20 per share) (1,363)
Comprehensive income...........
Net income................... $5,069 5,069
Other comprehensive income:
Unrealized gain on marketable
securities, net of tax.. 2,275 2,275
--------
$ 7,344
---------- ------ ------- ======== ------ -------
Balance - September 30, 2000... 11,503,904 $5,752 $67,365 $4,671 $42,422
========== ====== ======= ====== =======
</TABLE>
<PAGE>
[RESTUB TABLE]
<TABLE>
<CAPTION>
Years Ended September 30, 2000, 1999 and 1998
----------------------------------------------
Treasury Stock
---------------------
Shares Amount Total
--------- ------- -------
<S> <C> <C> <C>
Balance - October 1, 1997...... 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)
Net income..................... 14,056
--------- ------- -------
Balance - September 30, 1998... 3,862,917 (53,807) 51,553
Stock acquired................. 419,300 (6,919) (6,919)
Options exercised.............. 255
Dividends declared ($.25 per share) (2,048)
Comprehensive income...........
Net income................... 8,266
Other comprehensive income:
Unrealized gain on marketable
securities, net of tax.. 2,396
--------- ------- -------
Balance - September 30, 1999... 4,282,217 (60,726) 53,503
Stock split ratio activity applied
--------- ------- -------
Balance-September 30, 1999 - rest 4,282,217 (60,726) 53,503
Stock acquired................. 508,803 (5,208) (5,208)
Dividends declared ($.20 per share) (1,363)
Comprehensive income...........
Net income................... 5,069
Other comprehensive income:
Unrealized gain on marketable
securities, net of tax.. 2,275
-------- ------- -------
Balance - September 30, 2000... 4,791,020 ($65,934) $54,276
========= ======= =======
</TABLE>
The accompanying notes are an integral part of these financial statements
-31-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
NOTE 1 - BUSINESS AND ORGANIZATION
Business
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-three percent
(23%) of the Company's outstanding common stock at September 30, 2000.
The Company's only line of business at September 30, 2000 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 and 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.
The Company currently continues to seek acquisitions of exploration and
production and natural gas marketing and transmission assets.
References to the Company mean Castle Energy Corporation, the parent,
and/or 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 its 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 (unaudited)]. During fiscal
2000, the Company participated in the drilling of nine exploratory wells in
south Texas pursuant to two drilling ventures in which the Company participated.
Eight of the wells drilled resulted in dry holes while the other well was
completed as a producing well. Finally, in December 1999, the Company acquired
majority interests in twenty-six (26) offshore Louisiana wells. The Company then
sold these wells to Delta Petroleum Company ("Delta"), a public company involved
in oil and gas exploration and development, in September 2000. The Company also
participated in the drilling of two wildcat wells in Romania in fiscal 2000, but
neither well has yet tested to be commercial.
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 by their own terms and were not
replaced by other third party gas marketing business. The Company continues to
pursue additional natural gas marketing and transmission assets but has not yet
been able to acquire such assets.
-32-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except 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.
Investment In Networked Energy LLC
In August 2000, the Company purchased thirty-five percent (35%) of the
stock of Networked Energy LLC ("Network") for $500. Network is a private company
engaged in the operation of energy facilities that supply power, heating and
cooling services directly to retail customers.
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, 1998, 1999 and 2000 - 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 were recorded when deliveries were 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.
-33-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
Exploration and Production
Oil and gas revenues are recorded under the sales method when oil and
gas production volumes are delivered to the purchaser. Reimbursement of costs
from well operations is netted against oil and gas production expenses.
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
-34-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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.
Expenditures that relate to an existing condition caused by past operations and
that have no future economic benefits are expensed. Liabilities for expenditures
are recorded when environmental assessment and/or remediation is probable and
the costs can be reasonably estimated.
Impairment of Long-Term Assets
The Company reviewed its long-term assets other than oil and gas
properties for impairment whenever events or changes in circumstance indicated
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 were less than the carrying amount of the asset, an
impairment loss would have been 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." The Company currently has no significant long-term assets except
for its oil and gas properties, for which impairment is recorded pursuant to
full cost accounting as described above.
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
Note 1). 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 change in the hedged item.
Exploration and Production
The Company used hedging strategies to hedge a significant portion of
its crude oil and natural gas production through July 31, 2000. The Company used
futures contracts to hedge such production. Gains and losses from hedging
activities were deferred and debited or credited to the item being hedged, oil
and gas sales, when they occurred. In order to qualify as a hedge the change in
fair market value of the hedging instrument must be highly correlated with the
corresponding change in the hedged item. When the hedging instrument ceases to
qualify as a hedge, changes in fair value are charged against or credited 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
Gas balancing activities have been immaterial since May 1997, when the
Company sold a significant portion of its exploration and production assets to
UPRC.
Investment In Network
The Company's investment in Network (the Company owns 35% of Network) is
recorded on the equity method. Under this method, the Company records its share
of Network's income or loss with an offsetting entry to the carrying value of
the Company's investment. Cash dividends, if any, are recorded as reductions in
the carrying value of the Company's investment.
From inception (August 2000) through September 30, 2000, the Company's
share of Network's results of operations was immaterial.
-35-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
Comprehensive Income
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.
Stock Based Compensation
SFAS 123, "Accounting for Stock-Based Compensation," 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. 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. (See Note 17)
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.
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.
New Accounting Pronouncements
Statement of Financial Accounting Standards No. 133, as amended,
"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 such instrument
has been designated and qualifies as part of a hedging relationship and, if so,
depends 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
-36-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
derivative instrument is not designated as a hedge, the gain or loss is
recognized in earnings in the period of change. The Company adopted SFAS 133
effective October 1, 2000. At October 1, 2000, the Company had no freestanding
derivative instruments in place and had no embedded derivative instruments.
Based upon the Company's application of SFAS 133, its adoption had no impact on
its results of operations or financial condition.
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, 1997 to September 30, 2000 is as follows:
<TABLE>
<CAPTION>
Estimated
Realizable Value
of Discontinued Net Refining
Net Refining Assets Liabilities Retained
------------------- --------------------
<S> <C> <C>
Balance - October 1, 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
Cash transactions.................................................... (153)
Adjustment of vendor liabilities..................................... 152
------ ------
Balance - September 30, 2000......................................... $ 800 $3,204
====== ======
</TABLE>
As of September 30, 2000, 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 net vendor liabilities of $1,469 and accrued costs related to
discontinued refining operations of $2,253, offset by cash of $518.
"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.
-37-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
NOTE 4 - ACQUISITIONS AND DISPOSITIONS
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:
Year Ended September 30,
-------------------------------
1999 1998
--------- ----------
(Unaudited) (Unaudited)
Revenues.................................... $ 62,719 $ 81,373
Net income.................................. $ 7,958 $ 14,208
Net income per share........................ $ .95 $ 1.23
Shares outstanding (diluted)................ 8,347,932 11,513,709
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 fiscal 1999, the Company entered into two drilling ventures to
participate in the drilling of up to sixteen exploratory wells in south Texas.
During fiscal 2000, the Company participated in the drilling of nine exploratory
wells pursuant to the related joint venture operating agreements. Eight wells
drilled resulted in dry holes and one well was completed as a producer. The
Company has no further drilling obligations under these joint ventures. The
total cost incurred to participate in the drilling of the exploratory wells was
approximately $5,299.
Offshore Louisiana Property Acquisition
In December 1999, a subsidiary of the Company purchased majority
interests in twenty-six offshore Louisiana wells from Whiting Petroleum Company
("Whiting"), a public company engaged in oil and gas exploration and
development. The adjusted purchase price was $882.
In September 2000, the subsidiary of the Company sold its interests in
the offshore Louisiana wells to Delta. The effective date of the sale was July
1, 2000. The preliminary purchase price of $3,084 consisted of $1,147 cash plus
382,289 shares of Delta's common stock valued at market prices or $1,937. The
Company does not anticipate any material adjustment to the preliminary purchase
price.
-38-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
Investment in Romanian Concession
In April 1999, the Company purchased an option to acquire a fifty
percent (50%) interest in three oil and gas concessions granted to a subsidiary
of Costilla Energy Corporation ("Costilla"), a public oil and gas exploration
and production company, by the Romanian government. The Company paid Costilla
$65 for the option. In May 1999, the Company exercised the option. As of
September 30, 2000, the Company had participated in the drilling of two wildcat
wells and was in the process of drilling a third wildcat well. Neither of the
first two wells was completed as a producer although the Company plans to
conduct further testing of the second well drilled. At September 30, 2000, the
Company had invested $2,279 and provided an $832 impairment reserve against its
Romanian investment, resulting in a net book value of $1,447. The Company
expects that its minimum future obligation for the Romanian concessions will be
at least $1,300.
See Note 10.
Other Exploration and Production Investments
In November and December 1999, the Company acquired additional outside
interests in several Alabama and Pennsylvania wells, which it operates, for
$2,579.
NOTE 5 - RESTRICTED CASH
Restricted cash consists of the following:
<TABLE>
<CAPTION>
September 30,
--------------------
2000 1999
------ ----
<S> <C> <C>
Funds supporting letters of credit for offshore Louisiana wells............. $1,519
Drilling deposits in escrow - Romania....................................... 4 $551
Funds supporting letters of credit issued for operating bonds............... 219 219
------ ----
$1,742 $770
====== ====
</TABLE>
The drilling deposits in escrow in Romania are to be used only to
conduct exploratory drilling activities in Romania and cannot be withdrawn or
used for other purposes by the Company.
The funds supporting the letters of credit for offshore Louisiana wells
are secured by a note from Delta to the extent of $1,300 and Delta is required
to replace those funds not later than June 30, 2001 (see Note 13).
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:
September 30,
--------------------
2000 1999
------ ------
Exploration and production - trade............ $3,758 $3,354
Margin account - hedging...................... 1,750
Interest...................................... 68
------ ------
$3,758 $5,172
====== ======
-39-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
NOTE 7 - NOTE RECEIVABLE - PENN OCTANE
In January 2000, the Company invested $500 in a note due from Penn
Octane Corporation ("Penn Octane"), a public company involved in the sale of
liquid propane gas into Mexico. The note is due on December 15, 2000 and bears
interest at 9%, payable semi-annually. The note is secured by certain assets of
Penn Octane. In addition, the Company received options to acquire 62,500 shares
of common stock of Penn Octane at $4.00 per share. This investment in Penn
Octane is in addition to the Company's investment in the common stock of Penn
Octane.
At September 30, 2000, the amount due from Penn Octane was $513,
consisting of $500 of note principal and $13 of accrued interest.
See Note 21.
NOTE 8 - MARKETABLE SECURITIES
The Company's investment in marketable securities consists of common
shares of Penn Octane and Delta and options to acquire common stock of Penn
Octane.
At September 30, 1998, the Company accounted for its investment as
trading securities. In March 1999, the Company began to account for its
investment as available-for-sale securities. The Company's investments in Penn
Octane and Delta common stock and options to buy Penn Octane stock were as
follows:
Common Stock
-----------------------
Penn Octane Delta Total
----------- ------ -------
September 30, 2000:
Cost........................ $1,750 $1,937 $ 3,687
Unrealized gain............. 7,298 7,298
------ ------ -------
Book value (market
value)...................... $9,048 $1,937 $10,985
====== ====== =======
September 30, 1999:
Gross cost.................. $1,750 $ 1,750
Unrealized gain............. 2,444 2,444
------ -------
Book value (market
value)...................... $4,194 $ 4,194
====== =======
The fair market value of Penn Octane and Delta shares was based on one
hundred percent (100%) of the closing price on September 29, 2000, the last
trading day in the Company's fiscal year ending September 30, 2000.
At September 30, 2000, the Company owned options to purchase 166,667
common shares of Penn Octane common stock at $6.00 per share, options to
purchase 225,000 common shares of Penn Octane common stock at $1.75 per share
and options to purchase 62,500 common shares of Penn Octane common stock at
$4.00 per share. The options had a book (market) value of $1,641at September 30,
2000 based upon the Black - Scholes pricing model (See Note 16). On October 1,
2000, the 166,667 options at $6.00 expired unused.
All of the Company's Penn Octane shares are now registered. The
Company's Delta shares are not registered but the Company has registration
rights with respect to such shares.
See Note 21.
-40-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
NOTE 9 - FURNITURE, FIXTURES AND EQUIPMENT
Furniture, fixtures and equipment are as follows:
<TABLE>
<CAPTION>
September 30,
-----------------------
2000 1999
---- ----
<S> <C> <C>
Cost:
Furniture and fixtures............................................................ $660 $603
Automobile and trucks............................................................. 222 106
---- ----
882 709
Accumulated depreciation................................................................ (624) (411)
---- ----
$258 $298
==== ====
</TABLE>
NOTE 10 - OIL AND GAS PROPERTIES
Oil and gas properties consist of the following:
<TABLE>
<CAPTION>
September 30, 2000
------------------------------------------
United
States Romania Total
-------- --------- -------
<S> <C> <C> <C>
Proved properties......................................................... $42,127 $42,127
Less: Accumulated depreciation, depletion and amortization................ (12,909) (12,909)
------- -------
Proved properties......................................................... 29,218 29,218
Unproved properties not being amortized................................... $2,279 2,279
Impairment of unproved property........................................... (832) (832)
------- ------ -------
$29,218 $1,447 $30,665
======= ====== =======
September 30, 1999
-------------------------------------------
United
States Romania Total
-------- --------- -------
Proved properties......................................................... $34,684 $34,684
Less: Accumulated depreciation, depletion and amortization................ (9,919) (9,919)
------- -------
Proved properties......................................................... 24,765 24,765
Unproved properties not being amortized................................... 928 $934 1,862
------- ---- -------
$25,693 $934 $26,627
======= ==== =======
</TABLE>
Capital costs incurred by the Company in oil and gas activities are as
follows:
<TABLE>
<CAPTION>
Year Ended September 30,
-------------------------------------------------------------------------------
2000 1999
---------------------------------------- ------------------------------------
United United
States Romania Total States Romania Total
-------- ------- ----- -------- ------- -----
<S> <C> <C> <C> <C> <C> <C>
Acquisition of properties:
Proved properties.................... $3,642 $ 3,642 $21,029 $21,029
Unproved properties.................. 678 $ 999 1,677 928 $934 1,862
Exploration............................. 2,966 346 3,312
Development............................. 2,595 2,595 1,073 1,073
------ ------- -------- ------- ---- -------
$9,881 $ 1,345 $ 11,226 $23,030 $934 $23,964
====== ======= ======== ======= ==== =======
</TABLE>
Until September 30, 1998, all of the Company's capital costs were
incurred in the United States. As of September 30, 2000, the Company had
incurred $2,279 in Romania for unproven property acquisition costs and wildcat
drilling costs.
Results of operations, excluding corporate overhead and interest
expense, from the Company's oil and gas producing activities are as follows:
-41-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
<TABLE>
<CAPTION>
Year Ended September 30,
---------------------------------------
2000 1999 1998
---- ---- ----
<S> <C> <C> <C>
Revenues:
Crude oil, condensate, natural gas liquids and natural gas sales... $17,959 $6,712 $2,373
------- ------ ------
Costs and expenses:
Production costs................................................... $ 6,194 1,910 545
Depreciation, depletion and amortization........................... 2,990 1,937 367
Full cost ceiling write down....................................... 832
------- ------ ------
Total costs and expenses........................................... 10,016 3,847 912
------- ------ ------
Income tax provision (benefit).......................................... (6,553) 753 115
------- ------ ------
Income from oil and gas producing activities............................ $16,569 $2,112 $1,346
======= ====== ======
</TABLE>
The income tax provision is computed at a the effective tax rate for the
related fiscal year.
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,
-------------------------------------
2000 1999 1998
---- ---- ----
<S> <C> <C> <C>
Depletion rate per equivalent MCF of natural gas........................ $0.57 $0.71 $0.37
===== ===== =====
</TABLE>
The decrease in the depletion rate in fiscal 2000 resulted primarily
because the Company's reserve quantities increased significantly as a result of
higher oil and gas prices of September 30, 2000. The increase in reserve
quantities without a similar increase in costs resulted in the lower depletion
rate.
The 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.
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 2000, 1999 and 1998) and Ralph E. Davis Associates, Inc. (fiscal 2000
and 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.
-42-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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, 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
Acquisitions............................................... 1,063 6,639
Divestitures............................................... (974) (236)
Discoveries................................................ 1 317
Revisions of previous estimates............................ 2,894 12,728
Production................................................. (279) (3,547)
----- ------
As of September 30, 2000....................................... 4,735 44,303
===== ======
Proved developed reserves:
September 30, 1997............................................. 206 11,480
===== ======
September 30, 1998............................................. 162 13,589
===== ======
September 30, 1999............................................. 1,788 23,547
===== ======
September 30, 2000............................................. 2,963 35,815
===== ======
</TABLE>
Although the Company has 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.
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.
-43-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
<TABLE>
<CAPTION>
September 30,
-------------------------------------------
2000 1999 1998
---- ---- ----
<S> <C> <C> <C>
Future cash inflows................................................ $371,784 $118,794 $40,576
Future production costs............................................ (87,162) (42,934) (14,141)
Future development costs........................................... (12,620) (4,229) (1,283)
Future income tax expense.......................................... (84,445) (8,538) (4,868)
-------- -------- -------
Future net cash flows.............................................. 187,557 63,093 20,284
Discount factor of 10% for estimated timing of future cash flows... (96,438) (21,849) (10,338)
-------- -------- -------
Standardized measure of discounted future cash flows............... $ 91,119 $ 41,244 $ 9,946
======== ======== =======
</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 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,
------------------------------------------
2000 1999 1998
---- ---- ----
<S> <C> <C> <C>
Standardized measure, beginning of year............................. $41,244 $ 9,946 $10,767
Sale of oil and gas, net of production costs........................ (11,083) (4,324) (1,598)
Net changes in prices............................................... 45,757 2,163 (2,498)
Sale of reserves in place........................................... (1,457)
Purchase of reserves in place....................................... 6,757 22,215
Changes in estimated future development costs....................... (5,039) 2,405 (615)
Development costs incurred during the period that reduced future
development costs................................................ 2,595 1,073 2,195
Revisions in reserve quantity estimates............................. 76,355 1,438 594
Discoveries of reserves............................................. 963
Net changes in income taxes......................................... (32,031) 745 831
Accretion of discount............................................... 4,286 995 1,077
Other:
Change in timing of production................................... (36,168) 12,055 365
Other factors.................................................... (1,060) (7,467) (1,172)
------- ------- -------
Standardized measure, end of year................................... $91,119 $41,244 $ 9,946
======= ======= =======
</TABLE>
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 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. ("Texaco"), 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.
-44-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except 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 responded to the EPA information request in
January 2000.
On August 7, 2000, the Company received notice of a claim against it
and two of its inactive refining subsidiaries from Texaco and its parent. In its
claim, Texaco demanded that the Company and its former subsidiaries indemnify
Texaco for all liability resulting from environmental contamination at and
around the Indian Refinery. In addition, Texaco demanded that the Company assume
Texaco's defense in all matters relating to environmental contamination at and
around the Indian Refinery, including lawsuits, claims and administrative
actions initiated by the EPA as well as indemnify Texaco for costs that Texaco
has already incurred addressing environmental contamination at the Indian
Refinery. Finally, Texaco also claimed that the Company and its two inactive
subsidiaries are liable to Texaco under the Federal Comprehensive Environmental
Response Compensation and Liability Act as owners and operators of the Indian
Refinery.
The Company and its general counsel believe that Texaco's claims are
utterly without merit and the Company intends to vigorously defend itself
against Texaco's claims and any lawsuits that may follow.
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 and received relevant
information from the Company and Texaco made a claim against the Company and two
of its subsidiaries for all liability resulting from contamination at and around
the Indian Refinery. 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.
-45-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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, 2000:
Lease Sublease
Year Ending September 30, Commitments Rentals
------------------------- ----------- -------
2001.................................... $ 485 $ 64
2002.................................... 473 65
2003.................................... 470 66
2004.................................... 240
2005.................................... 76
------ ----
$1,744 $195
====== ====
Rent expense for the years ended September 30, 2000, 1999 and 1998 was
$412, $386 and $245, respectively.
Severance/Retention Obligations
The Company has severance agreements with substantially all of its
employees, including five of its officers, that provide for severance
compensation in the event substantially all of the Company's or its
subsidiaries' assets are sold and the employees are terminated as a result of
such sale. Such termination severance commitments aggregated $1,214 at September
30, 2000. No severance obligations were owed to employees at September 30, 2000.
In addition, at September 30, 2000 the Company had retention agreements
with six of its non-officer employees. Such retention is payable in equal
installments on October 31, 2000 and February 28, 2001. Such retention
obligations aggregated $105 at September 30, 2000.
Letters of Credit
At September 30, 2000, 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. In addition, the Company had issued
letters of credit aggregating $1,300 to prior owners of wells in offshore
Louisiana. The Company purchased interests in these wells from Whiting in
December 1999 and sold them to Delta in September 2000. Delta has agreed to
replace these letters of credit by June 30, 2001, and has issued the Company a
note to secure such obligation. If Delta fails to replace the letters of credit
by June 30, 2001, the Company has the option to collect on the Delta note or to
take shares of Delta common stock at $4.00 note principal per Delta share as
payment. The Company is also entitled to 8% interest on the note.
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.
-46-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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. 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.
In May 2000, the Company settled this lawsuit for $120.
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 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 $40,000.
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
apparently 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.
In April 2000, Larry Long withdrew as a named plaintiff and in
September 2000, the Company and the remaining named plaintiff agreed to settle
the case for a payment of $250 by the Company. The parties are currently
finalizing the settlement agreement, subject to court approval.
MGNG Litigation
On May 4, 1998, Castle Texas Production Limited Partnership ("CTPLP"),
a subsidiary of the Company, 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 sought to
recover gas measurement and transportation expenses charged by the defendants in
breach of a certain gas purchase contract. Improper charges exceeded $750 before
-47-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
interest. In October of 1998, MGNG and MGC filed a suit in Harris County, Texas.
This suit sought indemnification from two of the Company's subsidiaries in the
event CTPLP won its lawsuit against MGNG and MGC. The MG entities 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 parties participated in
mediation but were not able to resolve the 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 CTPLP by MGNG for improper gas
measurement and transportation deductions. The Castle entities answered this
suit denying MGNG's claims based partially on the right of offset.
In September 2000, the parties agreed to settle the case. Under the
terms of the proposed settlement the amount claimed by MGNG under a gas supply
contract was reduced by $325, CTPLP agreed to pay MGNG the reduced amount of
$447 and the parties agreed to sign mutual releases. The parties are currently
in the process of finalizing this settlement agreement.
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 negotiations, the Company believes that
revenue attributable to the ORRI should be released to CECI in the near future.
As of September 30, 2000, approximately $250 attributable to CECI's share of the
ORRI revenue was suspended.
See Note 21.
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 was to
receive $1,000 cash in settlement for its loans when GAMXX closed on its
financing. GAMXX expected such closing not later than May 31, 1998 but such
closing has still not occurred.
The Company has carried its loans to GAMXX at zero for the last seven
years. The Company will record the $1,000 proceeds or any portion thereof as
"other income" if and when it collects such amount. The Company considers the
probability of collection remote.
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. In May 1999, the Company's subsidiary terminated
its natural gas marketing business. As of September 30, 2000, 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
-48-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
production for the period from October 1, 1999 to September 30, 2000. The
Company 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, were $19.85 per barrel of crude oil and $2.66 per
mcf of gas. The Company accounted for these futures contracts as hedges and the
differences between the hedged price and the exchange price increased or
decreased 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 $1,528 and
$150 for the fiscal years ended September 30, 2000 and 1999, respectively.
At September 30, 2000 and as of November 24, 2000, the Company had not
hedged its anticipated future oil and gas production.
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. The Company is
currently in the process of extending its 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, 2000, 1999 and 1998, the Company's
contributions to the Plan aggregated $46, $37 and $23, respectively.
Post-Retirement Benefits
Neither the Company nor its subsidiaries provide any other post
retirement plans for employees.
NOTE 15 - STOCKHOLDERS' EQUITY
On December 29, 1999, the Company's Board of Directors declared a stock
split in the form of a 200% stock dividend applicable to all stockholders of
record on January 12, 2000. The additional shares were paid on January 31, 2000
and the Company's shares first traded at post-split prices on February 1, 2000.
The stock split applied only to the Company's outstanding shares on January 12,
2000 (2,337,629 shares) and did not apply to treasury shares (4,491,017 shares)
on that date. As a result of the stock split, 4,675,258 additional shares were
issued and the Company's common stock book value was increased $2,338 to reflect
additional par value applicable to the additional shares issued to effect the
stock split. All share changes, including those affecting the recorded book
value of common stock, have been recorded retroactively.
From November 1996 until September 30, 2000, the Company's Board of
Directors authorized the Company to purchase up to 5,267,966 of its outstanding
shares of common stock on the open market. As of September 30, 2000, 4,791,020
shares (13,773,054 shares before taking into account the 200% stock dividend
effective January 31, 2000) had been repurchased at a cost of $65,934. The
repurchased shares are held in treasury. Subsequent to September 30, 2000, the
Company purchased an additional 40,000 shares at a cost of $300 (see Note 21).
-49-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
On June 30, 1997, the Company's Board of Directors approved a dividend
policy of $.20 per share per year, payable quarterly. The dividend policy
remains in effect until rescinded or changed by the Board of Directors.
Quarterly dividends of $.05 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, 2000 are as follows (in whole units):
<TABLE>
<CAPTION>
Incentive
Plan Other
Options Options Total
--------- ------- -----
<S> <C> <C> <C>
Outstanding at October 1, 1997....................................... 162,500 25,000 187,500
Issued............................................................... 55,000 55,000
Exercised............................................................ (5,000) (5,000)
Repurchased.......................................................... (17,500) (5,000) (22,500)
--------- ------ ---------
Outstanding at September 30, 1998.................................... 195,000 20,000 215,000
Issued............................................................... 15,000 15,000
Exercised............................................................ (25,000) (25,000)
Repurchased.......................................................... (10,000) (10,000)
--------- ------ ---------
Outstanding at September 30, 1999.................................... 175,000 20,000 195,000
Effect of 200% stock dividend (see Note 15).......................... 350,000 40,000 390,000
Issued............................................................... 105,000 105,000
--------- ------ ---------
Outstanding at September 30, 2000.................................... 630,000 60,000 690,000
========= ====== =========
Exercisable at September 30, 2000.................................... 615,000 60,000 675,000
========= ====== =========
Reserved at September 30, 2000....................................... 1,687,500 60,000 1,747,500
========= ====== =========
Reserved at September 30, 1999....................................... 1,687,500 60,000 1,747,500
========= ====== =========
Reserved at September 30, 1998....................................... 1,687,500 60,000 1,747,500
========= ====== =========
Exercise prices at:
September 30, 2000.......................................... $ 3.42- $3.79
$ 8.58
September 30, 1999.......................................... $ 3.42- $3.79
$ 5.75
September 30, 1998.......................................... $ 3.42- $3.58-
$ 5.75 $3.79
Exercise Termination Dates.................................. 5/17/2003- 4/23/2007 5/17/2003-
4/11/2010 4/11/2000
</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 1,687,500 shares
(after taking into account the 200% stock dividend effective January 31, 2000)
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 15,000 shares of common
stock at fair market value on the date of grant.
-50-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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.
A summary of the Company's stock option and warrant activity from
October 1, 1997 to September 30, 2000 is as follows:
Weighted
Average
Options Price
------- --------
Outstanding - October 1, 1997.................... 187,500 11.69
Issued........................................... 55,000 16.23
Exercised........................................ (5,000) 12.65
Repurchased...................................... (22,500) 10.43
------- -----
Outstanding - September 30, 1998................. 215,000 12.96
Issued........................................... 15,000 17.25
Exercised........................................ (25,000) 10.25
Repurchased...................................... (10,000) 10.75
------- -----
Balance - September 30, 1999..................... 195,000 13.75
Effect of 200% stock dividend (see Note 15)...... 390,000 (9.17)
Issued........................................... 105,000 7.89
------- -----
Outstanding - September 30, 2000................. 690,000 $5.09
======= =====
At September 30, 2000, exercise prices for outstanding options ranged
from $3.42 to $8.58. The weighted average remaining contractual life of such
options was 6.3 years.
The per share weighted average fair values of stock options issued
during fiscal 2000, 1999 and fiscal 1998 were $3.29, $4.56 and $3.92,
respectively, on the dates of issuance using the Black-Scholes option pricing
model with the following weighted average assumptions: average expected dividend
yield -3.1% in 2000, 3.5% in 1999 and 3.6% in 1998; risk free interest rate -
5.54% in 2000, 6.32% in 1999 and 5.03% in 1998; expected life of 10 years in
2000, 1999 and 1998 and volatility factor of .44 in 2000, .22 in 1999 and .24 in
1998.
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.
-51-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
Proforma 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,
-----------------------------------------
2000 1999 1998
---- ---- ----
<S> <C> <C> <C>
Net income as reported............................................... $5,069 $8,266 $14,056
Adjustment required by SFAS 123...................................... (346) (152) (132)
------ ------ -------
Pro-forma net income................................................. $4,723 $8,114 $13,924
====== ====== =======
Pro-forma net income per share:
Basic............................................................. $ .68 $ .99 $ 1.22
====== ====== =======
Diluted........................................................... $ .66 $ .97 $ 1.21
====== ====== =======
</TABLE>
NOTE 17 - INCOME TAXES
Provisions for (benefit of) income taxes consist of:
<TABLE>
<CAPTION>
September 30,
--------------------------------------------
2000 1999 1998
---- ---- ----
<S> <C> <C> <C>
Provision for (benefit of) income taxes:
Current:
Federal....................................................... ($ 35) $ 193 $ 223
State......................................................... (2) 13
Deferred:
Federal....................................................... 922 2,209 1,653
State......................................................... 26 68 47
Adjustment to the valuation allowance for deferred taxes:
Federal....................................................... (3,115) 475 (712)
State......................................................... (89) 13 (20)
------- ------ ------
($2,291) $2,956 $1,204
======= ====== ======
</TABLE>
Deferred tax assets (liabilities) are comprised of the following at
September 30, 2000 and 1999:
<TABLE>
<CAPTION>
September 30,
-----------------------
2000 1999
---- ----
<S> <C> <C>
Operating losses and tax credit carryforwards....................................... $4,993 $3,775
Statutory depletion carryovers...................................................... 3,689 3,597
Depletion accounting................................................................ (3,602) (1,044)
Discontinued net refining operations................................................ 866 866
Losses in foreign subsidiaries...................................................... 300
------ ------
6,246 7,194
Valuation allowance................................................................. (3,990) (7,194)
------ ------
$2,256 -
====== ======
Deferred tax assets - current....................................................... $2,256
Deferred tax assets - non-current...................................................
------ ------
$2,256
====== ======
</TABLE>
At September 30, 2000, the Company determined that it was more likely
than not, that a portion of the deferred tax assets would be realized, based on
current projections of taxable income due to higher commodity prices at
September 30, 2000, and the valuation allowance was decreased by $3,204 to a
total valuation allowance of $3,990.
-52-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
In 1999, the Company increased its valuation allowance by $489 to
$7,194 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.
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,
-------------------------------------
2000 1999 1998
---- ---- ----
<S> <C> <C> <C>
Tax at statutory rate.................................................... $ 972 $3,928 $5,341
State taxes, net of federal benefit...................................... (42) 51 26
Revision of tax estimates and contingencies.............................. (151) (3,463)
Statutory depletion...................................................... (1,330)
Increase (decrease) in valuation allowance............................... (3,204) 489 (732)
Other.................................................................... (17) (31) 32
------- ------ ------
($2,291) $2,956 $1,204
======= ====== ======
</TABLE>
At September 30, 2000, the Company had the following tax carryforwards
available:
Federal Tax
------------------------
Alternative
Minimum
Regular Tax
------- -----------
Net operating loss.......................... $ 2,888 $25,120
Alternative minimum tax credits............. $ 3,953 N/A
Statutory depletion......................... $10,246
The net operating loss carryforwards expire from 2001 through 2009.
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 carryforward 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 and 1998 the Company
used $4,367, and $10,295, respectively, of its net operating loss carryforwards,
including $2,765 of built-in gains.
The Company also has approximately $58,000 in individual state tax loss
carryforwards available at September 30, 2000. Approximately $47,000 of 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.
-53-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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.
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,
2000, 1999 and 1998 aggregated zero, zero and $292, 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.
Another officer of the Company is a 10% shareholder in an unaffiliated
company that is entitled to receive 12.5% of the Company's share of net cash
flow from it Romanian joint venture after the Company has recovered its
investment in Romania.
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.
The Company does not allocate interest income, interest expense or
income tax expense to these segments.
<TABLE>
<CAPTION>
Year Ended September 30, 2000
---------------------------------------------------------------------------------------
Natural Gas Oil & Gas Eliminations
Marketing Exploration and
and and Refining Corporate
Transmission Production (Discontinued) Items Consolidated
------------ ---------- -------------- ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues........................... $17,959 $17,959
Operating income (loss)............ $ 5,686 ($ 3,717) $ 1,969
Identifiable assets................ $67,727* $92,229 ($96,661) $63,295
Capital expenditures............... $11,399 $11,399
Depreciation, depletion and
amortization................ $3,207 $ 2 $ 3,209
</TABLE>
-54-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
<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
Year Ended September 30, 1998
---------------------------------------------------------------------------------------
Natural Gas Oil & Gas Eliminations
Marketing Exploration and
and and Refining Corporate
Transmission Production (Discontinued) Items Consolidated
------------ ---------- -------------- ------------ ------------
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>
*Consists primarily of intracompany receivables.
For the years ended September 30, 1999 and 1998, sales by the Company's
natural gas marketing subsidiary to Lone Star Gas Company under the Lone Star
Contract aggregated $46,802 and $64,619, respectively. These amounts constituted
approximately 82% and 89% of consolidated revenues for the years ended September
30, 1999 and 1998, respectively. The Lone Star contract terminated in May 1999.
At the present time, the Company's consolidated revenues consist
entirely of oil and gas sales. Two 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 24% of consolidated revenues and
are expected to comprise a similar percentage of oil and gas sales in the
future.
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 and Delta common stock and options to buy Penn Octane stock and are
recorded at fair market value. Market value for common stock is computed to
equal the closing share price at year end times the number of shares held by the
Company. Fair market value for options is computed using the Black - Scholes
option valuation model.
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 - SUBSEQUENT EVENTS
Subsequent to September 30, 2000, the Company repurchased an additional
40,000 shares of its common stock at a cost of $300. (See Note 15).
-55-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
On October 21, 2000, options held by the Company to acquire 166,667
shares of the common stock of Penn Octane at $6.00 expired as they were not
exercised by the Company (see Note 8).
Subsequent to September 30, 2000, the market price of the common stocks
of Penn Octane and Delta declined significantly. Based upon the closing prices
of these stocks at November 24, 2000, the market value of the Company's
investment was $5,848 at that time. In addition, the market value of the
Company's remaining options to acquire Penn Octane's common stock was $506.
In December 2000, the Company agreed to extend its $500 note receivable
from Penn Octane until June 15, 2002. In return, Penn Octane agreed to increase
the interest rate on the note to 13.5% and to issue to the Company warrants to
acquire an additional 62.500 shares of Penn Octane common stock at $3.00 per
share. Penn Octane paid all interest due on the note through December 15, 2000,
its original due date (see Note 7).
In November 2000, the Company and three of its subsidiaries were
defendants in a jury trial in Rusk County, Texas. The plaintiffs in the case,
the Long Trusts, are non-operating working interest owners in wells previously
operated by CTPLP. The wells were among those sold to UPRC in May 1997 (see Note
4). The Long Trusts claimed that CTPLP did not allow them to sell their share of
gas production from March 1, 1996 to January 31, 1997 as required by applicable
joint operating agreements, and they sued CTPLP and the other defendants,
claiming (among other things) breach of contract, breach of fiduciary duty,
conversion and conspiracy. The plaintiffs sought actual damages, exemplary
damages, pre-judgment and post- judgment interest, attorney's fees and court
costs. CTPLP counterclaimed for approximately $150 of unpaid joint interests
billings, attorneys' fees and court costs.
After a three-week trail, the District Court submitted 36 questions to
the jury which covered all of the claims and counterclaims in the lawsuit. The
jury's answers supported the plaintiffs' claims against the Company and its
subsidiaries, CTPLP's counterclaim against the plaintiffs and two of the
affirmative defenses asserted by the defendants. The Company and its
subsidiaries are preparing motions to have the District Court disregard certain
jury findings and to render judgment on other findings. Plaintiffs are
presumably similarly engaged. Because certain of the plaintiffs' theories are
mutually exclusive and because certain jury findings are duplicative, it is
difficult to determine the amount of any judgment that the plaintiffs will seek
to have entered. The plaintiffs may seek to have the Court award them as much as
$2,900 plus interest on certain items. The defendants will seek to have the
Court award them approximately $700 plus interest on certain items. It is
impossible to determine at this time the amount of any judgment that may be
rendered by the District Court; however, the defendants have already filed
notice that they will appeal the matter to the Tyler, Texas Court of Appeals.
Special counsel to the Company does not consider an unfavorable outcome
to this lawsuit probable. The Company's management and legal counsel believe
that several of the plaintiffs' primary legal theories are contrary to
established Texas law and that the Court's charge to the jury was fatally
defective. They further believe that any judgment for plaintiffs based on those
theories or on the jury's answers to certain questions in the charge cannot
stand and will be reversed on appeal. Nevertheless, the Company and its
subsidiaries may be required to post a bond to cover the total amount of damages
awarded to the plaintiffs in any judgment and to maintain that bond until the
resolution of any appeals (which may take several years).
-56-
<PAGE>
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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, 2000 and 1999, 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, 2000. 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 auditing standards generally accepted
in the United State of America. 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, 2000 and 1999, and the results
of their operations and their cash flows for each of the years in the three year
period ended September 30, 2000 in conformity with accounting principles
generally accepted in the United States of America.
KPMG LLP
Houston, Texas
December 27, 2000
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<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
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<PAGE>
PART III
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 Items 10, 11, 12 and 13 is incorporated by
reference to the Registrant's Proxy Statement for its 2001 Annual Meeting of
Stockholders.
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<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.
<TABLE>
<CAPTION>
Exhibit Number Description of Document
-------------- -----------------------
<S> <C>
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 (26)
10.131 Letter dated July 29, 1999 between Penn Octane Corporation and Castle Energy Corporation (26)
10.132 Castle Energy Corporation Severance Benefit Plan (26)
10.133 Asset Acquisition Agreement between Castle Exploration Company, Inc., Deerlick Creek Partners,
I., L.P. and Deven Resources, Inc, effective September 1, 1999 (27)
</TABLE>
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<PAGE>
<TABLE>
<CAPTION>
Exhibit Number Description of Document
-------------- -----------------------
<S> <C>
10.134 Purchase and Sale Agreement, dated December 15, 1999, between Whiting Park Production, Ltd. and
Castle Exploration Company, Inc. (27)
10.135 Asset Acquisition Agreement between Castle Exploration Company, Inc, and American Refining and
Exploration Company, Deven Resources, Inc., CMS/Castle Development Fund I L.P., effective as of
October 1, 1999 (27)
10.136 Promissary Note between CEC, Inc. and Penn Octane Corporation (28)
10.137 Purchase Agreement between CEC, Inc. and Penn Octane Corporation Effective January 5, 2000 (28)
10.138 Purchase and Sale Agreement, dated August 6, 2000 between and among Castle Exploration
Company, Inc., Parks and Luttrell Energy Partners L.P. and Parks and Luttrell Energy, Inc.
10.139 Purchase and Sale Agreement dated August 4, 2000 between Castle Offshore LLC, BWAB Limited
Liability Company and Delta Petroleum Company
10.140 Agreement to Transfer a Membership Interest In Networked Energy LLC to CEC, Inc., dated August
31, 2000
11.1 Statement re: Computation of Earnings Per Share
21 List of subsidiaries of Registrant
23.2 Consent of Ralph E. Davis Associates, Inc.
23.3 Consent of Huntley & Huntley, Inc.
27 Financial Data Schedule
</TABLE>
(b) Reports on Form 8-K
The Company filed no reports on Form 8-K during the last quarter of the
Company's fiscal year ended September 30, 2000.
-----------------
(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
(26) Incorporated by reference to the Registrant's Form 10-K for the fiscal year
ended September 30, 1999
(27) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
December 31, 1999
(28) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
March 31, 2000
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<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 22, 2000 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 22, 2000
------------------------ Executive Officer
Joseph L. Castle II Director
/s/MARTIN R. HOFFMANN Director December 22, 2000
------------------------
Martin R. Hoffmann
/s/JOHN P. KELLER Director December 22, 2000
------------------------
John P. Keller
/s/RUSSELL S. LEWIS Director December 22, 2000
------------------------
Russell S. Lewis
/s/RICHARD E. STAEDTLER Senior Vice President December 22, 2000
------------------------- Chief Financial Officer
Richard E. Staedtler Chief Accounting Officer
Director
/s/SIDNEY F. WENTZ Director December 22, 2000
-------------------------
Sidney F. Wentz
</TABLE>
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<PAGE>
DIRECTORS AND OFFICERS
BOARD OF DIRECTORS
(December xx, 2000)
JOSEPH L. CASTLE II RICHARD E. STAEDTLER
Chairman & Chief Executive Officer Chief Financial Officer and Chief
Accounting Officer
MARTIN R. HOFFMANN SIDNEY F. WENTZ
Former Chairman of The Robert Wood
Johnson Foundation
JOHN P. KELLER RUSSELL S. LEWIS
President, Keller Group, Inc. President, Lewis Capital Group
OPERATING OFFICERS
JOSEPH L. CASTLE II RICHARD E. STAEDTLER
Chief Executive Officer Chief Financial Officer
Chief Accounting Officer
WILLIAM C. LIEDTKE III TIMOTHY M. MURIN
Company Counsel 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, Alabama 35406 Pittsburgh, PA 15241-1633
P.O. Box 425 5623 North Western Avenue, Suite A
Acme, PA 15610-0425 Oklahoma City, OK 73118
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
