SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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, 2001
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
(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-- $.50 par value and related Rights
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ X ].
As of December 14, 2001, there were 6,632,884 shares of the
registrant's Common Stock ($.50 par value) outstanding. The aggregate market
value of voting stock held by non-affiliates of the registrant as of such date
was $29,637,835 (5,049,035 shares at $5.87 per share).
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Proxy Statement for the 2002 Annual Meeting of
Stockholders are incorporated by reference in Items 10, 11, 12 and 13
CASTLE ENERGY CORPORATION
2001 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.......... 10
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters.......................................... 11
6. Selected Financial Data...................................... 11
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 13
8. Financial Statements and Supplementary Data.................. 26
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 59
PART III
10. Directors and Executive Officers of the Registrant........... 60
11. Executive Compensation....................................... 60
12. Security Ownership of Certain Beneficial Owners and
Management................................................... 60
13. Certain Relationships and Related Transactions............... 60
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K..................................................... 61
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 uses 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 one or more of
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 was unable to
negotiate similar profitable long-term contracts since most gas purchasers now
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 segment of the energy business. During the fiscal
years ended September 30, 2001, 2000 and 1999 the Company invested $15,449,000,
$11,226,000 and $23,964,000 respectively, in oil and gas property acquisition,
exploration and development, including $3,707,000 in Romania. The Company is
currently planning to participate in the drilling of a wildcat well in the Black
Sea in the spring or early summer of 2002. As of September 30, 2001, the
Company's exploration and production subsidiaries owned interests in 522
producing oil and gas wells located in fourteen states. Of these interests, 430
were working interests, where the Company is responsible for operating costs
applicable to the well, and 92 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, 2001, the Company's exploration and
production assets included proved reserves of approximately 31 billion cubic
feet of natural gas and approximately 3,400,000 barrels of oil.
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 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.
-1-
In August 2000, the Company purchased thirty-five percent (35%) of the
membership interests 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.
On December 11, 2001, the Company entered into a letter of intent to
sell all of its domestic oil and gas assets to Delta Petroleum Company ("Delta")
for $20,000,000 cash and 9,566,000 shares of common stock of Delta. The
effective date of the sale is October 1, 2001 and the expected closing date is
April 30, 2002 or later. The sale is subject to execution of a definitive
purchase and sale agreement by both parties, approval of the transaction by the
boards of directors of the Company and Delta and approval by Delta's
shareholders of the issuance of the Delta shares to Castle.
In October 1996, the Company commenced a program to repurchase shares of
its common stock at stock prices beneficial to the Company. At December 14,
2001, 4,871,020 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 396,946 additional shares.
OIL AND GAS EXPLORATION AND PRODUCTION
General
On June 1, 1999, the Company consummated the purchase of all of the oil
and gas properties of AmBrit Energy Corp. ("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 was January 1, 1999. The adjusted purchase price after accounting for all
transactions between the effective date, January 1, 1999, and the closing date
was $20,170,000. 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 2,000,000
barrels of crude oil and 12,500,000 mcf (thousand cubic feet) of natural gas,
which, together, approximated 150% of the Company's oil and gas reserves before
the acquisition. In addition, the production acquired initially increased the
Company's consolidated production by approximately 425%.
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 and has
terminated participation in each drilling venture. The total cost incurred to
participate in the drilling of the exploratory wells was $6,003,000.
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 $890,000.
In September 2000, the subsidiary sold its interests in the offshore
Louisiana wells to Delta. The effective date of the sale was July 1, 2000. The
adjusted purchase price of $3,059,000 consisted of $1,122,000 cash plus 382,289
shares of Delta's common stock valued at the closing market price of $1,937,000
(see Note 8 to the Company's Consolidated Financial Statements included in Item
8 of this Form 10-K).
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
$65,000 for the option. In May 1999, the Company exercised the option. As of
September 30, 2001, the Company had participated in the drilling of five wildcat
wells in Romania. Four of those wells resulted in dry holes. Although the fifth
well produced some volumes of natural gas when tested, the Company has not been
able to obtain a sufficiently high gas price to justify future production and
has elected at the present time not to undertake an offset drilling program in
the acreage surrounding the fifth well. The Company has agreed to participate in
the drilling of a sixth well in the Black Sea in the spring or early summer of
2002.
-2-
In November and December 1999, the Company acquired additional outside
interests in several Alabama and Pennsylvania wells, which it operates, for
$2,580,000.
On April 30, 2001, the Company consummated the purchase of several East
Texas oil and gas properties from a private company. The effective date of the
purchase was April 1, 2001. These properties included majority interests in
twenty-one (21) operated producing oil and gas wells and interests in
approximately 6,500 gross acres in three counties in East Texas. The Company
estimated the proved reserves acquired to be approximately 12.5 billion cubic
feet of natural gas and 191,000 barrels of crude oil. The consideration paid,
net of purchase price adjustments, was $10,040,000. The Company used its own
internally generated funds to make the purchase.
Properties
Proved Oil and Gas Reserves
The following is a summary of the Company's oil and gas reserves as of
September 30, 2001. 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, 2001
were as follows:
Net MCF (1) of gas:
Proved developed............................................. 26,480,000
Proved undeveloped........................................... 4,212,000
----------
Total........................................................ 30,692,000
==========
Net barrels of oil:
Proved developed............................................. 1,890,000
Proved undeveloped........................................... 1,470,000
----------
Total........................................................ 3,360,000
==========
- -----------------
(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, 2001, including production from acquired properties since the date
of acquisition.
Fiscal Year Ended September 30,
2001 2000 1999
---- ---- ----
Oil -- Bbls (barrels)................................. 262,000 279,000 124,000
Gas -- MCF............................................ 3,083,000 3,547,000 1,971,000
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.
-3-
Fiscal Year Ended September 30,
2001 2000 1999
---- ---- ----
Average Sales Price per Barrel of Oil.......................... $27.39 $27.94 $18.36
Average Sales Price per MCF of Gas............................. $ 4.53 $ 2.87 $ 2.25
Average Production Cost per Equivalent MCF(1).................. $ 1.59 $ 1.19 $ .70
--------------
(1) For purposes of equivalency of units, a barrel of oil is assumed
equal to six MCF of gas, based upon relative energy content.
No production was hedged in fiscal 2001.
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 after July 2000.
Productive Wells and Acreage
The following table presents the oil and gas properties in which the
Company held an interest as of September 30, 2001. The wells and acreage owned
by the Company and its subsidiaries are located primarily in Alabama,
California, Illinois, Louisiana, Mississippi, Montana, New Mexico, Oklahoma,
Pennsylvania, Texas and Wyoming.
As of
September 30, 2001
Gross(2) Net (3)
------------ ----------
Productive Wells:(1)
Gas Wells................................................. 521 203
Oil Wells................................................. 103 49
Acreage:
Developed Acreage......................................... 129,517 31,351
Undeveloped Acreage....................................... 85,686 29,678
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).
----------------
(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, 2001 the number of gross and net productive and dry
developmental wells drilled, including wells drilled on acquired properties
since the dates of acquisition.
-4-
Fiscal Year Ended September 30,
----------------------------------------------------------------------------------------------------
2001 2000 1999
------------------------------------- --------------------------------------- -----------------
United States Romania United States Romania United States
------------------ ----------------- ----------------- -------------------- -----------------
Productive Dry Productive Dry Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- --- ---------- --- ---------- ---
Developmental:
Gross........... 17 4 -- -- 9 -- -- 5 3
Net............. 4 1.3 -- -- 4.5 -- -- 2.3 1.2
Exploratory:
Gross........... -- 3* 1 8 -- 2 -- --
Net............. -- 1.5* .5 3.75 -- 1 -- --
All wells drilled by the Company in fiscal 1999 were drilled in the
United States.
* One well, in which the Company has a fifty percent (50%) interest,
produced some volumes of natural gas when tested but the Company has
not been able to obtain a price for its production that makes future
operations economical.
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. 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 requirements continue to absorb
an increasing percentage of management's time.
The Company plans to participate in the drilling of a wildcat well in
the Black Sea in the spring or early summer of 2002. Participation in the
drilling of this well will expose the Company to several risks not commonly
associated with the Company's domestic onshore operations including drilling
offshore, using foreign contractors to drill, political and governmental
regulatory risks and possible delays in obtaining permits, parts and supplies.
In addition, if the well is successful, a pipeline may have to be installed to
transport the crude oil or natural gas discovered to onshore collection
facilities.
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, including the well planned to
be drilled in the Black Sea.
-5-
EMPLOYEES AND OFFICE FACILITIES
As of November 30, 2001, the Company, through its subsidiaries, employed
30 personnel. 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
Blue Bell, PA Accounting and Land
Mt. Pleasant, PA Gas Production Office
Pittsburgh, PA Drilling and Exploration Office
Tuscaloosa, Alabama Oil and Gas Production Office
Oklahoma City, Oklahoma Legal and International Operations
ITEM 3. LEGAL PROCEEDINGS
Contingent Environmental Liabilities
In December 1995, IRLP, an inactive subsidiary of the Company, sold its
refinery, the Indian Refinery, to American Western Refining L.P. ("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 outside party has substantially dismantled the Indian
Refinery. American Western recently filed a Plan of Liquidation. American
Western anticipates that the Plan of Liquidation expects to be confirmed in
January 2002.
During fiscal 1998, the Company was informed that the United States
Environmental Protection Agency ("EPA") had investigated offsite acid sludge
waste found near the Indian Refinery and had investigated and remediated surface
contamination on 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 inactive
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. A subsidiary of Texaco had owned the refinery until December
of 1988. The Company subsequently responded to the EPA indicating that it was
neither the owner nor the 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. Texaco had
made no previous claims against the Company although the Company's subsidiaries
had owned the refinery from August 1989 until December 1995. 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 and indemnify Texaco for costs that Texaco has already incurred
addressing environmental contamination at the Indian Refinery. Finally, Texaco
also claimed that the Company and two of its 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
responded to Texaco disputing the factual and theoretical basis for Texaco's
claims against the Company. The Company's management and special counsel
subsequently met with representatives of Texaco but the parties disagreed
concerning Texaco's claims.
-6-
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 addition to the
numerous defenses that the Company has against Texaco's contractual claim for
indemnity, the Company and its special counsel believe that by the express
language of the agreement which Texaco construes to create an indemnity, Texaco
has irrevocably elected to forgo all rights of contractual indemnification it
might otherwise have had against any person, including the Company.
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, we are informed, continues to seek 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. Estimated gross undiscounted clean-up costs for
this refinery are at least $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. Furthermore, as noted above,
Texaco has claimed that the Company indemnified it for all environmental
liabilities related to the Indian Refinery. If Texaco were to sue the Company on
this theory and prevail in court, the Company could be held responsible for the
entire estimated clean up costs of $80,000,000-$150,000,000 or more. In such a
case, this cost would be far in excess of the Company's financial capability.
An opinion issued by the U.S. Supreme Court in June 1998 in a comparable
matter and a recent opinion by the U.S. Appeals Court for the Fifth Circuit
support the Company's positions. 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
parties 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
Long Trusts Lawsuit
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 Castle Texas Production Limited Partnership ("CTPLP"), an inactive
exploration and production subsidiary of the Company. The wells were among those
sold to UPRC in May 1997. The Long Trusts claimed that CTPLP did not allow them
to sell gas 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, interest, attorneys' fees and court costs.
After a three-week trial, the District Court in Rusk County submitted 36
questions to the jury which covered all of the claims and counterclaims in the
lawsuit. Based upon the jury's answers, the District Court entered judgement
granting plaintiffs' claims against the Company and its subsidiaries, as well as
CTPLP's counterclaim against the plaintiffs. The District Court issued an
amended judgement on September 5, 2001 which became final December 19, 2001. The
net amount awarded to the plaintiffs was approximately $2,700,000. The Company
and its subsidiaries have filed a notice of appeal with the Tyler Court of
Appeals and will continue to vigorously contest this matter.
-7-
Special counsel to the Company does not consider an unfavorable outcome
to this lawsuit probable. The Company's management and special 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. As a result, the Company has not accrued
any liability for this litigation. Nevertheless, to pursue the appeal, the
Company and its subsidiaries will be required to post a bond to cover the net
amount of damages awarded to the plaintiffs and to maintain that bond until the
resolution of the appeal (which may take several years). The Company has
included the letter of credit to support the bond, estimated at approximately
$3,000,000, in its line of credit with a major energy bank. See Note 21 to the
consolidated financial statements which are included in Item 8 to this Form
10-K.
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 named plaintiff agreed to settle
the case for a payment of $250,000 by the Company. As of December 27, 2001, the
Company had paid $259,000, representing the $250,000 settlement amount plus $
9,000 of interest, to the plaintiffs and their lawyers.
MGNG Litigation
On May 4, 1998, 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 $750,000 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.
In October 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
believed that they do not owe $772,000 and were entitled to legally 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's claims based partially on the right of offset.
-8-
In September 2000, the parties agreed to settle all lawsuits. Under the
terms of the settlement the amount claimed by MGNG under a gas supply contract
was reduced by $325,000 and the net amount payable to MGNG was set at $400,000
and the parties signed mutual releases. The Company paid MGNG $400,000 in
November 2001.
Pilgreen Litigation
As part of the AmBrit purchase, Castle Exploration Company, Inc.
("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, 2001, approximately
$415,000 attributable to CECI's share of the ORRI revenue was suspended. The
Company's policy is to recognize the suspended revenue only when and if it is
received.
-9-
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 2001.
-10-
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 three
fiscal years ended September 30, 2001.
2001 2000 1999
-------------- --------------- ---------------
High Low High Low High Low
---- --- ---- --- ---- ---
First Quarter (December 31)..................... $7.73 $5.92 $ 9.67 $5.50 $6.46 $5.63
Second Quarter (March 31)....................... $6.94 $5.60 $ 10.56 $4.81 $5.96 $5.25
Third Quarter (June 30)......................... $6.92 $5.67 $ 6.50 $4.63 $6.42 $5.00
Fourth Quarter (September 30)................... $6.47 $4.21 $ 7.75 $6.25 $6.08 $5.50
The final sale of the Company's Common Stock as reported by the NNM on
November 30, 2001 was at $5.87.
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 - including a covenant in the Company's letter of credit facility that
limits dividends to 50% of the Company's net income.
Approximate Number of Holders of Common Stock
As of November 30, 2001, 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, 2001, 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.
-11-
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, 2001. The information should be read in conjunction with the
Consolidated Financial Statements and notes thereto included in Item 8 of this
Form 10-K.
Earnings per share have been retroactively restated in accordance with
SFAS 128.
For the Fiscal Year Ended September 30,
------------------------------------------------------------------
(in Thousands, except per share amounts)
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Revenues:
Natural gas marketing and transmission........ $ 50,067 $ 70,001 $ 64,606
Exploration and production ................... $21,144 $ 17,959 7,190 2,603 7,113
Gross Margin:
Natural gas marketing and transmission ....... 19,005 26,747 24,640
Exploration and production ................... 13,745 11,765 4,802 1,828 5,173
Earnings before interest, taxes, depreciation, and
amortization and impairment of unproven
properties:
Natural gas marketing and transmission ..... 17,847 25,162 23,054
Exploration and production ................. 11,917 9,727 3,764 836 4,036
Corporate general and administrative expenses .... (4,169) (3,717) (4,112) (3,081) (3,370)
Depreciation, depletion and amortization and
impairment of unproven properties ............ (6,235) (4,041) (8,330) (9,885) (12,250)
Interest expense ................................. (2) (1,038)
Interest income and other income ................. 584 809 2,053 2,230 21,097(1)
-------- -------- -------- -------- --------
Income from continuing operations before income
taxes ........................................ 2,097 2,778 11,222 15,260 31,529
Provision for (benefit of) income taxes related to
continuing operations ........................ 381 (2,291) 2,956 1,204 4,663
-------- -------- -------- -------- --------
Net income ....................................... $ 1,716 $ 5,069 $ 8,266 $ 14,056 $ 26,866
======== ======== ======== ======== ========
Dividends ........................................ $ 1,322 $ 1,363 $ 2,048 $ 1,688 $ 1,446
======== ======== ======== ======== ========
Net income per share (diluted) ................... $ .25 $ .71 $ .99 $ 1.22 $ 1.55
======== ======== ======== ======== ========
Dividends per share .............................. $ .20 $ .20 $ .25 $ .15 $ .10
======== ======== ======== ======== ========
September 30,
-----------------------------------------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
Working capital ................................. $10,409 $22,304 $26,489 $40,271 $46,384
Property, plant and equipment, net, including oil
and gas properties ........................... 40,226 30,978 26,985 4,969 2,998
Total assets .................................... 59,118 63,295 60,796 67,004 82,717
Long-term debt, including current maturities
Stockholders' equity ............................ 51,027 54,276 53,503 51,553 67,765
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.
-12-
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 2,000,000
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 1999 and none of fiscal 2000 or fiscal 2001.
Fiscal 2001 vs Fiscal 2000
OIL AND GAS SALES
Oil and gas sales increased $3,185 or 17.7% from fiscal 2000 to fiscal
2001. An analysis of the increase is as follows:
Fiscal Year Ended September 30, Increase
2001 2000 (Decrease)
---- ---- ----------
Production (Net):
Barrels of crude oil .............................................. 262,000 279,000 (17,000)
Mcf of natural gas ................................................ 3,083,000 3,547,000 (464,000)
Equivalent net of natural gas ..................................... 4,655,000 5,221,000 (566,000)
Oil and Gas Sales:
Before hedging .................................................... $ 21,144 $ 19,487 $ 1,657
Effect of hedging ................................................. (1,528) 1,528
----------- ----------- -----------
Net of hedging .................................................... $ 21,144 $ 17,959 $ 3,185
=========== =========== ===========
Average Price/MCFE:
Before hedging ......................................................... $ 4.54 $ 3.73 $ .81
Effect of hedging ...................................................... (0.29) 0.29
----------- ----------- -----------
Net .................................................................... $ 4.54 $ 3.44 $ 1.10
=========== =========== ===========
Analysis of Increase:
Price (5,221,000 mcfe x $.81/mcfe) ..................................... $ 4,229
Volume (566,000 mcfe x $4.54/mcfe) ..................................... (2,570)
Decrease in hedging losses ............................................. 1,528
Rounding ............................................................... (2)
-----------
$ 3,185
===========
-13-
For the year ended September 30, 2001, the Company's net production
averaged 718 barrels of crude per day and 8,447 mcfe of natural gas per day
versus 764 barrels of crude oil per day and 9,718 mcf of natural gas per day for
the year ended September 30, 2000.
The decline in production volumes is primarily attributable to the
depletion of the Company's oil and gas reserves and the fact that all but one of
the exploratory wells drilled in fiscal 2000 and 2001 by the Company resulted in
dry holes rather than production. The decline in production would have been
greater by 467,000 mcfe had the Company not acquired twenty- one producing East
Texas properties in April 2001 (see Items 1 and 2 above).
At the present time, natural gas spot prices are averaging less than
$3.00/mcf - far less than the average price of $4.53/mcf for the year ended
September 30, 2001 and the record prices of $9.00/mcf received for some
production in January 2001. In addition, current crude prices are slightly below
$20.00 per barrel - significantly less than the average price of $27.39 received
by the Company for the year ended September 30, 2001. Since the Company has not
hedged its production and since most credible experts are not predicting
significant increases for oil and gas prices in the short term, the Company
expects that its oil and gas revenues will decrease significantly in fiscal 2002
unless the Company successfully drills or acquires new reserves and/or oil and
as prices increase significantly. If the Company consummates the intended sale
of its domestic oil and gas properties to Delta (see Items 1 and 2 above), oil
and gas price or volume increases will affect both operations until closing of
the sale and the ultimate purchase price the Company receives. Net cash flow
between October 1, 2001, the effective date, and the closing date, would be
retained by the Company but would reduce the purchase price paid by Delta.
Oil and gas production expenses increased $1,205 or 19.5% from fiscal
2000 to fiscal 2001. The increase is primarily attributable to the acquisition
of twenty-one (21) producing properties in East Texas in April 2001. For the
year ended September 30, 2001 oil and gas production expenses, net of income
from well operations, were $1.59 per equivalent mcf sold versus $1.19 per
equivalent mcf sold for the year ended September 30, 2000. The increase results
primarily from two factors. When oil and gas prices increased substantially in
the beginning of fiscal 2001, so did operating costs. Such operating costs,
however, did not decrease or decreased less than oil and gas prices when oil and
gas prices receded sharply later in the fiscal year. 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 and the resultant lack of
reserves added by new drilling. 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 decreased $210 or 10.3% from fiscal
2000 to fiscal 2001. The decrease is primarily attributable to transferring some
costs associated with the Company's Oklahoma City office to corporate, general
and administrative costs and decreased consulting costs. Also, see "Corporate
General and Administrative Expenses" below.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization increased $261 on 8.1% from
fiscal 2000 to fiscal 2001. The components of depreciation, depletion and
amortization were as follows:
Year Ended September 30,
Increase
2001 2000 (Decrease)
---- ---- --------
Depreciation and amortization of furniture and fixtures and equipment...... $ 122 $ 219 ($ 97)
Depreciation, depletion and amortization of oil and gas properties......... 3,348 2,990 358
------- ------- ----
$ 3,470 $ 3,209 $261
======= ======= ====
Depreciation and amortization of furniture and fixtures and equipment
decreased $97 from fiscal 2000 to fiscal 2001 primarily because certain
furniture and fixture assets and vehicles were fully depreciated in fiscal 2000.
For the year ended September 30, 2001, the depletion rate per equivalent
mcf was $.72 in fiscal 2001 versus $.57 in fiscal 2000. The increase resulted
primarily from two factors. First, in April 2001, the Company acquired
twenty-one (21) East Texas wells at a higher cost per equivalent mcfe of
reserves than that for the Company's existing reserves, causing the Company's
average cost per mcfe of reserves to increase. Second, the depletion rate
increased significantly because of significantly lower reserves at September 30,
2001 compared to those at September 30, 2000. Reserves decreased primarily
because of much lower oil and gas prices at September 30, 2001 compared to
September 30, 2000. The lower reserves and higher costs at September 30, 2001
caused the depletion rate to increase.
-14-
IMPAIRMENT OF UNPROVED PROPERTIES
The impairment reserve for unproved properties increased $1,933 from
fiscal 2000 to fiscal 2001. To date, the Company has spent $3,597 participating
in the drilling of five dry holes or uneconomical wells on three concessions in
Romania and $110 with respect to the planned drilling of a sixth wildcat well in
the Black Sea on a second phase of one concession. In fiscal 2000, the Company
recorded an $832 reserve related to one drilling concession. The $2,765 reserve
incurred in 2001 relates to the other two drilling concessions. At September 30,
2001, impairment reserves have been provided for all costs incurred in Romania
except the $110 applicable to the planned sixth well in the Black Sea (see Note
4 to the Consolidated Financial Statements included in Item 8 of this Form
10-K).
CORPORATE GENERAL AND ADMINISTRATIVE EXPENSES
Corporate, general and administrative expenses increased $452 or 12.2%
from fiscal 2000 to fiscal 2001. The increase is primarily attributable to legal
costs related to the Long Trusts Litigation and the Texaco claim and $181
related to the Company's effort to sell its oil and gas properties earlier in
the fiscal year.
OTHER INCOME (EXPENSE)
Interest income decreased $143 or 18.2% from fiscal 2000 to fiscal 2001.
The decrease is primarily attributable to a decrease in the average balance of
cash invested during the periods being compared and to a decrease in the
interest rate received by the Company on invested funds.
The composition of other income (expense) for the years ended September
30, 2001 and 2000 is as follows:
Year Ended September 30,
2001 2000
---- ----
Litigation recovery (costs)........................................................... ($45)
Miscellaneous......................................................................... $42 70
--- ---
$42 $25
=== ===
PROVISION FOR INCOME TAXES
The tax provisions (benefit) for the years ended September 30, 2001 and
2000 consist of the following components:
Year Ended September 30,
2001 2000
---- ----
1. Decrease in net deferred tax asset using 36% Federal and state blended
tax rate..................................................................... $808 $ 948
2. Change in valuation allowance................................................ (431) (3,204)
4. Other (primarily revisions of previous estimates)............................ 4 (35)
---- ------
$381 ($2,291)
==== ======
The tax provision for the year ended September 30, 2001 consists
primarily of deferred taxes of $808 related to timing differences originating in
fiscal 2001 and a decrease of $431 in the valuation allowance from fiscal 2000.
The decrease in the valuation allowance resulted because the Company determined
that a portion of the deferred tax asset would more likely than not be realized
based upon estimates of future taxable income and upon the projected taxable
income resulting from the anticipated sale of its oil and gas assets to Delta
and, accordingly, decreased the valuation allowance by $431 to $3,559.
-15-
If recent decreases in oil and gas prices continue and if the sale of
the Company's oil and gas assets to Delta is not consummated, the Company may be
required to increase its valuation allowance.
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 would 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.
EARNINGS PER SHARE
Since November 1996, the Company has repurchased 4,871,020 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.
Fiscal 2000 vs Fiscal 1999
OIL AND GAS SALES
Oil and gas sales increased $11,247 or 167.6% from fiscal 1999 to fiscal
2000. An analysis of the increase is as follows:
Year Ended September 30,
-------------------------------------
2000 1999 Increase
---- ---- --------
Production (Net):
Barrels 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
========= ========= =========
An analysis of the increase in oil and gas sales is as follows:
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.
-16-
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 Energy Corp. ("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.
DEPRECIATION, DEPLETION AND AMORTIZATION
Depreciation, depletion and amortization increased $1,163 or 56.8% from
fiscal 1999 to fiscal 2000. The components of depreciation, depletion and
amortization were as follows:
Year Ended September 30,
---------------------------------
2000 1999 Increase
---- ---- --------
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
======= ======= =======
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.
-17-
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 onshore 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.
The composition of other income (expense) for the years ended September
30, 2000 and 1999 is as follows:
Year Ended September 30,
-----------------------
2000 1999
---- ----
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
==== ====
PROVISION FOR INCOME TAXES
The tax provision (benefit) for the years ended September 30, 2000 and
1999 consist of the following components:
Year Ended September 30,
2000 1999
---- ----
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
====== ======
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.
-18-
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.
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, 2001, the Company generated $11,884
from operating activities. During the same period the Company invested $15,449
in oil and gas properties and $572 to reacquire shares of its common stock. In
addition, it paid $1,326 in stockholder dividends. At September 30, 2001, the
Company had $5,844 of unrestricted cash, $10,409 of working capital and no
long-term debt.
Discontinued Refining Operations
Although the Company's former and present subsidiaries have exited the
refining business and third parties have assumed environmental liabilities, if
any, of such subsidiaries, the Company and several of its subsidiaries remain
liable for contingent environmental liabilities (see Item 3 and Note 12 to the
consolidated financial statements included in Item 8 of this Form 10-K).
As noted previously, the Company entered into a letter of intent to sell
all of its domestic oil and gas properties to Delta. Closing of the transaction
is anticipated between March 31, 2002 and June 30, 2002. The Company's expected
uses and sources of funds assuming this transaction closes on April 30, 2002 are
as follows:
Expected Uses of Funds
----------------------
Funds to support bond for appeal of verdict in Long Trusts Lawsuit..................... $3,000
Reduction of trade payables............................................................ 1,025
Estimated drilling costs for wildcat in Black Sea (excludes completion costs if well
successful)......................................................................... 1,000
Dividends to shareholders.............................................................. 990
Recompletions and reworks on existing wells............................................ 600
--------
$6,615
========
If sufficient funds are available, the Company may also consider an
additional investment in Networked. The Company does not expect to undertake any
significant developmental drilling since it has entered into a letter of intent
to sell its oil and gas properties to Delta for a fixed price (see Items 1 and 2
above) effective October 1, 2001. The Company may also continue to repurchase
its shares if funds are available.
-19-
Expected Sources of Funds
-------------------------
Proceeds of sale of oil/gas properties to Delta at closing............................ $15,500
Unrestricted cash - September 30, 2001................................................ 5,844
Letter of credit portion of credit facility........................................... 3,000
---------
$24,344
=========
The Company expects only marginally positive cash flow from operations
during the period from October 1, 2001 to April 30, 2002 given current low oil
and gas prices. If such prices increase, the Company may be able to fund some of
its expected expenditures from cash flow from oil and gas operations.
Conversely, the Company could experience negative cash flow from oil and gas
operations if oil and gas prices decrease from present levels.
In addition, the Company owns marketable securities which had a market
value (also book value) of $6,722 at September 30, 2001 and the Company could
liquidate these and use the proceeds to fund planned expenditures if needed.
Most of the marketable securities owned by the Company, however, are the common
stocks of Delta (382,289 shares) and Penn Octane Corporation ("Penn Octane"), a
small public company involved in the sale of liquid propane gas in Mexico
(1,343,600 shares). Both of these companies are thinly traded and volatile and
the Company may, therefore, not be able to liquidate its shares in Delta and
Penn Octane at recorded values - especially if such shares must be liquidated
quickly in the market.
If the sale to Delta is consummated as planned, the Company will also
receive 9,566,000 shares of Delta common stock.
The closing of the sale of the Company's domestic oil and gas properties
to Delta is subject to numerous conditions, including execution of a definitive
agreement by December 31, 2001, approval of the sale by the Company's and
Delta's boards of directors and approval by Delta's shareholders. Accordingly,
there can be no assurance that the contemplated sale will close or that it will
close when anticipated. In addition, economic conditions could change between
the present time and closing and either Delta or the Company may not conclude
the transaction, although the party failing to close could be subject to
significant penalties pursuant to the terms of the letter of intent.
If the Delta transaction does not close, the Company's expected uses and
sources of funds for the period October 1, 2001 to September 30, 2002 are
approximately as follows:
Expected Uses of Funds
----------------------
Developmental drilling.................................................................... $ 5,286
Funds to support bond for appeal of verdict in Long Trusts lawsuit........................ 3,000
Reduction of trade payables............................................................... 1,025
Estimated drilling costs for wildcat well in the Black Sea................................ 1,000
Recompletions and reworks on existing wells............................................... 600
Dividends to shareholders................................................................. 1,320
---------
$ 12,231
=========
As noted above, the Company may also consider additional investments in
Networked and further repurchase of its shares if sufficient cash is available.
In addition, the Company may consider acquisitions of other properties or
exploration and production companies, as it has in the past.
Expected Sources of Funds
-------------------------
Unrestricted cash - September 30, 2001.................................................... $ 5,844
Letter of credit portion of credit facility............................................... 3,000
Expected minimum cash available for drilling under credit facility ($12,500-$3,000
letter of credit)...................................................................... 9,500
--------
$ 18,344
========
The amount that can be borrowed under the Company's line of credit will
be determined by the energy bank making the loan based upon its parameters and
will probably change based upon past production, changes in oil and gas prices
and other factors.
-20-
In addition, the same comments, as above, apply concerning the Company's
possible use of its marketable securities or cash flow from operations to fund
expected expenditures.
The Company's future operations are subject to the following risks:
a. Failure of Delta Transaction to Close
-------------------------------------
There are several reasons why the Delta transaction may not
ultimately close - including but not limited to failure of the
parties to enter into a definitive purchase and sale agreement,
failure to approve the transaction by the boards of directors of
Delta and/or the Company or both, failure of the Delta shareholders
to approve the transaction and failure of either party to consummate
the transaction. In addition, the Securities and Exchange Commission
may review Delta's proxy to its shareholders and such review may
delay closing.
If the transaction does not close the Company may miss drilling or
acquisition opportunities and may suffer the loss of key employees -
thus impeding its future operations. The Company has only thirty
employees. It cannot simply switch gears from a divestiture mode to
an acquisition mode without major disruption to its operations as
can much larger exploration and production companies. The Company
may find it difficult to retain key employees given that it has
formally put its assets up for sale twice in the last year. Loss of
key employees could negatively impact the Company's ability to meet
the myriad of accounting and regulatory requirements to which the
Company is subject as a public company.
b. 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 claimed 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 was initially 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 from 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 had 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's management and special counsel subsequently
met and continue to discuss Texaco's claims with representatives of
Chevron/Texaco but the parties disagree concerning the validity of
Texaco's claims. 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.
-21-
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 and a
recent decision by a U.S. Appeal Court for the Fifth Circuit support
the Company's positions.
The above estimate of expected cash resources and cash uses assumes
no expenditure for contingent environmental liabilities or legal
defense costs related to the Indian Refinery. If the Company is sued
and related legal proceedings continue longer than expected
(environmental litigation often continues 3-5 years or more) and/or
the Company is found liable for a portion of the environmental
remediation of either the Indian Refinery or Powerine Refinery,
estimated cash uses will be increased and such increase could be
significant.
c. 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. IRLP has agreed to settle its $5,388 note for $612
in exchange for a covenant of the EPA not to sue IRLP. These
provisions are included in the Plan of Liquidation of American
Western which American Western expects to be confirmed in January
2002. Assuming American Western's Plan of Liquidation is confirmed,
IRLP will be able to pay its creditors only a small portion of the
amounts owed to them.
d. 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 4,871,020 shares or 69% of its outstanding common stock
since November of 1996 and was the major market maker in the
Company's stock for much of the period. If the Company ceases
repurchasing shares, the market value of the Company's stock may be
adversely affected.
e. Foreign Operating Risks
-----------------------
As of September 30, 2001, the Company had incurred $3,597 drilling
five wildcat wells (resulting in dry holes or uneconomic wells) on
three Romanian concessions. The Company plans to drill a sixth
wildcat well in the Black Sea in the spring or early summer of 2002.
The Company's Romanian operations 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.
f. Exploration and Production Reserve Risk
---------------------------------------
The Company plans to participate in the drilling of a sixth Romanian
wildcat well in the Black Sea whether or not it closes the sale of
its domestic properties to Delta (see page 2). The planned wildcat
well in the Black Sea involves high risk wildcat drilling where the
probability of discovering commercial oil and gas reserves is less
than twenty percent (20%). If the sale to Delta or a similar sale
does not occur, the Company may also participate in the drilling of
several domestic development wells and recompletions of existing
wells to other producing zones. Drilling investments are essentially
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 or
not found in the quantities anticipated, the Company's future
operations and cash flow will be adversely affected and the Company
could be required to record an impairment provision for its oil and
gas properties pursuant to the full cost accounting method. (See
Note 2 to the financial statements included as Item 8 to this Form
10-K).
-22-
g. Exploration and Production Price Risk
-------------------------------------
The Company did not hedge any of its anticipated future oil and gas
production because the cost to do so appeared 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 January 2001 to November 2001, crude oil prices
decreased approximately 25% and natural gas prices decreased
approximately 65%. Current oil and gas prices are low and are
generally not predicted to increase appreciably over the next 2-4
years. In the past crude oil prices and gas prices have shown
general volatility over short periods of time and it is possible
that prices could change significantly and suddenly as they have in
the past.
The Company follows the full-cost method of accounting for oil and
gas properties and equipment costs. Under this method of accounting
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 expense (full cost ceiling test). If at a future
reporting date oil and gas prices decline below the prices used to
perform the full cost ceiling test at September 30, 2001, the
Company estimates that it would likely incur a charge to expense.
h. Exploration and Production Operating Risk
-----------------------------------------
All of the Company's current oil and gas properties are onshore
properties with relatively low operating risk. Nevertheless, the
Company faces the risks encountered from operating over 250 oil and
gas wells in several states - including the risks of oil and gas
spills, resulting environmental damage, third party liability claims
related to operations, including claims by landowners where the
operated wells are located, and general operating risks.
i. 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.
j. Future of the Company
---------------------
In the last three years the regulatory burdens and related costs of
being a public company have increased significantly. New
requirements have been added by the Securities and Exchange
Commission, the Nasdaq stock market and the Financial Accounting
Standards Board at an accelerated pace including but not limited to
requiring reviews of quarterly financial statements, increased Audit
Committee procedures and protocol and compliance with new accounting
and disclosure requirements. This has resulted in increased fees
paid by the Company and diversion of management's efforts. In short,
the Company's current level of operations are not sufficiently large
to bear the Company's current general and administrative burden. In
addition, the Company's high oil and gas production expense burden
is at least partially attributable to the fact that the Company's
fixed production costs are not spread over a larger number of and
more productive oil and gas wells. As a result of these and other
factors, the Company has not only aggressively sought to acquire
properties to achieve a critical mass over which to apply its
general and administrative expenses but has also sought to sell it
properties when the conditions appeared most favorable. Although the
Company has purchased approximately $34,000 of producing properties
in the last three years, it has still not achieved the critical mass
necessary to support its general and administrative burden.
As noted earlier, the Company has entered into a letter of intent to
sell all of its domestic oil and gas properties to Delta on terms
the Company's management consider favorable. The Company's
management considers such a transaction prudent given the
uncertainty of oil and gas prices and the significant costs to
operate a public company. If the Delta transaction fails to close as
planned, the Company expects to continue to seek similar
transactions on similar or better terms. The Company may also seek a
merger with another company although to date the claims made by
Texaco against the Company have hindered this process. Nevertheless,
there can be no assurance that the Company will be able to succeed
in this endeavor and the Company's management and board of directors
may decide to continue to seek future acquisitions in the oil and
gas sector when conditions are favorable and to attain the needed
critical mass in that manner.
-23-
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. Oil and gas prices are currently much lower than
they have been in several months and many forecasters are anticipating continued
lower oil and gas prices for several years. There can be, however, no assurance
that such prices will increase in the future or even remain at current 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 No. 133"),
was issued by the Financial Accounting Standards Board in June 1998.
Subsequently, SFAS No. 138 "Accounting for Certain Derivative Instruments"
("SFAS No. 138"), an amendment of SFAS No. 133, was issued. SFAS 133 and SFAS
138 standardize 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 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 No. 133 and SFAS No. 138 effective October 1, 2000. The Company ceased
hedging its oil and gas production in July 2000. At September 30, 2001 and 2000,
the Company had no freestanding derivative instruments in place and had no
embedded derivative instruments. As a result, the Company's adoption of SFAS No.
133 and SFAS No. 138 had no impact on its results of operations or financial
condition.
Statement of Financial Accounting Standards No. 141, "Business
Combinations" ("SFAS No. 141") and Statement of Financial Accounting Standards
No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142") were issued in
July 2001. SFAS No. 141 requires that all business combinations entered into
subsequent to June 30, 2001 be accounted for under the purchase method of
accounting and that certain acquired intangible assets in a business combination
be recognized and reported as assets apart from goodwill. SFAS No. 142 requires
that amortization of goodwill be replaced with periodic tests of the goodwill's
impairment at least annually in accordance with the provisions of SFAS No. 142
and that intangible assets other than goodwill be amortized over their useful
lives. The Company adopted SFAS No. 141 in July 2001 and will adopt SFAS No. 142
in the first quarter of fiscal 2003. The Company does not believe that its
future adoption of SFAS No. 142 will have a material effect on its results of
operations.
In June 2001, the FASB issued Statement No. 143, "Accounting for Asset
Retirement Obligations" ("SFAS No. 143"), which provides accounting requirements
for retirement obligations associated with tangible long-lived assets,
including: 1) the timing of liability recognition; 2) initial measurement of the
liability; 3) allocation of asset retirement cost to expense; 4) subsequent
measurement of the liability; and 5) financial statement disclosures. SFAS No.
143 requires that asset retirement cost be capitalized as part of the cost of
the related long-lived asset and subsequently allocated to expense using a
systematic and rational method. Any transition adjustment resulting from the
adoption of SFAS No. 143 would be reported as a cumulative effect of a change in
accounting principle. The Company will adopt the statement effective October 1,
2002. At this time, the Company cannot reasonably estimate the effect of the
adoption of this statement on either its financial position or results of
operations.
-24-
In August 2001, the FASB issued Statement No. 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"), which will be
effective for financial statements issued for fiscal years beginning after
December 15, 2001 and interim periods within those fiscal years. SFAS No. 144
requires that long-lived assets to be disposed of by sale be measured at the
lower of the carrying amount or fair value less cost to sell, whether reported
in continuing operations or in discontinued operations. SFAS No. 144 broadens
the reporting of discontinued operations to include all components of an entity
with operations that can be distinguished from the rest of the entity and that
will be eliminated from the ongoing operations of the entity in a disposal
transaction. After its effective date, SFAS No. 144 will be applied to those
transactions where appropriate. The Company will adopt SFAS No 144 effective
October 1, 2002. At this time the Company is unable to determine what the future
impact of adopting this statement will have on its financial position or results
of operations.
-24-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
----
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Statements of Operations for the Years Ended September 30, 2001, 2000 and 1999................. 27
Consolidated Balance Sheets as of September 30, 2001 and 2000............................................... 28
Consolidated Statements of Cash Flows for the Years Ended September 30, 2001, 2000 and 1999................. 29
Consolidated Statements of Stockholders' Equity and Other Comprehensive Income for the Years
Ended September 30, 2001, 2000 and 1999............................................................. 31
Notes to the Consolidated Financial Statements.............................................................. 32
INDEPENDENT AUDITORS' REPORT................................................................................ 58
All other schedules are omitted because they are not applicable or the
required information is shown in the financial statements or notes thereto.
-26-
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
("$000's" Omitted Except Share and Per Share Amounts)
Year Ended September 30,
----------------------------------------
2001 2000 1999
---- ---- ----
Revenues:
Natural gas marketing and transmission:
Gas sales.............................................. $ 50,067
Exploration and production:
Oil and gas sales...................................... $ 21,144 $ 17,959 6,712
---------- --------- -----------
21,144 17,959 56,779
---------- --------- -----------
Expenses:
Natural gas marketing and transmission:
Gas purchases.......................................... 31,062
General and administrative............................. 35
Transportation......................................... 1,123
Depreciation and amortization.......................... 6,284
-----------
38,504
-----------
Exploration and production:
Oil and gas production................................. 7,399 6,194 1,910
General and administrative............................. 1,828 2,038 1,038
Depreciation, depletion and amortization............... 3,470 3,209 2,046
Impairment of foreign unproved properties.............. 2,765 832
---------- --------- -----------
15,462 12,273 4,994
---------- --------- -----------
Corporate general and administrative..................... 4,169 3,717 4,112
---------- --------- -----------
19,631 15,990 47,610
---------- --------- -----------
Operating income............................................. 1,513 1,969 9,169
---------- --------- -----------
Other income (expense):
Interest income.......................................... 641 784 1,701
Other income............................................. 42 25 352
Equity in loss of Networked Energy LLC................... (99)
---------- --------- -----------
584 809 2,053
---------- --------- -----------
Income before provision for (benefit of) income taxes....... 2,097 2,778 11,222
---------- --------- -----------
Provision for (benefit of) income taxes:
State.................................................... 11 (64) 79
Federal.................................................. 370 (2,227) 2,877
---------- --------- -----------
381 (2,291) 2,956
---------- --------- -----------
Net income................................................... $ 1,716 $ 5,069 $ 8,266
========== ========= ===========
Net income per share:
Basic.................................................... $ .26 $ .73 $ 1.01
========== ========= ===========
Diluted.................................................. $ .25 $ .71 $ .99
========== ========= ===========
Weighted average number of common and potential dilutive
shares outstanding:
Basic 6,643,724 6,939,350 8,205,501
========== ========== ==========
Diluted.............................................. 6,818,855 7,102,803 8,347,932
========== ========== ==========
The accompanying notes are an integral part of these
consolidated financial statements
-27-
CASTLE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
("$000's" Omitted Except Share and Per Share Amounts)
September 30,
-----------------------------
2001 2000
---- ----
ASSETS
Current assets:
Cash and cash equivalents ................................................... $ 5,844 $ 11,525
Restricted cash ............................................................. 370 1,742
Accounts receivable ......................................................... 2,787 3,758
Marketable securities ....................................................... 6,722 10,985
Prepaid expenses and other current assets ................................... 277 251
Estimated realizable value of discontinued net refining assets .............. 612 800
Deferred income taxes ....................................................... 1,879 2,256
--------- ---------
Total current assets ...................................................... 18,491 31,317
Property, plant and equipment, net:
Natural gas transmission .................................................... 51 55
Furniture, fixtures and equipment ........................................... 222 258
Oil and gas properties, net (full cost method):
Proved properties ......................................................... 39,843 29,218
Unproved properties not being amortized ................................... 110 1,447
Investment in Network Energy LLC ................................................ 401 500
Note receivable - Penn Octane Corporation ....................................... 500
--------- ---------
Total assets .............................................................. $ 59,118 $ 63,295
========= =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Dividend payable ............................................................ $ 331 $ 333
Accounts payable ............................................................ 3,543 2,433
Accrued expenses ............................................................ 292 265
Accrued taxes on appreciation of marketable securities ...................... 900 2,628
Stock subscription payable .................................................. 150
Net refining liabilities retained ........................................... 3,016 3,204
--------- ---------
Total current liabilities ................................................. 8,082 9,013
Long-term liabilities ........................................................... 9 6
--------- ---------
Total liabilities ......................................................... 8,091 9,019
--------- ---------
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, 2001 and 2000 ................... 5,752 5,752
Additional paid-in capital .................................................. 67,365 67,365
Accumulated other comprehensive income - unrealized gains on marketable
securities, net of taxes .................................................. 1,600 4,671
Retained earnings ........................................................... 42,816 42,422
--------- ---------
117,533 120,210
Treasury stock at cost - 4,871,020 shares at September 30, 2001 and 4,791,020
shares at September 30, 2000 .............................................. (66,506) (65,934)
--------- ---------
Total stockholders' equity ................................................ 51,027 54,276
--------- ---------
Total liabilities and stockholders' equity ................................ $ 59,118 $ 63,295
========= =========
The accompanying notes are an integral part of these
consolidated financial statements
-28-
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
("$000's" Omitted Except Share and Per Share Amounts)
Year Ended September 30,
2001 2000 1999
---- ---- ----
Cash flows from operating activities:
Net income ........................................................... $ 1,716 $ 5,069 $ 8,266
-------- -------- --------
Adjustments to reconcile net income to cash provided by operating
activities:
Depreciation, depletion and amortization .......................... 3,470 3,209 8,330
Impairment of foreign unproved properties ......................... 2,765 832
Deferred income taxes (benefit) ................................... 377 (2,256) 2,765
Unrealized gain on marketable securities .......................... (481)
Impairment of Penn Octane preferred stock ......................... 423
Equity in loss of Networked Energy LLC ............................ 99
Changes in assets and liabilities:
(Increase) decrease in restricted cash ......................... 1,372 (972) (157)
Decrease in accounts receivable ................................ 971 1,414 3,209
Decrease in prepaid transportation ............................. 1,123
(Increase) decrease in prepaid expenses and other current assets (26) 343 (301)
Decrease in other assets ....................................... 29
Decrease in prepaid gas purchases .............................. 852
Increase (decrease) in accounts payable ........................ 1,110 (436) (5,740)
Increase (decrease) in accrued expenses ........................ 27 (537) (861)
Increase in other long-term liabilities ........................ 3 6
-------- -------- --------
Total adjustments .......................................... 10,168 1,632 9,162
-------- -------- --------
Net cash flow provided by operating activities ............. 11,884 6,701 17,428
-------- -------- --------
Cash flows from investment activities:
Investment in note receivable - Penn Octane Corporation .............. (500)
Investment in marketable securities .................................. (34) (269)
Proceeds from sale of oil and gas assets ............................. 48 1,427
Realization from (liquidation of) discontinued net refining assets ... 900
Acquisition of AmBrit oil and gas properties ......................... (20,170)
Investment in other oil and gas properties ........................... (15,449) (11,226) (3,794)
Investment in Networked Energy LLC ................................... (150) (350)
Purchase of furniture, fixtures and equipment ........................ (82) (173) (98)
Other ................................................................ (35)
-------- -------- --------
Net cash used in investing activities ...................... (15,667) (10,857) (23,431)
-------- -------- --------
(continued on next page)
The accompanying notes are an integral part of these
consolidated financial statements
-29-
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
("$000's" Omitted)
(continued from previous page)
Year Ended September 30,
2001 2000 1999
---- ---- ----
Cash flows from financing activities:
Acquisition of treasury stock ............................................ (572) (5,208) (6,919)
Dividends paid to stockholders ........................................... (1,326) (1,363) (1,681)
Proceeds from exercise of stock options .................................. 255
-------- -------- --------
Net cash (used in) financing activities ............................ (1,898) (6,571) (8,345)
-------- -------- --------
Net (decrease) in cash and cash equivalents ................................. (5,681) (10,727) (14,348)
Cash and cash equivalents - beginning of period ............................. 11,525 22,252 36,600
-------- -------- --------
Cash and cash equivalents - end of period ................................... $ 5,844 $ 11,525 $ 22,252
======== ======== ========
Supplemental disclosures of cash flow information are as follows:
Cash paid during the period:
Income taxes .......................................................... $ 11 $ 188 $ 108
======== ======== ========
Accrued dividends ........................................................ $ 331 $ 333 $ 368
======== ======== ========
Conversion of Penn Octane Corporation note and accrued interest receivable
to marketable securities .............................................. $ 521 $ 1,000
======== ========
Unrealized gain (loss) on investment in available-for-sale marketable
securities ........................................................... ($ 3,071) $ 2,275 $ 2,396
======== ======== ========
Exchange of oil/gas properties for Delta Petroleum Company common
stock ................................................................. $ 1,937
========
The accompanying notes are an integral part of these
consolidated financial statements
-30-
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
AND OTHER COMPREHENSIVE INCOME
("$000's" Omitted Except Per Share Amounts)
Years Ended September 30, 2001, 2000 and 1999
------------------------------------------------------------------------------
Accumulated
Common Stock Additional Other
--------------------- Paid-In Comprehensive Comprehensive Retained
Shares Amount Capital Income Income (Loss) Earnings
------ ------ ----------- ------------- ------------- ---------
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 (loss) on
marketable securities, net of tax 2,396 $2,396
-------
$10,662
=======
---------- ------ ------- ------ -------
Balance - September 30, 1999.... 6,828,646 3,414 67,365 2,396 41,054
Stock split ratio retroactively applied 4,675,258 2,338 (2,338)
---------- ------ ------- ------ -------
Balance-September 30, 1999 - restated 11,503,904 5,752 67,365 2,396 38,716
Stock acquired..................
Dividends declared ($.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
Stock acquired..................
Dividends declared ($.20 per share) (1,322)
Comprehensive income............
Net income.................... $1,716 1,716
Other comprehensive income (loss):
Unrealized gain (loss) on
marketable securities, net of tax (3,071) (3,071)
-------
($1,355)
=======
---------- ------ ------- ------ -------
Balance - September 30, 2001.... 11,503,904 $5,752 $67,365 $1,600 $42,816
========== ====== ======= ====== =======
[RESTUBBED TABLE]
Years Ended September 30, 2001, 2000 and 1999
---------------------------------------------
Treasury Stock
---------------------
Shares Amount Total
------ ------ -------
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 (loss) on
marketable securities, net of tax 2,396
--------- ------- -------
Balance - September 30, 1999.... 4,282,217 (60,726) 53,503
Stock split ratio retroactively applied
--------- ------- -------
Balance-September 30, 1999 - restated 4,282,217 (60,726) 53,503
Stock acquired.................. 508,803 (5,208) (5,208)
Dividends declared ($.20 per share) (1,363)
Comprehensive income............
Net income.................... 5,069
Other comprehensive income:...
Unrealized gain on marketable
securities, net of tax..... 2,275
--------- ------- -------
Balance - September 30, 2000.... 4,791,020 (65,934) 54,276
Stock acquired.................. 80,000 (572) (572)
Dividends declared ($.20 per share) (1,322)
Comprehensive income............
Net income.................... 1,716
Other comprehensive income (loss):
Unrealized gain (loss) on
marketable securities, net of tax (3,071)
--------- ------- -------
Balance - September 30, 2001.... 4,871,020 ($66,506) $51,027
========= ======= =======
The accompanying notes are an integral part of these
consolidated financial statements
-31-
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, 2001.
The Company's only line of business at September 30, 2001 and at present
is oil and gas exploration and production. The Company's operations are
conducted in the United States and 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 applicable to the Company's natural gas marketing business expired by
their terms on May 31, 1999.
On December 11, 2001, the Company entered into a letter of intent to
sell all of its domestic oil and gas properties to another public oil and gas
exploration company. See Note 21.
References to the Company mean Castle Energy Corporation, the parent,
and/or one or more of its subsidiaries. Such references are used for convenience
and are not intended to describe legal relationships.
Oil and Gas Exploration and Production
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 2,000,000 barrels of
crude oil or approximately one hundred and fifty percent (150%) of the Company's
proved reserves before such acquisition. See Note 4.
During fiscal 2000, the Company participated in the drilling of nine
exploratory wells in south Texas pursuant to two drilling ventures with other
exploration and production companies. Eight of the wells drilled resulted in dry
holes while the ninth well was completed as a producing well. During fiscal
2000 and 2001, the Company participated in the drilling of five wildcat
wells in Romania. Four of the wells drilled resulted in dry holes. The fifth
well produced some volumes of natural gas when tested. The Company considered
participating in a four well drilling program offsetting the fifth well but has
currently decided not to do so because of the current low prices obtainable for
production and the potential costs of constructing a pipeline to transport
production to potential purchasers. The Company has also agreed to participate
in the drilling of a sixth well in the Black Sea in the spring or early summer
of 2002. 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.
In April 2001, the Company consummated the purchase of twenty-one (21)
operated producing East Texas oil and gas properties from a private company.
See Note 4.
-32-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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.
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 has
substantially dismantled it. American Western subsequently filed a Plan of
Liquidation which it expects to be confirmed by the governing bankruptcy court
in January 2002. If the Plan is confirmed, IRLP expects to receive $612 which it
would then distribute to its vendors.
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"), an unaffiliated entity, and EMC acquired the refinery
from Kenyen. EMC subsequently sold the refinery to an outside party which, we
are informed, continues to seek 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
membership interests 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, 2001, 2000 and 1999 - natural gas marketing and
transmission and exploration and production. References should be made to
previous Forms 10-K for summaries of accounting principles applicable to the
discontinued refining segment.
-32-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
Principles of Consolidation
The consolidated financial statements presented include the accounts of
the Company and all of its subsidiaries. All 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.
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 the related 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 lives 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.
-34-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
Oil and Gas Properties
The Company follows the full-cost method of accounting for oil and gas
properties and equipment costs. Under this method of accounting, all productive
and nonproductive costs incurred in the acquisition, exploration and development
of oil and gas reserves are capitalized. Capitalized costs are amortized on a
composite unit-of-production method by country using estimates of proved
reserves. Capitalized costs which relate to unevaluated oil and gas properties
are not amortized until proved reserves are associated with such costs or
impairment of the related property occurs. Management and drilling fees earned
in connection with the transfer of oil and gas properties to a joint venture and
proceeds from the sale of oil and gas properties are recorded as reductions in
capitalized costs unless such sales are material and involve a significant
change in the relationship between the cost and the value of the remaining
proved reserves, in which case a gain or loss is recognized. Expenditures for
repairs and maintenance of wellhead equipment are expensed as incurred. Net
capitalized costs, less related deferred income taxes, in excess of the present
value of net future cash inflows (oil and gas sales less production expenses)
from proved reserves, tax-effected and discounted at 10%, and the cost of
properties not being amortized, if any, are charged to current expense.
Amortization and excess capitalized costs, if any, are computed separately for
the Company's investment in Romania.
Environmental Costs
The Company is subject to extensive federal, state and local
environmental laws and regulations. These laws, which are constantly changing,
regulate the discharge of materials into the environment and may require the
Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites. Environmental
expenditures are expensed or capitalized depending on their future expected
economic benefit to the Company. 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 circumstances 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 was highly correlated with the
corresponding change in the hedged item. When the hedging instrument ceased to
qualify as a hedge, changes in fair value were charged against or credited to
earnings.
-35-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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 during the periods
reported.
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 distributions, if any, are recorded as reductions
in the carrying value of the Company's investment.
The Company's investment in Network exceeded the fair value of the
Company's share of Network's assets by $350. Such excess (goodwill) is being
amortized on a straight-line method over forty (40) years.
Comprehensive Income
Comprehensive income includes net income and all changes in an
enterprise's other comprehensive income including, among other things,
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 and 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 allowance
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.
-36-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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 No. 133"),
was issued by the Financial Accounting Standards Board in June 1998.
Subsequently, SFAS No. 138 "Accounting for Certain Derivative Instruments"
("SFAS No. 138"), an amendment of SFAS No. 133, was issued. SFAS 133 and SFAS
138 standardize 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 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 No. 133 and SFAS No. 138 effective October 1, 2000. The Company ceased
hedging its oil and gas production in July 2000. At September 30, 2001 and 2000,
the Company had no freestanding derivative instruments in place and had no
embedded derivative instruments. As a result, the Company's adoption of SFAS No.
133 and SFAS No. 138 had no impact on its results of operations or financial
condition.
Statement of Financial Accounting Standards No. 141, "Business
Combinations" ("SFAS No. 141") and Statement of Financial Accounting Standards
No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142") were issued in
July 2001. SFAS No. 141 requires that all business combinations entered into
subsequent to June 30, 2001 be accounted for under the purchase method of
accounting and that certain acquired intangible assets in a business combination
be recognized and reported as assets apart from goodwill. SFAS No. 142 requires
that amortization of goodwill be replaced with periodic tests of the goodwill's
impairment at least annually in accordance with the provisions of SFAS No. 142
and that intangible assets other than goodwill be amortized over their useful
lives. The Company adopted SFAS No. 141 in July 2001 and will adopt SFAS No. 142
in the first quarter of fiscal 2003. The Company does not believe that its
future adoption of SFAS No. 142 will have a material effect on its results of
operations.
In June 2001, the FASB issued Statement No. 143, "Accounting for Asset
Retirement Obligations" ("SFAS No. 143"), which provides accounting requirements
for retirement obligations associated with tangible long-lived assets,
including: 1) the timing of liability recognition; 2) initial measurement of the
liability; 3) allocation of asset retirement cost to expense; 4) subsequent
measurement of the liability; and 5) financial statement disclosures. SFAS No.
143 requires that asset retirement cost be capitalized as part of the cost of
the related long-lived asset and subsequently allocated to expense using a
systematic and rational method. Any transition adjustment resulting from the
adoption of SFAS No. 143 would be reported as a cumulative effect of a change in
accounting principle. The Company will adopt the statement effective October 1,
2002. At this time, the Company cannot reasonably estimate the effect of the
adoption of this statement on either its financial position or results of
operations.
-37-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
In August 2001, the FASB issued Statement No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"), which will be
effective for financial statements issued for fiscal years beginning after
December 15, 2001 and interim periods within those fiscal years. SFAS No. 144
requires that long-lived assets to be disposed of by sale be measured at the
lower of the carrying amount or fair value less cost to sell, whether reported
in continuing operations or in discontinued operations. SFAS No. 144 broadens
the reporting of discontinued operations to include all components of an entity
with operations that can be distinguished from the rest of the entity and that
will be eliminated from the ongoing operations of the entity in a disposal
transaction. After its effective date, SFAS No. 144 will be applied to those
transactions where appropriate. The Company will adopt SFAS No 144 effective
October 1, 2002. At this time the Company is unable to determine what the future
impact of adopting this statement will have on its financial position or results
of operations.
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, 1998 to September 30, 2001 is as follows:
Estimated
Realizable Value
of Discontinued Net Refining
Net Refining Assets Liabilities Retained
------------------- --------------------
Balance - October 1, 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
Cash transactions.................................................... (80)
Adjustment of vendor liabilities..................................... 80
Adjustments resulting from American Western's Plan of
Liquidation.................................................. (188) (188)
------- ------
Balance - September 30, 2001......................................... $ 612 $3,016
======= ======
As of September 30, 2001, the estimated realizable value of discontinued
net refining assets consists of $612 of estimated recoverable proceeds from the
American Western note. The estimated value of net refining liabilities retained
consist of net vendor liabilities of $1,281 and accrued costs related to
discontinued refining operations of $2,155, offset by cash of $420.
"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
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 from
such amounts.
See Notes 12 and 13.
-38-
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 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 2,000,000 barrels of crude oil and 12,500,000 mcf
(thousand cubic feet) of natural gas, which, together, approximated 150% of the
Company's oil and gas reserves before the acquisition. In addition, the
production acquired initially 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
-----------------------------
(Unaudited)
Revenues................................................................. $ 62,719
Net income............................................................... $ 7,958
Net income per share..................................................... $ .95
Shares outstanding (diluted)............................................. 8,347,932
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 and has
terminated participation in each drilling venture. The total cost incurred to
participate in the drilling of the exploratory wells was $6,003.
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 $890.
-39-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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 adjusted purchase price of $3,059 consisted of $1,122 cash plus
382,289 shares of Delta's common stock valued at the market price or $1,937 (see
Note 8).
Investment in Romanian Concessions
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, 2001, the Company had participated in the drilling of five onshore
wildcat wells. Four of those wells resulted in dry holes. Although the fifth
well produced some volumes of natural gas when tested, the Company has not been
able to obtain a sufficiently high gas price to justify future production and
has elected at the present not to undertake an offset drilling program where the
fifth well was drilled. As a result, the Company recorded impairment provisions
of $2,765 and $832 for the years ended September 30, 2001 and 2000,
respectively, for costs incurred for the five onshore wells. The Company has
agreed to participate in the drilling of a sixth well, offshore, in the Black
Sea in the spring or early summer of 2002.
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
$2,580.
East Texas Property Acquisition
On April 30, 2001, the Company consummated the purchase of several East
Texas oil and gas properties from a private company. The effective date of the
purchase was April 1, 2001. These properties included majority interests in
twenty-one (21) operated producing oil and gas wells and interests in
approximately 6,500 gross acres in three counties in East Texas. The Company
estimates the proved reserves acquired were approximately 12.5 billion cubic
feet of natural gas and 191,000 barrels of crude oil. The consideration paid,
net of purchase price adjustments, was $10,040. The Company used its own
internally generated funds to make the purchase.
NOTE 5 - RESTRICTED CASH
Restricted cash consists of the following:
September 30,
------------------
2001 2000
---- ----
Funds supporting letters of credit for offshore Louisiana wells................... $1,519
Drilling deposits in escrow - Romania............................................. $ 7 4
Funds supporting letters of credit issued for operating bonds..................... 209 219
Funds escrowed for litigation settlement.......................................... 154
---- ------
$370 $1,742
==== ======
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 escrowed for litigation settlement pertain to Larry Long
Litigation (see Note 13).
-40-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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. All of the Company's accounts receivable at September 30, 2001 and
2000 consisted of exploration and production trade receivables.
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 was originally due on December 15, 2000
and bore interest at 9%, payable quarterly.
In December 2000, the Company agreed to extend the note until June 15,
2002. In return, Penn Octane increased the interest rate on the note to 13.5%
and issued to the Company warrants to acquire an additional 62,500 shares of
Penn Octane common stock at $3.00 per share. Subsequently, the interest rate was
increased to 16.5% and the exercise price on the 62,500 options issued was
reduced to $2.50 per share.
Effective September 14, 2001, the Company exercised options to acquire
275,933 shares of common stock of Penn Octane by exchanging its $500 note plus
$21 of accrued interest for the shares.
NOTE 8 - MARKETABLE SECURITIES
The Company's investment in marketable securities consists of common
shares of Penn Octane, Delta and Chevron/Texaco.
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, Delta and Chevron/Texaco common stock and options to buy Penn Octane
stock were as follows:
Common Stock
----------------------
Penn Octane Delta Chevron/Texaco Total
----------- ----- -------------- -----
September 30, 2001:
Cost.............................................. $2,271 $1,937 $14 $ 4,222
Unrealized gain (loss)............................ 3,308 (808) 2,500
------ ------ --- -------
Book value (market value)......................... $5,579 $1,129 $14 $ 6,722
====== ====== === =======
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
====== ====== =======
The fair market values of Penn Octane, Delta and Chevron/Texaco shares
were based on one hundred percent (100%) of the closing price on September 28,
2001, the last trading day in the Company's fiscal year ending September 30,
2001.
At September 30, 2001 and 2000, the fair market values of the Penn
Octane shares include $164 and $1,641, respectively, related to options to
acquire Penn Octane common stock held by the Company. The value of such options
was computed using the Black-Scholes method (see Note #16).
-41-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
The Company owned 1,343,600 shares of Penn Octane, 382,289 shares of
Delta and 177 shares of Chevron/Texaco at September 30, 2001. Of these 501,000
shares of Penn Octane and all 177 shares of Chevron/Texaco were registered. The
remaining shares are either in the process of being registered or the Company
has registration rights with respect to such shares. At September 30, 2001, the
Company also owned options to purchase 74,067 common shares of Penn Octane
common stock at $2.50 per share.
At September 30, 2000, the Company owned 1,067,667 shares of Penn Octane
and 382,289 shares of Delta, as well as options to purchase 454,167 common
shares of Penn Octane at exercise prices of $1.75 to $6.00 per share.
NOTE 9 - FURNITURE, FIXTURES AND EQUIPMENT
Furniture, fixtures and equipment are as follows:
September 30,
---------------
2001 2000
---- ----
Cost:
Furniture and fixtures........................................ $693 $660
Automobile and trucks......................................... 269 222
---- ----
962 882
Accumulated depreciation...................................... (740) (624)
---- ----
$222 $258
==== ====
NOTE 10 - OIL AND GAS PROPERTIES (Unaudited)
Oil and gas properties consist of the following:
September 30, 2001
-----------------------------------------
United
States Romania Total
------ ------- ------
Proved properties......................................................... $56,100 $56,100
Less: Accumulated depreciation, depletion and amortization................ (16,257) (16,257)
------- -------
Proved properties......................................................... 39,843 39,843
Unproved properties not being amortized................................... $3,707 3,707
Impairment of unproved properties......................................... (3,597) (3,597)
------- ------ -------
$39,843 $ 110 $39,953
======= ====== =======
September 30, 2000
-----------------------------------------
United
States Romania Total
------ ------- ------
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 properties......................................... (832) (832)
------- ------ -------
$29,218 $1,447 $30,665
======= ====== =======
-42-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
Capital costs incurred by the Company in oil and gas activities are as
follows:
Year Ended September 30,
--------------------------------------------------------------------------
2001 2000
----------------------------------- -------------------------------
United United
States Romania Total States Romania Total
------ ------- ----- ------ ------- -----
Acquisition of properties:
Proved properties.................... $10,002 $10,002 $3,642 $ 3,642
Unproved properties.................. 346 346 678 $ 999 1,677
Exploration............................. 1,560 $1,428 2,988 2,966 346 3,312
Development............................. 2,113 2,113 2,595 2,595
------- ------ ------- ------ ------ -------
$14,021 $1,428 $15,449 $9,881 $1,345 $11,226
======= ====== ======= ====== ====== =======
Results of operations, excluding corporate overhead and interest
expense, from the Company's oil and gas producing activities are as follows:
Year Ended September 30,
---------------------------------------
2001 2000 1999
---- ---- ----
Revenues:
Crude oil, condensate, natural gas liquids and natural gas sales... $21,144 $17,959 $6,712
------- ------- ------
Costs and expenses:
Production costs................................................... $ 7,399 $ 6,194 1,910
Depreciation, depletion and amortization........................... 3,348 2,990 1,937
Impairment of foreign unproved properties.......................... 2,765 832
------- ------- ------
Total costs and expenses........................................... 13,512 10,016 3,847
------- ------- ------
Income tax provision (benefit).......................................... 1,387 (6,553) 753
------- ------- ------
Income from oil and gas producing activities............................ $ 6,245 $16,569 $2,112
======= ======= ======
The income tax provision is computed at 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:
Year Ended September 30,
-------------------------------------
2001 2000 1999
---- ---- ----
Depletion rate per equivalent MCF of natural gas........................ $0.72 $0.57 $0.71
===== ===== =====
The increase in the depletion rate in fiscal 2001 resulted primarily
because the Company's reserves qualitites decreased significantly as a result of
lower oil and gas prices at September 30, 2001. The decrease in reserve
quantities without a similar decrease in related costs resulted in a higher
depletion rate. In addition, in fiscal 2001, the Company acquired significant
East Texas reserves at a higher cost per mcfe than the cost for the Company's
existing reserves at the time of the acquisition (see Note 4).
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 at September 30, 2000. The increase in reserve
quantities without a similar increase in costs resulted in the lower depletion
rate.
See Note 21.
-43-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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
and Ralph E. Davis Associates, Inc. and may be affected by the limitations
inherent in such estimations. The process of estimating reserves is subject to
continuous revisions as additional information is made available through
drilling, testing, reservoir studies and production history. There can be no
assurance such estimates will not be materially revised in subsequent periods.
Estimated quantities of proved reserves and changes therein, all of
which are domestic reserves, are summarized below:
("000's" omitted)
----------------------------------
Oil (BBLS) Natural Gas (MCF)
---------- -----------------
Proved developed and undeveloped reserves:
As of October 1, 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
Acquisitions............................................... 266 10,183
Revisions of previous estimates............................ (1,379) (20,711)
Production................................................. (262) (3,083)
----- ------
As of September 30, 2001....................................... 3,360 30,692
===== ======
Proved developed reserves:
September 30, 1998............................................. 162 13,589
===== ======
September 30, 1999............................................. 1,788 23,547
===== ======
September 30, 2000............................................. 2,963 35,815
===== ======
September 30, 2001............................................. 1,890 26,480
===== ======
Although the Company has participated in the drilling of five
exploratory wells in Romania, no proved reserves have yet been assigned to any
of these wells. 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.
-44-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
September 30,
---------------------------------------------
2001 2000 1999
---- ---- ----
Future cash inflows................................................ $ 138,594 $ 371,784 $ 118,794
Future production costs............................................ (43,288) (87,162) (42,934)
Future development costs........................................... (8,655) (12,620) (4,229)
Future income tax expense.......................................... (13,102) (84,445) (8,538)
--------- --------- --------
Future net cash flows.............................................. 73,549 187,557 63,093
Discount factor of 10% for estimated timing of future cash flows... (37,269) (96,438) (21,849)
--------- --------- --------
Standardized measure of discounted future cash flows............... $ 36,280 $ 91,119 $ 41,244
========= ========= ========
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:
September 30,
----------------------------------------
2001 2000 1999
---- ---- ----
Standardized measure, beginning of year............................. $91,119 $41,244 $ 9,946
Sale of oil and gas, net of production costs........................ (13,745) (11,083) (4,324)
Net changes in prices............................................... (60,403) 45,757 2,163
Sale of reserves in place........................................... (1,457)
Purchase of reserves in place....................................... 7,662 6,757 22,215
Changes in estimated future development costs....................... 1,408 (5,039) 2,405
Development costs incurred during the period that reduced future
development costs................................................ 2,113 2,595 1,073
Revisions in reserve quantity estimates............................. (26,591) 76,355 1,438
Discoveries of reserves............................................. 963
Net changes in income taxes......................................... 30,528 (32,031) 745
Accretion of discount............................................... 9,112 4,286 995
Other:
Change in timing of production................................... (1,228) (36,168) 12,055
Other factors.................................................... (3,695) (1,060) (7,467)
------- ------- -------
Standardized measure, end of year................................... $36,280 $91,119 $41,244
======= ======= =======
NOTE 12 - CONTINGENT ENVIRONMENTAL LIABILITY
In December 1995, IRLP, an inactive subsidiary of the Company, sold its
refinery, the Indian Refinery, to 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 outside party has
substantially dismantled the Indian Refinery.
American Western recently filed a Plan of Liquidation. American Western
anticipates that the Plan of Liquidation will be confirmed in January 2002.
During fiscal 1998, the Company was informed that the United States
Environmental Protection Agency ("EPA") had investigated offsite acid sludge
waste found near the Indian Refinery and had investigated and remediated surface
contamination on the Indian Refinery property. Neither the Company nor IRLP was
initially named with respect to these two actions.
-45-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
In October 1998, the EPA named the Company and two of its inactive
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. A subsidiary of Texaco had owned the refinery until December
of 1988. The Company subsequently responded to the EPA indicating that it was
neither the owner nor the 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. Texaco had
made no previous claims against the Company although the Company's subsidiaries
had owned the refinery from August 1989 until December 1995. 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 and indemnify Texaco for costs that Texaco has already incurred
addressing environmental contamination at the Indian Refinery. Finally, Texaco
also claimed that the Company and two of its 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
responded to Texaco disputing the factual and theoretical basis for Texaco's
claims against the Company. The Company's management and special counsel
subsequently met with representatives of Texaco but the parties disagreed
concerning Texaco's claims.
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 addition to the
numerous defenses that the Company has against Texaco's contractual claim for
indemnity, the Company and its special counsel believe that by the express
language of the agreement which Texaco construes to create an indemnity, Texaco
has irrevocably elected to forgo all rights of contractual indemnification it
might otherwise have had against any person, including the Company.
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, we are informed, continues to seek 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. Estimated gross undiscounted clean up costs for
this refinery are at least $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
remediation liability would be proportional to its years of operation, although
such may not be the case. Furthermore, as noted above, Texaco has claimed that
the Company indemnified it for all environmental liabilities related to the
Indian Refinery. If Texaco were to sue the Company on this theory and prevail in
court, the Company could be held responsible for the entire estimated clean up
costs of $80,000-$150,000 or more. In such a case, this cost would be far in
excess of the Company's financial capability.
-46-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
An opinion issued by the U.S. Supreme Court in June 1998 in a comparable
matter and a recent decision by the U.S. Appeals Court for the Fifth Circuit
supports the Company's positions. 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
parties in additional legal actions to recover remediation costs. In recent
years, government and other plaintiffs have often sought redress for
environmental liabilities from the party most capable of payment without regard
to responsibility or fault. Whether or not the Company is ultimately held liable
in such a circumstance, should litigation involving the Company and/or IRLP
occur, the Company would probably incur substantial legal fees and experience a
diversion of management resources from other operations.
Although the Company does not believe it is liable for any of its
subsidiaries' clean-up costs and intends to vigorously defend itself in such
regard, the Company cannot predict the ultimate outcome of these matters due to
inherent uncertainties.
NOTE 13 - COMMITMENTS, CONTINGENCIES AND LINE OF CREDIT
Operating Lease Commitments
The Company has the following noncancellable operating lease commitments
and noncancellable sublease rentals at September 30, 2001:
Lease Sublease
Year Ending September 30, Commitments Rentals
- ------------------------- ----------- -------
2002........................................................ $ 473 $ 65
2003........................................................ 470 66
2004........................................................ 240
2005........................................................ 76
------ ----
2006........................................................ $1,259 $131
====== ====
Rent expense for the years ended September 30, 2001, 2000 and 1999 was
$456, $412 and $386, 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 $1,101 at September
30, 2001. No severance obligations were owed to employees at September 30, 2001.
Letters of Credit
At September 30, 2001, the Company had issued letters of credit of $209
for oil and gas drilling, operating and plugging bonds. The letters of credit
are renewed semi-annually or annually.
Line of Credit
See Note 21.
-47-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
Legal Proceedings
Contingent Environmental Liabilities
See Note 12.
General
Long Trusts Lawsuit
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 Castle Texas Production Limited Partnership ("CTPLP"), an inactive
exploration and production subsidiary of the Company. The wells were among those
sold to Union Pacific Resources Corporation ("UPRC") in May 1997. The Long
Trusts claimed that CTPLP did not allow them to sell gas 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, interest, attorneys' fees
and court costs.
After a three-week trial, the District Court in Rusk County
submitted 36 questions to the jury which covered all of the claims and
counterclaims in the lawsuit. Based upon the jury's answers, the District Court
entered judgement granting plaintiffs' claims against the Company and its
subsidiaries, as well as CTPLP's counterclaim against the plaintiffs. The
District Court issued an amended judgement on September 5, 2001, which became
final in December 2001. The net amount awarded to the plaintiffs was
approximately $2,700. The Company and its subsidiaries have filed a notice of
appeal with the Tyler Court of Appeals and will continue to vigorously contest
this matter.
Special counsel to the Company does not consider an unfavorable
outcome to this lawsuit probable. The Company's management and special 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. As a result, the Company has not accrued
any liability for this litigation. Nevertheless, to pursue the appeal, the
Company and its subsidiaries will be required to post a bond to cover the net
amount of damages awarded to the plaintiffs and to maintain that bond until the
resolution of the appeal (which may take several years). The Company has
included the letter of credit to support the bond, estimated at approximately
$3,000, in its line of credit with a major energy bank.
See Note 21.
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.
-48-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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. In July 2001, the Company deposited $250
plus accrued interest of $9 in a litigation settlement account. As of September
30, 2001, $106 had been disbursed from the account.
See Note 21.
MGNG Litigation
On May 4, 1998, 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 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.
In 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
believed that they do not owe $772 and were 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 all lawsuits. Under the
terms of the settlement the amount claimed by MGNG under a gas supply contract
was reduced by $325 and the net amount payable to MGNG was set at $400 and the
parties signed mutual releases.
See Note 21.
Pilgreen Litigation
As part of the AmBrit purchase, Castle Exploration Company, Inc.
("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 ORR should
be released to CECI in the near future. As of September 30, 2001, approximately
$415 attributable to CECI's share of the ORRI revenue was suspended. The
Company's policy is to recognize the suspended revenue only when and if it is
received.
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.
-49-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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 failed to
do so. As a result, the Company elected to terminate the GAMXX Agreement.
Pursuant to the Agreement, GAMXX agreed to assist the Company in selling GAMXX's
assets or the Company's investment in GAMXX. The Company is currently seeking to
dispose of its lender's interest in GAMXX and recover some of the loan to GAMXX.
The Company has carried its loans to GAMXX at zero for the last eight
years. The Company will record any proceeds as "other income" if and when it
collects such amount.
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 for the year ended September 30, 1999.
On June 1, 1999, the Company acquired all of the oil and gas assets of
AmBrit (see Note 4) and thereafter commenced hedging sales of the related oil
and gas production. As of September 30, 1999, the Company had hedged
approximately 54% of its anticipated consolidated crude oil production and
approximately 39% of its anticipated consolidated natural gas production for the
period from October 1, 1999 to September 30, 2000. 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 after July 2000 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, 2001 and December 14, 2001, the Company had not hedged
its anticipated future oil and gas production.
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, 2001, 2000 and 1999, the Company's
contributions to the Plan aggregated $50, $46 and $37, 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.
-50-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
From November 1996 until September 30, 2001, 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, 2001, 4,871,020
shares (13,973,054 shares before taking into account the 200% stock dividend
effective January 31, 2000) had been repurchased at a cost of $66,506. The
repurchased shares are held in treasury
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.
See Note 21
NOTE 16 - STOCK OPTIONS AND WARRANTS
Option and warrant activities during each of the three years ended
September 30, 2001 are as follows (in whole units):
Incentive
Plan Other
Options Options Total
------- ------- -----
Outstanding at October 1, 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
Issued............................................................... 60,000 60,000
---------- ------ ---------
Outstanding at September 30, 2001.................................... 690,000 60,000 750,000
========== ====== =========
Exercisable at September 30, 2001.................................... 690,000 60,000 750,000
========== ====== =========
Reserved at September 30, 2001....................................... 1,687,500 60,000 1,747,500
========== ====== =========
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
========== ====== =========
Exercise prices at:
September 30, 2001.......................................... $3.42- $3.79
$8.58
September 30, 2000.......................................... $3.42- $3.79
$8.58
September 30, 1999.......................................... $3.42- $3.79
$5.75
Exercise Termination Dates.................................. 5/17/2003- 4/23/2007 5/17/2003-
1/02/2011 1/02/2011
-51-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
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.
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, 1998 to September 30, 2001 is as follows:
Weighted
Average
Options Price
------- -----
Outstanding - October 1, 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
Issued..................................................... 60,000 7.00
------- ------
Outstanding - September 30, 2001........................... 750,000 $ 5.24
======= ======
At September 30, 2001, exercise prices for outstanding options ranged
from $3.42 to $8.58. The weighted average remaining contractual life of such
options was 5.6 years.
The per share weighted average fair values of stock options issued
during fiscal 2001, 2000 and fiscal 1999 were $2.41, $3.29 and $4.56,
respectively, on the dates of issuance using the Black-Scholes option pricing
model with the following weighted average assumptions: average expected dividend
yield - 3.0% in 2001, 3.0% in 2000 and 3.5% in 1999; risk free interest rate -
3.50% in 2001, 5.54% in 2000 and 6.32% in 1999; expected life of 10 years in
2001, 2000 and 1999 and volatility factor of .38 in 2001, .44 in 2000, and .22
in 1999.
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.
-52-
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:
Year Ending September 30,
-------------------------------------------
2001 2000 1999
---- ---- ----
Net income as reported............................................... $ 1,716 $ 5,069 $ 8,266
Adjustment required by SFAS 123...................................... (145) (346) (152)
------- -------- --------
Pro-forma net income................................................. $ 1,571 $ 4,723 $ 8,114
======= ======== ========
Pro-forma net income per share:
Basic............................................................. $ 0.24 $ .68 $ .99
======= ======== ========
Diluted........................................................... $ 0.23 $ .66 $ .97
======= ======== ========
NOTE 17 - INCOME TAXES
Provisions for (benefit of) income taxes consist of:
September 30,
----------------------------------------
2001 2000 1999
---- ---- ----
Provision for (benefit of) income taxes:
Current:
Federal....................................................... $ 4 ($ 35) $ 193
State......................................................... (2)
Deferred:
Federal....................................................... 786 922 2,209
State......................................................... 22 26 68
Adjustment to the valuation allowance for deferred taxes:
Federal....................................................... (419) (3,115) 475
State......................................................... (12) (89) 13
---- ------ ------
$381 ($2,291) $2,956
==== ====== ======
Deferred tax assets (liabilities) are comprised of the following at
September 30, 2001 and 2000:
September 30,
----------------------
2001 2000
---- ----
Operating losses and tax credit carryforwards....................................... $4,715 $4,993
Statutory depletion carryovers...................................................... 3,903 3,689
Depletion accounting................................................................ (5,341) (3,602)
Discontinued net refining operations................................................ 866 866
Losses in foreign subsidiaries...................................................... 1,295 300
------ ------
5,438 6,246
Valuation allowance................................................................. (3,559) (3,990)
------ ------
$1,879 $2,256
====== ======
Deferred tax assets - current....................................................... $1,879 $2,256
------ ------
$1,879 $2,256
====== ======
At September 30, 2001, the Company determined that a portion of the
deferred tax asset would more likely than not be realized based upon estimates
of future taxable income and upon the projected taxable income resulting from
the anticipated sale of its oil and gas assets to Delta and accordingly
decreased the valuation allowance by $431 to $3,559.
If recent decreases in oil and gas prices continue and if the sale of
the Company's oil and gas assets to Delta is not consummated, the Company may be
required to increase its valuation allowance.
-53-
See Note 21.
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.
The income tax provision (benefit) differs from the amount computed by
applying the statutory federal income tax rate to income before income taxes as
follows:
Year Ended September 30,
------------------------------------
2001 2000 1999
---- ---- ----
Tax at statutory rate.................................................... $734 $ 972 $3,928
State taxes, net of federal benefit...................................... 7 (42) 51
Revision of tax estimates and contingencies.............................. 50 (151)
Statutory depletion...................................................... (1,330)
Increase (decrease) in valuation allowance............................... (431) (3,204) 489
Other.................................................................... 21 (17) (31)
---- ------- ------
$381 ($2,291) $2,956
==== ======= ======
At September 30, 2001, the Company had the following tax carryforwards
available:
Federal Tax
-------------------------------
Alternative
Minimum
Regular Tax
------- ---
Net operating loss...................................................... $ 2,674 $24,021
Alternative minimum tax credits......................................... $ 3,752 N/A
Statutory depletion..................................................... $ 10,841 $ 440
The net operating loss carryforwards expire from 2001 through 2010.
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. At
September 30, 2001 all net operating loss carryforwards of the Company were no
longer subject to the annual limitation.
The Company also has approximately $58,688 in individual state tax loss
carryforwards available at September 30, 2001. Approximately $47,287 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.
-54-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
NOTE 18 - RELATED PARTIES
In June 1999, the Company repurchased 24,700 (74,100 after stock split)
shares of the Company's common stock from an officer of the Company. 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 its 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.
Year Ended September 30, 2001
--------------------------------------------------------------------------------------
Natural Gas Oil & Gas Eliminations
Marketing Exploration and
and and Refining Corporate
Transmission Production (Discontinued) Items Consolidated
------------ ---------- -------------- ----- ------------
Revenues........................... $ 21,144 $ 21,144
Operating income (loss)............ $ 5,682 ($ 4,169) $ 1,513
Identifiable assets................ $67,702* $ 105,238 ($113,822) $ 59,118
Capital expenditures............... $ 15,531 $ 15,531
Depreciation, depletion and
amortization................ $ 3,468 $ 2 $ 3,470
Year Ended September 30, 2000
--------------------------------------------------------------------------------------
Natural Gas Oil & Gas Eliminations
Marketing Exploration and
and and Refining Corporate
Transmission Production (Discontinued) Items Consolidated
------------ ---------- -------------- ----- ------------
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
-55-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
Year Ended September 30, 1999
----------------------------------------------------------------------------------------
Natural Gas Oil & Gas Eliminations
Marketing Exploration and
and and Refining Corporate
Transmission Production (Discontinued) Items Consolidated
------------ ---------- -------------- ----- ------------
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
*Consists primarily of intracompany receivables.
For the year ended September 30, 1999, sales by the Company's natural
gas marketing subsidiary to Lone Star Gas Company under the Lone Star Contract
aggregated $46,802. These amounts constituted approximately 82% of consolidated
revenues for the year ended September 30, 1999. The Lone Star contract
terminated in May 1999.
At the present time, the Company's consolidated revenues consist
entirely of oil and gas sales. Three purchasers of the Company's oil and gas
production currently account for approximately 43% of consolidated production
and a similar percentage of oil and gas sales 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 -- the carrying amount is a reasonable
estimate of fair value.
Marketable securities are related solely to the Company's investment in
Penn Octane, Delta and Chevron/Texaco 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, 2001, the Company disbursed the remaining
$153 from the Larry Long Litigation settlement account (see Note 13).
Subsequent to September 30, 2001, the Company paid MGNG $400 in
settlement of the MGNG Litigation (see Note 13).
In November 2001, the Company entered into an agreement for a line of
credit of up to $40,000 with an energy bank. Pursuant to the related agreement
the energy bank agreed to make available to the Company loans and letters of
credit not to exceed a borrowing base determined by the value of the Company's
oil and gas reserves using parameters set by the bank. Such borrowing based will
be determined no less than semi-annually. The loans and letters of credit will
be secured by the Company's oil and gas properties to the extent the amount
outstanding under the facility exceeds $10,000. Interest under the facility will
accrue at the bank's prime rate or at a LIBOR rate - the choice of rates being
determined by the Company. Letters of credit issued under the facility will
accrue interest at 2.25% annually. Loans outstanding under the facility will be
repaid pursuant to a schedule set by the bank but redetermined at each borrowing
base determination date. In addition, the Company is subject to typical
financial covenants including minimum tangible net worth, debt service coverage,
interest coverage and current ratio limitations, limitations on annual and
quarterly dividends the Company may pay to shareholders and other limitations
governing capital expenditures. The facility is scheduled to terminate November
30, 2003. The facility also includes a provision to provide letters of credit of
up to $3,000 as may be required for the Long Trusts Lawsuit litigation (see
Note 13).
-56-
Castle Energy Corporation
Notes to Consolidated Financial Statements
("$000's" Omitted Except Per Share Amounts)
On December 11, 2001, the Company entered into a letter of intent to
sell all of its domestic oil and gas assets to Delta for $20,000 and 9,566,000
shares of commons stock of Delta. The effective date of the proposed sale is
October 1, 2001 and the expected closing date is April 30, 2002 or later. The
sale is subject to execution of a definitive purchase and sale agreement by both
parties, approval of the transaction by both Delta's and the Company's directors
and approval of the issuance of the shares to Castle by Delta's shareholders.
If the sale to Delta is not consummated, the Company could continue to
operate as it does currently or pursue other alternative strategies.
NOTE 22 - QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
First Second Third Fourth
Quarter Quarter Quarter Quarter
(December 31) (March 31) (June 30) (September 30)
------------- ---------- --------- --------------
Year Ended September 30, 2001:
Revenues.................................. $5,394 $6,316 $5,347 $4,087
Operating income (loss)................... $1,533 $2,174 $ 511 ($2,705)
Net income (loss)......................... $1,110 $1,531 $ 397 ($1,322)
Net income per share (diluted)............ $ .16 $ .22 $ .06 ($ .20)
First Second Third Fourth
Quarter Quarter Quarter Quarter
(December 31) (March 31) (June 30) (September 30)
------------- ---------- --------- --------------
Year Ended September 30, 2000:
Revenues.................................. $4,085 $3,318 $4,945 $5,611
Operating income (loss) .................. $ 32 ($ 387) $ 835 $1,489
Net income (loss)......................... $ 259 ($ 277) $1,024 $4,063
Net income (loss) per share (diluted)..... $ .04 ($ .04) $ .15 $ .58
For the year ended September 30, 2000 revenues from well operations have
been retroactively reclassified as reductions of oil and gas production costs.
The sums of the quarterly per share amounts differ from the annual per
share amounts primarily because the stock purchases made by the Company were not
made in equal amounts and at corresponding times each quarter.
-57-
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, 2001 and 2000, 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, 2001. 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, 2001 and 2000, and the results
of their operations and their cash flows for each of the years in the three year
period ended September 30, 2001 in conformity with accounting principles
generally accepted in the United States of America.
KPMG LLP
Houston, Texas
December 18, 2001
-58-
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
-59-
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 2002 Annual
Meeting of Stockholders.
-60-
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. and 2. Financial Statements and Financial Statement Schedules
Financial statements and schedules filed as part of this Report on Form 10-K
are listed in Item 8 of this Form 10-K.
3. Exhibits
The Exhibits required by Item 601 of Regulation S-K and filed herewith or
incorporated by reference herein are listed in the Exhibit Index below.
Exhibit Number Description of Document
-------------- -----------------------
3.1 Restated Certificate of Incorporation(15)
3.2 Bylaws(10)
4.1 Specimen Stock Certificate representing Common Stock(8)
4.2 Rights Agreement between Castle Energy Corporation and American Stock Transfer and Trust
Company as Rights Agent, dated as of April 21, 1994(10)
10.33 Castle Energy Corporation 1992 Executive Equity Incentive Plan(8)
10.34 First Amendment to Castle Energy Corporation 1992 Executive Equity Incentive Plan, effective
May 11, 1993(8)
10.124 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)
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)
-61-
Exhibit Number Description of Document
-------------- -----------------------
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. (31)
10.139 Purchase and Sale Agreement dated August 4, 2000 between Castle Offshore LLC, BWAB Limited
Liability Company and Delta Petroleum Company (31)
10.140 Agreement to Transfer a Membership Interest In Networked Energy LLC to CEC, Inc., dated August
31, 2000 (31)
10.141 Second Amendment - Promissary Note of Penn Octane Corporation (29)
10.142 Purchase and Sale Agreement, dated April 1, 2001, between Strand Energy LC and Castle
Exploration Company, Inc. (30)
10.143 Credit Agreement as of November 26, 2001 among Castle Exploration Company, Inc. and Castle
Energy Corporation and Bank of Texas National Association
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.
(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, 2001.
- ------------------
(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
(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
(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
(29) Incorporated by reference to the Registrant's Form 10-Q for quarter ended December 31, 2000
(30) Incorporated by reference to the Registrant's Form 10-Q for quarter ended March 31, 2001
(31) Incorporated by reference to the Registrant's Form 10-K for year ended September 30, 2000
-62-
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 19, 2001 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.
/s/JOSEPH L. CASTLE II Chairman of the Board and Chief December 19, 2001
- --------------------------- Executive Officer
Joseph L. Castle II Director
/s/MARTIN R. HOFFMANN Director December 19, 2001
- ---------------------------
Martin R. Hoffmann
/s/JOHN P. KELLER Director December 19, 2001
- ---------------------------
John P. Keller
/s/RUSSELL S. LEWIS Director December 19, 2001
- ---------------------------
Russell S. Lewis
/s/RICHARD E. STAEDTLER Senior Vice President December 19, 2001
- --------------------------- Chief Financial Officer
Richard E. Staedtler Chief Accounting Officer
Director
/s/SIDNEY F. WENTZ Director December 19, 2001
- ---------------------------
Sidney F. Wentz
-63-
DIRECTORS AND OFFICERS
BOARD OF DIRECTORS
(December 19, 2001)
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 Secretary of the Army 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
MARY A. CADE TIMOTHY M. MURIN
Company Controller and Treasurer President - Exploration and Production
WILLIAM C. LIEDTKE III
Company Counsel
PRINCIPAL OFFICES
One Radnor Corporate Center 512 Township Line Road
Suite 250 Three Valley Square, Suite 100
100 Matsonford Road Blue Bell, PA 19422
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.
1717 St. James Place, Suite 460
KPMG LLP Houston, Texas 77056
700 Louisiana
Houston, Texas 77002
Registrar and Transfer Agent
American Stock Transfer & Trust Company
40 Wall Street, 46th Floor
New York, New York 10005