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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, 2002
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 -- $.50
par value and related Rights
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes __X__ No ____
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ].
As of December 13, 2002, there were 6,592,884 shares of the registrant's
Common Stock ($.50 par value) outstanding. The aggregate market value of voting
stock held by non-affiliates of the registrant as of such date was $21,037,947
(5,009,035 shares at $4.20 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
2002 FORM 10-K
TABLE OF CONTENTS
Item Page
- ---- ----
PART I
------
1. and 2. Business and Properties.................................................................. 1
3. Legal Proceedings........................................................................ 5
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.................................................................. 12
7. Management's Discussion and Analysis of Financial Condition and Results of Operations.... 13
8. Financial Statements and Supplementary Data.............................................. 23
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..... 62
PART III
--------
10. Directors and Executive Officers of the Registrant....................................... 63
11. Executive Compensation................................................................... 63
12. Security Ownership of Certain Beneficial Owners and Management........................... 63
13. Certain Relationships and Related Transactions........................................... 63
PART IV
-------
14. Controls and Procedures.................................................................. 64
15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K......................... 64
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. All forward-looking statements in this Form 10-K are expressly qualified
in their entirety by the cautionary statements in this paragraph.
References to Castle Energy Corporation mean "the Company", the parent,
and/or one or more of its subsidiaries. Such references are for convenience only
and are not intended to describe legal relationships.
From inception (February 1981) until September 2002, the Company
operated in the exploration and production segment of the energy business.
During this period the Company owned interests in oil and gas wells in fourteen
states in the United States and participated in the drilling of five wildcat
wells in Romania. For the periods from inception until August 1989 and from June
1999 to September 6, 2002, the exploration and production segment of the energy
business was the only business in which the Company operated. On May 31, 2002,
the Company sold all of its domestic oil and gas properties to Delta Petroleum
Corporation, another public company engaged in oil and gas exploration and
production ("Delta"). On September 6, 2002, the Company sold all of its
interests in Romania to the operator of its Romanian concession. Prior to these
sales the Company owned interests in approximately 525 oil and gas wells in the
United States and a fifty percent interest in several drilling concessions in
Romania. As a result of these sales, the Company now owns no operating assets
and is not directly involved in any business.
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 former Texaco 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.
During the period from December 31, 1992 to May 31, 1999, the Company,
through two of its subsidiaries, was 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 then
bought gas on the spot market.
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, installation and operation of
natural gas fueled energy generating facilities that supply power, heating and
cooling services directly to retail customers with significant energy
consumption to reduce their energy costs - especially during peak usage periods.
In March 2002, the Company invested an additional $150,000 in Network,
increasing its membership interest to 45%. Network is a start up company and
recently entered into its first consulting contract.
In October 1996, the Company commenced a program to repurchase shares of
its common stock at stock prices beneficial to the Company. As of December 13,
2002, 4,911,020 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 356,946 additional shares.
-1-
As of December 13, 2002, the Company's primary assets are as follows:
a. Approximately $14,000,000 of unrestricted cash.
b. Approximately $4,100,000 of restricted cash.
c. 1,343,600 shares of common stock of Penn Octane Corporation, a public
company engaged in the transportation and sale of liquid propane gas
to Mexico ("Penn Octane").
d. 9,948,289 common shares of Delta, representing approximately 44% of
Delta's outstanding common shares.
e. A 45% membership interest in Network.
In addition, the Company is involved in three lawsuits - see Item 3 -
"Legal Proceedings."
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 included 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
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.
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, a public oil and gas exploration and production
company ("Costilla"), by the Romanian government. The Company paid Costilla
$65,000 for the option. In May 1999, the Company exercised the option. As of
September 30, 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 was not able
to obtain a sufficiently high gas price to justify future production. The
Company subsequently agreed to participate in the drilling of a sixth well in
the Black Sea in the spring or early summer of 2002. The drilling of the Black
Sea well was postponed several times because of the lack of suitable drilling
rigs. On September 6, 2002, the Company's subsidiary, which owned a 50% interest
in the Romanian drilling concessions, sold all of its interests to the operator
of the concessions for $1. As a result, the Company owns no interests in
Romania.
In November and December 1999, the Company acquired additional outside
interests in several Alabama and Pennsylvania wells, which it operated, 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.
-2-
On May 31, 2002, the Company consummated the sale of all of its domestic
oil and gas properties to Delta. The sale was pursuant to a definitive purchase
and sale agreement dated January 15, 2002. At closing, the Company received
$18,236,000 cash plus 9,566,000 shares of Delta's common stock. The $18,236,000
cash represented a $20,000,000 purchase price cash component as of October 1,
2001, the effective date of the sale, less $1,764,000 of net cash flow received
by the Company applicable to production from the properties subsequent to the
effective date. In September 2002, the Company paid Delta $194,000 as a final
purchase price adjustment, effectively reducing the cash portion of the sale to
$18,042,000. Pursuant to the governing purchase and sale agreement the Company
granted Delta an option to repurchase up to 3,188,667 of Delta's shares at
$4.50/share through May 31, 2003. As of December 13, 2002, Delta had not
exercised any portion of its options.
As a result of the sales to Delta and the operator of the Romanian
concessions, the Company no longer directly owns any oil and gas properties. The
Company's only oil and gas interests at September 30, 2002 and December 13, 2002
are those derived from its 44% ownership of Delta.
Properties
Proved Oil and Gas Reserves
Since the Company sold all of oil and gas properties by September 30,
2002, the Company does not directly own any proved oil and gas reserves at
September 30, 2002. Nevertheless, proven oil and gas reserves can indirectly be
attributed to the Company by virtue of the Company's 44% ownership of Delta.
Such reserves are included in the unaudited reserve disclosures in Note 11 to
the consolidated financial statement included in Item 8 to this Form 10-K.
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, 2002, including production from acquired properties since the date
of acquisition.
Fiscal Year Ended September 30,
--------------------------------------
2002 2001 2000
---- ---- ----
Oil -- Bbls (barrels).............................................. 179,000 262,000 279,000
Gas -- MCF (thousand cubic feet)................................... 2,254,000 3,083,000 3,547,000
Production for the year ended September 30, 2002 only includes
production for the period October 1, 2001 to May 31, 2002 since the Company sold
all of its producing properties to Delta on May 31, 2002.
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, if
applicable, and the average production cost (lifting cost) per equivalent unit
of production for the periods indicated. Production costs include applicable
operating costs and maintenance costs of support equipment and facilities,
labor, repairs, severance taxes, property taxes, insurance, materials, supplies
and fuel consumed in operating the wells and related equipment and facilities.
Fiscal Year Ended September 30,
--------------------------------
2002 2001 2000
---- ---- ----
Average Sales Price per Barrel of Oil.................................. $21.51 $27.39 $27.94
Average Sales Price per MCF of Gas..................................... $ 2.48 $ 4.53 $ 2.87
Average Production Cost per Equivalent MCF(1).......................... $ .98 $ 1.59 $ 1.19
--------------
(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 or fiscal 2002.
-3-
No sale price or production cost data are included in the above data for
the period June 1, 2002 to September 30, 2002 because the Company sold all of
its producing oil and gas properties to Delta on May 31, 2002.
The average sales price per barrel of crude oil decreased $4.64 per
barrel for the year ended September 30, 2000 as a result of hedging. The average
sales price per mcf (thousand cubic feet) of natural gas decreased $.07 for the
year ended September 30, 2000 as a result of hedging. Oil and gas sales were not
hedged after July 2000.
Productive Wells and Acreage
The Company owned no productive wells or acreage at September 30, 2002,
having sold all its interests in wells and acreage to Delta on May 31, 2002.
Drilling Activity
The table below sets forth for each of the three fiscal years in the
period ended September 30, 2002 the number of gross and net productive and dry
developmental and exploratory wells drilled, including wells drilled on acquired
properties since the dates of acquisition.
Fiscal Year Ended September 30,
--------------------------------------------------------------------------------------------------------
2002 2001 2000
----------------------------------- ------------------------------- ---------------------------------
United States Romania United States Romania United States Romania
---------------- ----------------- --------------- -------------- -------------- -----------------
Productive Dry Productive Dry Productive Dry Productive Dry Productive Dry Productive Dry
---------- --- ---------- --- ---------- --- ---------- --- ---------- --- ---------- ---
Developmental:
Gross........... -- 2 -- -- 17 4 -- -- 9 -- -- --
Net............. -- 1 -- -- 4 1.3 -- -- 4.5 -- -- --
Exploratory:
Gross........... -- -- -- -- -- -- -- 3* 1 8 -- 2
Net............. -- -- -- -- -- -- -- 1.5* .5 3.75 -- 1
* One well, in which the Company has a fifty percent (50%) interest,
produced some volumes of natural gas when tested but the Company was not
able to obtain a price for its production that made future operations
economical.
REGULATIONS
The oil and gas exploration and production operations of the Company
were subject to a number of local, state and federal environmental laws and
regulations. Compliance with such regulation did not result in material
expenditures.
Most states in which the Company conducted 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 resulted in increased
legal and compliance costs to the Company.
The Company was also subject to various state and Federal laws regarding
environmental and ecological matters because it acquired, drilled and operated
oil and gas properties. To alleviate the environmental risk, the Company carried
$25,000,000 of liability insurance and $3,000,000 of special operator's extra
expense (blowout) insurance for wells it drilled.
As a result of the sale of all of its oil and gas properties to Delta on
May 31, 2002, the Company is no longer directly subject to regulations governing
oil and gas production and exploration.
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 both contingent and litigated environmental
exposures. See Items 3 and 7 of this Form 10-K and Note 12 to the consolidated
financial statements included in Item 8 of this Form 10-K.
-4-
EMPLOYEES AND OFFICE FACILITIES
As of December 13, 2002, the Company, through its subsidiaries, employed
five personnel.
The Company leases certain offices as follows:
Office Location Function
--------------- --------
Radnor, PA Corporate Headquarters
Blue Bell, PA Accounting and Administration
Oklahoma City, Oklahoma Legal
The leases governing the Company's offices include standard provisions
for fixed rentals that escalate 3-4% annually over the period of the lease,
reimbursement of allocated shares of utility costs (minor) and the right to
sublease subject to landlord approval. The last office lease expires in April
2005. The lease commitment of the Company are set forth in Note 13 to the
Consolidated Financial Statements in Item 8 to this Form 10-K.
The Company is currently attempting to sublease most of its Radnor,
Pennsylvania and Blue Bell, Pennsylvania offices or terminate the related leases
on favorable terms.
ITEM 3. LEGAL PROCEEDINGS
Environmental Liabilities
ChevronTexaco Litigation
On August 13, 2002, three subsidiaries of ChevronTexaco, Inc.
(collectively, "ChevronTexaco") filed Cause No. 02-4162-JPG in the United States
District Court for the Southern District of Illinois against the Company, as
well as against two inactive subsidiaries of the Company and three unrelated
parties. The lawsuit seeks damages and declaratory relief under contractual and
statutory claims arising from environmental damage at the now dismantled Indian
Refinery. In particular, the lawsuit claims that the Company is contractually
obligated to indemnify and defend ChevronTexaco against all liability and costs,
including lawsuits, claims and administrative actions initiated by the EPA and
others, that ChevronTexaco has or will incur as a result of environmental
contamination at and around the Indian Refinery, even if that environmental
contamination was caused by Texaco, Inc. and its present and former subsidiaries
("Texaco" - now merged into ChevronTexaco) which previously owned the refinery
for over 75 years. The suit also seeks costs, damages and declaratory relief
against the Company under CERCLA, OPA and the Solid Waste Disposal Act, as
amended, ("RCRA").
History
In December 1995, IRLP 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 large portions of
the Indian Refinery to an outside party pursuant to a bankruptcy proceeding. The
outside party has substantially dismantled the Indian Refinery. American Western
filed a Liquidation Plan in 2001. American Western anticipated that the
Liquidation Plan would be confirmed in January 2002 but confirmation has been
delayed primarily because of legal challenges by Texaco, and now ChevronTexaco.
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 an area of approximately 1,000 acres, which the EPA later designated
as the Indian Refinery-Texaco Lawrenceville Superfund Site. In addition,
eighteen other parties were named including Texaco and a subsidiary of Texaco
which 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.
-5-
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.
Claims by Texaco
On August 7, 2000, the Company received notice of a claim against it and
two of its inactive refining subsidiaries from Texaco. 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 had already incurred addressing
environmental contamination at the Indian Refinery. Finally, Texaco also claimed
that the Company and two of its inactive subsidiaries were liable to Texaco
under the Federal Comprehensive Environmental Response Compensation and
Liability Act ("CERCLA") as owners and operators of the Indian Refinery. The
Company responded to Texaco disputing the factual and legal contentions 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. In October 2001, Texaco merged with
Chevron and the merged Company was named ChevronTexaco.
In May 2002, the Company received a letter from ChevronTexaco which
asserted a new claim against the Company and its subsidiaries pursuant to the
Oil Pollution Act of 1990 ("OPA") for costs and damages incurred or to be
incurred by ChevronTexaco resulting from actual or threatened discharges of oil
to navigable waters at or near the Indian Refinery. ChevronTexaco estimated
these costs and damages to be $20,500,000.
The Company's general counsel subsequently corresponded with
ChevronTexaco and the Company voluntarily provided a number of documents
requested by ChevronTexaco. In June 2002, ChevronTexaco's counsel indicated to
the Company's general counsel that ChevronTexaco did not intend to sue the
Company. Subsequently, ChevronTexaco requested additional documents from the
Company, which the Company promptly and voluntarily supplied to ChevronTexaco.
In August 2002, the Company's management and special counsel met with
legal and management representatives of ChevronTexaco in an effort to resolve
outstanding issues. At the meeting a special outside counsel of ChevronTexaco
asserted claims against the Company based upon newly expressed legal theories.
ChevronTexaco also informed the Company that residential landowners adjacent to
the Indian Refinery site had recently filed a toxic torts suit against
ChevronTexaco in Illinois state court. The meeting ended in an impasse.
Litigation
On August 13, 2002, ChevronTexaco filed the above litigation in federal
court. By letter dated August 28, 2002, ChevronTexaco tendered the Illinois
state court litigation to the Company for indemnification, but the Company
promptly responded, denying responsibility. The Company has retained Bryan Cave
LLP as trial counsel.
On October 25, 2002, the Company filed motions to dismiss as a matter of
law the contractual claims in Texaco's complaint, as well as the OPA and RCRA
claims. At the same time, the Company filed its answer to ChevronTexaco's
lawsuit on the remaining CERCLA claim. The Federal District Court has not set a
preliminary trial date for this matter due to the complexity of this matter and
the crowded docket of the Court. The Company does intend to pursue all available
opportunities for early dismissal of this matter, including requests for summary
judgement prior to trial.
The central argument to both ChevronTexaco's contractual and statutory
claims is that the Company should be treated as a "successor" and "alter ego" of
certain of its present and former subsidiaries, and thereby should be held
directly liable for ChevronTexaco's claims against those entities. ChevronTexaco
makes this argument notwithstanding the fact that the Company never directly
owned the refinery or was a party to any of the disputed contracts.
ChevronTexaco has also claimed that the Company itself directly operated the
refinery. The leading opinion in this area of the law, as issued by the U.S.
Supreme Court in June 1998 in the comparable matter of United States v.
Bestfoods, 524 U.S. 51, 118 S.Ct. 1876 (1998), supports the Company's positions.
-6-
Estimated gross undiscounted clean-up costs for this refinery are at
least $80,000,000-$150,000,000 according to public statements by Texaco to the
Company and third parties. ChevronTexaco has asserted in its contractual claim
that the Company should indemnify ChevronTexaco for all environmental
liabilities related to the Indian Refinery. If ChevronTexaco were to prevail on
this theory, the Company could be held liable for the entirety of the estimated
clean up costs, a sum far in excess of the Company's financial capability. On
the other hand, if the Company were found liable by reason of ChevronTexaco's
statutory claims for contribution and reimbursement under CERCLA and OPA, the
Company could be required to pay a percentage of the clean-up costs based on
equitable allocation factors such as comparative time of ownership and
operation, toxicity and amount of hazardous materials released, remediation
funded to date, as well as other factors. Since the Company's subsidiary only
operated the Indian Refinery five years, whereas Texaco operated it over seventy
five years the Company would expect that its share of remediation liability
would at a minimum be reduced to an amount proportional to the years of
operation by its subsidiary, although such may not be the case. Additionally,
since Texaco and its subsidiaries intentionally disposed of hazardous wastes on
site at the Indian Refinery while the Company's subsidiary arranged to remove
for offsite destruction and disposal any hazardous wastes it may have generated,
any allocation to the Company and its subsidiaries might be further reduced. As
an added factor, IRLP has already expended or contributed substantial sums to
study and remediate environmental contamination at the Indian Refinery,
including that caused by Texaco, which should be credited against any allocation
made against the Company and its subsidiaries.
The Company and its special counsel, Reed Smith LLP, believe that
ChevronTexaco's previous and current claims, including ChevronTexaco's newly
expressed legal theories, are utterly without merit and the Company intends to
vigorously defend itself against all of ChevronTexaco's claims in the litigation
and any lawsuits that may follow. In addition to the numerous defenses that the
Company has against ChevronTexaco's contractual claim for indemnity, the Company
and its special counsel believe that by the express language of the agreement
which ChevronTexaco construes to create an indemnity, ChevronTexaco has
irrevocably elected to forego all rights of contractual indemnification it might
otherwise have had against any person, including the Company.
Contingent Environmental Liabilities
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 or timing of these
matters due to inherent uncertainties. If funds for environmental clean-up are
not provided by former and/or present owners, it is possible that the Company
and/or one of its former refining subsidiaries could be held responsible or
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.
Although any environmental liabilities related to the Indian 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.
As noted above, the EPA named the Company as a potentially responsible
party for remediation of the Indian Refinery and requested and received relevant
information from the Company and ChevronTexaco has tendered the defense of a
state court toxic torts action to the Company. Whether or not the Company is
ultimately held liable in the current litigation or other proceedings, it is
probable that the Company will incur substantial legal fees and experience a
diversion of corporate resources.
Powerine
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 of Powerine. In August 1998, EMC sold
the Powerine Refinery, which it had subsequently acquired from Kenyen, to a
third party.
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 any environmental liabilities related to the Powerine Refinery
have been transferred to others, there can be no assurance that the parties
assuming such liabilities will be able to pay them. 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.
-7-
Other Litigation
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 Company's other
subsidiaries 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 plus 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 the plaintiffs' claims against the Company and its subsidiaries, as
well as CTPLP's counterclaim against the plaintiffs. The District Court issued
an amended judgment 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 and the plaintiffs subsequently filed notices of
appeal and each party submitted legal briefs with the Tyler Court of Appeals in
April 2002 and reply briefs in June and July 2002. In October 2002, the Company
and the plaintiffs argued the case before the Tyler Court of Appeals. A decision
from that court is expected in fiscal 2003.
Special counsel to the Company, Jenkens & Gilchrist, does not consider
an unfavorable outcome to this lawsuit probable. The Company's management and
general 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 were required to post a bond to cover
the gross amount of damages awarded to the plaintiffs, including interest and
attorney's fees, and to maintain that bond until the resolution of the appeal,
which may take several years. Originally, the Company and its subsidiaries
anticipated posting a bond of approximately $3,000,000 based upon the net amount
of damages but the Company and its subsidiaries later decided to post a bond of
$3,886,000 based upon the gross damages in order to avoid on-going legal
expenses and to expeditiously move the case to the Tyler Court of Appeals. The
letter of credit supporting this bond was provided by the Company's lender
pursuant to the Company's line of credit with that lender and such letter of
credit was supported by a certificate of deposit of the Company. The certificate
of deposit will remain restricted until the Long Trusts Lawsuit is adjudicated.
Having sold all of its domestic oil and gas properties, the Company no longer
has any oil and gas assets with which to collateralize the bond.
Pilgreen Litigation
As part of the oil and gas properties acquired from AmBrit in June 1999,
Castle Exploration Company, Inc., a wholly-owned subsidiary of the Company
("CECI") acquired a 10.65% overriding royalty interest ("ORRI") in the Simpson
lease in south Texas, including the Pilgreen #2ST gas well. CECI subsequently
transferred that interest to Castle Texas Oil and Gas Limited Partnership
("CTOGLP"), an indirect wholly-owned subsidiary. Because the operator suspended
revenue attributable to the ORRI from first production due to title disputes,
AmBrit, the previous owner, filed claims against the operator of the Pilgreen
well, and CTOGLP acquired rights in that litigation with respect to the period
after January 1, 1999. The Company and the operator signed an agreement to
release $282,000 of the suspended revenue attributable to CTOGLP's ORRI in the
Pilgreen well to CTOGLP subject to judicial approval. Because of a claim by
Dominion Oklahoma Texas Exploration and Production, Inc. ("Dominion") (see
below), a working interest owner in the same well, that CTOGLP's ORRI in the
Simpson lease should be deemed burdened by 3.55% overriding royalty interest,
there is still a title dispute as to approximately $151,000 of the suspended
CTOGLP Pilgreen #2ST production proceeds of which $120,000 is for the Company's
account and $31,000 is for Delta's account. (The Company sold all of its oil and
gas assets, including the Pilgreen #2ST well, to Delta on May 31, 2002.) The
Company has named Dominion as a defendant in a legal action seeking a
declaratory judgment that the Company is entitled to its full 10.65% overriding
royalty interest in the Pilgreen well. The Company believes that Dominion's
title exception to CTOGLP's overriding royalty interest is erroneous and notes
that several previous title opinions have confirmed the validity of CTOGLP's
interest.
-8-
CTOGLP has also been informed that production proceeds from an
additional well on the Simpson lease in which CTOGLP has a 5.325% overriding
royalty interest have been suspended by the court because of title disputes. The
Company intends to contest this matter vigorously. At the present time, the
amount held in escrow applicable to the additional well accruing to the
Company's interest is $66,000.
In August 2002, $282,000 was released to the Company of which $249,000
was recorded as income by the Company and the remaining $33,000 paid to Delta.
The Company's policy with respect to any amounts recovered is to record
them as income only when and if such amounts are actually received.
Dominion Litigation
On March 18, 2002, Dominion, operator of the Mitchell and Migl-Mitchell
wells in the Southwest Speaks field in south Texas and a working interest owner
in the Pilgreen #2ST well, filed suit in Texas against CTOGLP seeking
declaratory judgment in a title action that the overriding royalty interest held
by CTOGLP in these wells should be deemed to be burdened by certain other
overriding royalty interests aggregating 3.55% and should therefore be reduced
from 10.65% to 7.10%. Dominion is also seeking an accounting and refund of
payments for overriding royalty to CTOGLP in excess of the 7.10% since April
2000. The Company preliminarily estimates the amount in controversy to be
approximately $1,180,000. Dominion threatened to suspend all revenue payable to
the Company from the Mitchell and Migl-Mitchell to offset its claim. The Company
and Dominion are currently examining land and lease documents concerning the
overriding royalty interests. The Company believes that Dominion's title
exception to CTOGLP's overriding royalty interest is erroneous and notes that
several previous title opinions have confirmed the validity of CTOGLP's
interest. The Company is contesting this matter vigorously and has accordingly
made no provision for Dominion's claim in its September 30, 2002 financial
statements.
-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 2002.
-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.
2002 2001 2000
--------------- ---------------- ----------------
High Low High Low High Low
----- ----- ----- ----- ------ -----
First Quarter (December 31)........................... $7.24 $4.46 $7.73 $5.92 $ 9.67 $5.50
Second Quarter (March 31)............................. $6.99 $5.20 $6.94 $5.60 $10.56 $4.81
Third Quarter (June 30)............................... $6.85 $5.59 $6.92 $5.67 $ 6.50 $4.63
Fourth Quarter (September 30)......................... $6.82 $3.64 $6.47 $4.21 $ 7.75 $6.25
The final sale of the Company's Common Stock as reported by the NNM on
December 13, 2002 was at $4.20.
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
except for the quarter ended June 30, 2002. As with any company, the declaration
and payment of future dividends are subject to the discretion of the Company's
Board of Directors and will depend on various factors.
Approximate Number of Holders of Common Stock
As of December 13, 2002, the Company's Common Stock was held by
approximately 3,000 stockholders.
Equity Compensation Plans of the Company
Information with respect to outstanding options to acquire the Company's
stock pursuant to equity compensation plans of the Company as of September 30,
2002 is as follows:
-11-
1992 Equity
Incentive Plan Other Total
-------------- ----- -------
Shares under option...................................................... 750,000 60,000 810,000
Weighted average exercise price.......................................... $5.41 $3.79 $5.29
Shares available for future issuance under existing plans................ 937,500 0 937,500
The Company's 1992 Equity Incentive Plan was approved by shareholders
and adopted by the Company in 1993. The other options issued were not pursuant
to any plan. (See Note 16 to the consolidated financial statements included in
Item 8 of Form 10-K.)
ITEM 6. SELECTED FINANCIAL DATA
During the five fiscal years ended September 30, 2002, the Company
consummated a number of transactions affecting the comparability of the
financial information set forth below. See Note 4 to the Company's Consolidated
Financial Statements included in Item 8 of this Form 10-K.
The following selected financial data have been derived from the
Consolidated Financial Statements of the Company for each of the five years
ended September 30, 2002. The information should be read in conjunction with the
Consolidated Financial Statements and notes thereto included in Item 8 of this
Form 10-K.
For the Fiscal Year Ended September 30,
----------------------------------------------------------------
(in Thousands, except per share amounts)
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
Net sales:
Natural gas marketing and transmission ............. $50,067 $70,001
Exploration and production ......................... $ 9,445 $21,144 $17,959 $ 7,190 $ 2,603
Gross Margin:
Natural gas marketing and transmission (gas
sales less gas purchases) ........................ $19,005 $26,747
Exploration and production (oil and gas sales less
production expenses) ............................. $6,178 $13,745 $11,765 $ 4,802 $ 1,828
Income (loss) before provision for (benefit of)
income taxes........................................ ($1,017) $ 2,097 $ 2,778 $11,222 $15,260
Net income (loss) from continuing operations per share
outstanding (diluted)............................... ($.32) $.25 $.71 $.99 $1.22
Dividends declared per common shares outstanding...... $.15 $.20 $.20 $.25 $.15
September 30,
----------------------------------------------------------------
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
Total assets.......................................... $ 51,941 $59,118 $63,295 $60,796 $67,004
Long-term obligations................................. 0 0 0 0 0
Redeemable preferred stock............................ 0 0 0 0 0
Capital leases........................................ 0 0 0 0 0
Share data have been retroactively restated to reflect the 200% stock
dividend that was effective January 31, 2000.
-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. As a result, the Company
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 subsidiaries and
contingent and litigated environmental liabilities of the Company and/or its
inactive refining subsidiaries.
Fiscal 2002 versus Fiscal 2001
Exploration and Production
As noted above, the Company sold all of its domestic oil and gas properties
to Delta on May 31, 2002. As a result, the following exploration and production
financial data for the year ended September 30, 2002 represent only eight months
of revenue and expense whereas the data for the year ended September 30, 2001
represent a full twelve months of revenue and expense.
Fiscal Year Ended September 30,
-------------------------------
2002 2001
---- ----
Production Volumes:
-------------------
Barrels of crude oil (net).................................... 179,000 262,000
Mcf (thousand cubic feet) of natural gas (net)................ 2,254,000 3,083,000
Mcf equivalents (net) (mcfe) *................................ 3,328,000 4,655,000
Oil/Gas Prices:-
---------------
Crude Oil/Barrel:
-----------------
Gross $21.51 $27.39
Hedging effects............................................... ------ ------
Net of hedging ............................................... $21.51 $27.39
====== ======
Natural Gas/Mcf:
---------------
Gross $2.48 $ 4.53
Hedging effects............................................... ----- ------
Net of hedging .............................................. $2.48 $ 4.53
===== ======
Oil and Gas Production Expenses/Mcf Equivalent................ $ .98 $ 1.59
---------------------------------------------- ===== ======
- ---------------------
* Barrels of crude oil have been converted to mcf based upon relative energy
content of 6 MCF of natural gas per barrel of crude oil.
Oil and gas sales decreased approximately $5,670 from fiscal 2001 to
fiscal 2002 due to significant decreases in oil and gas prices. The average
price per mcfe decreased from $4.54/mcfe for the year ended September 30, 2001
to $2.84/mcfe for the year ended September 30, 2002. The decline in the price
received for natural gas was especially precipitous. For the year ended
September 30, 2001, the average price received per mcf of natural gas sold was
$4.53 versus only $2.48 per mcf for the year ended September 30, 2002.
Oil and gas sales decreased approximately $6,029 as a result of
decreases in oil and gas production. The production decreases were caused
primarily by the sale of the Company's domestic oil and gas properties to Delta
on May 31, 2002. From the year ended September 30, 2001 to the year ended
September 30, 2002 oil production decreased by approximately 83,000 barrels and
natural gas production decreased by 829,000 mcf.
-13-
As a result of the $5,670 decrease in oil and gas sales due to a
decrease in oil and gas prices and the $6,029 decrease due to a decrease in oil
and gas production, there was a net decrease of $11,699 or 55.3% in oil and gas
sales from the year ended September 30, 2001 to the year ended September 30,
2002.
Oil and gas production expenses decreased $4,132 or 55.8% from fiscal
2001 to fiscal 2002. A significant portion of the decrease is attributable to
the sale of the Company's domestic oil and gas properties to Delta on May 31,
2002, resulting in only eight months of production expense during the year ended
September 30, 2002 versus twelve months of production expenses during the year
ended September 30, 2001. For the year ended September 30, 2002, such expenses
were $.98 per equivalent mcf of production versus $1.59 per equivalent mcf of
production for the year ended September 30, 2001. The decrease in production
expenses per equivalent mcf is primarily attributable to a higher volume of
nonrecurring repairs and maintenance incurred during the year ended September
30, 2001 than were incurred during the year ended September 30, 2002. The higher
level of repairs and maintenance expenses incurred during the year ended
September 30, 2001 related primarily to the wells acquired from AmBrit in June
1999 since it appeared AmBrit did not repair such wells pending their sale to
the Company. Furthermore, oil and gas production expenses are typically not
incurred ratably throughout any given year but are incurred when and if certain
wells require repair and maintenance. As a result, such comparisons are more
appropriate on a multi-year basis than on an annual basis.
General and administrative expenses increased $292 or 4.9% from the year
ended September 30, 2001 to the year ended September 30, 2002. General and
administrative expenses increased $998 as a result of severance expenses
primarily related to employees who were terminated or whose compensation was
reduced as a result of the sale of the Company's oil and gas properties to
Delta. Legal fees also increased significantly as a result of the Texaco lawsuit
(see Item 3 of this Form 10-K). These increases were partially offset by
decreased insurance and compensation expenses and by $181 of non-recurring costs
incurred during the year ended September 30, 2001 related to a previous effort
by the Company to sell its oil and gas properties that terminated in December
2000 without a sale. These offsetting factors resulted in the net increase of
$292.
Depreciation, depletion and amortization decreased $319 or 9.2% from
fiscal 2001 to fiscal 2002. This net decrease consists of a decrease of $43 in
depreciation of equipment and furniture and fixtures from $122 to $79 and a $276
decrease in depletion of oil and gas properties from $3,348 to $3,072. For the
year ended September 30, 2002, the depletion rate was $.92 per mcfe versus $.72
per mcfe for the year ended September 30, 2001. The increase in the depletion
rate is indirectly attributable to the significant decreases in oil and gas
prices that occurred between the two periods being compared. The reserve reports
used to compute depletion rates are prepared annually as of September 30, the
Company's fiscal year end. As a result of lower oil and gas prices at September
30, 2001 as compared to those at September 30, 2000, the Company's economic oil
and gas reserves decreased significantly and the resultant cost per mcfe and
depletion rate per mcfe increased significantly. The Company did not cause its
reserves to be evaluated at September 30, 2002, having sold all of its domestic
oil and gas properties to Delta on May 31, 2002 (see Note 4).
Interest income decreased $484 from fiscal 2001 to fiscal 2002. The
decrease was caused by a significant decrease in the average balance of invested
cash and a decrease in the rate of interest earned on such invested cash.
The following operating items for the year ended September 30, 2002 have
no counterpart for the year ended September 30, 2001:
Gain on sale of domestic oil and gas properties $1,295
======
Loss on sale of unproved Romanian properties ($ 311)
======
The $1,295 gain recorded on the Delta sale is analyzed in Note 4 to the
consolidated financial statements included in Item 8 of this Form 10-K. The $311
loss on the sale of the unproven Romanian properties results from the Company's
sale of its remaining interest in Romania. The Company had originally intended
to participate in a wildcat well in the Black Sea but instead sold its interest
before drilling commenced. The Company has been informed that such drilling
subsequently resulted in a dry hole.
The following other income (expense) items for the year ended September
30, 2002 are primarily related to the sale of the Company's domestic oil and gas
properties to Delta at May 31, 2002 and have no counterpart during the year
ended September 30, 2001.
-14-
Impairment provision - marketable securities................................... ($ 388)
Equity in loss of Delta Petroleum Company before June 1, 2002.................. ($ 165)
Equity in loss of Delta Petroleum Company after May 31, 2002................... ($ 433)
Decrease in fair value of option granted to Delta Petroleum Corporation........ $2,250
The impairment provision for marketable securities relates to 382,289
shares of Delta's common stock acquired by the Company in September 2000. The
provision consists of a $204 impairment provision recorded in the quarter ended
March 31, 2002 and a $184 provision recorded effective May 31, 2002 to reduce
the book value of the 382,289 shares of Delta then owned by the Company to
market value prior to accounting for the Company's investment in Delta using the
equity method of accounting. The $2,250 decrease in the value of the option
granted to Delta is the result of a decrease in the fair value of the option
which, in turn, resulted from a decrease in Delta's share price. The equity in
the estimated losses of Delta represent the Company's share of Delta's estimated
losses. The loss prior to May 31, 2002 is applicable only to the 382,289 shares
of Delta owned by the Company before May 31, 2002 and approximates 3.4% of
Delta's losses for the period from October 1, 2001 to May 31, 2002. The loss
after May 31, 2002 applies to all 9,948,289 shares of Delta owned by the Company
after the closing of the Delta transaction on May 31, 2002. These shares
represent approximately 44% of Delta's outstanding shares.
The Company's equity in the loss of Network increased $77 from $99 for
the year ended September 30, 2001 to $176 for the year September 30, 2002. The
increase results from increased expenses incurred by Network, a start up company
that has not yet earned operating revenue. The Company owns 45% of Network.
The $1,085 tax provision for the year ended September 30, 2002 results
primarily because of changes in the Company's expectations that it will not
generate future taxable income. The Company increased its valuation allowance by
$1,438 at September 30, 2002, resulting in a deferred tax asset, net of $274 of
accrued income taxes on appreciation of marketable securities, of $521. The
net deferred tax asset at September 30, 2002 relates to income that has been
recognized for tax purposes, but has not yet been recognized for financial
reporting purposes.
Since November of 1996, the Company has reacquired 4,911,020 shares or
69% of its common stock (after taking into account a three for one stock split
in January 2000). As a result of these share acquisitions, earnings and losses
per outstanding share have been higher than would be the case if no shares had
been repurchased.
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
=======
-15-
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).
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
non-operator reimbursements, 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.
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).
-16-
See Note 10 to the consolidated financial statements included in Item 8
of this Form 10-K concerning the impairment of the Company's domestic oil and
gas revenues.
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
---- ----
Decrease in net deferred tax asset using 36% Federal and state blended
tax rate........................................................................ $ 808 $ 948
Change in valuation allowance.................................................... (431) (3,204)
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.
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.
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.
-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.
LIQUIDITY AND CAPITAL RESOURCES
During the year ended September 30, 2002, the Company used $3,639 from
operating activities. During the same period the Company invested $810 in oil
and gas properties and $150 in Network. At September 30, 2002, the Company had
$15,539 of unrestricted cash, $21,279 of working capital, no long-term debt and
no operating assets or operating revenues, having sold all of its domestic oil
and gas properties to Delta on May 31, 2002.
In December 2002, the Company loaned an additional $125 to Network.
At the present time the two most likely future courses of action for the
Company are liquidation and continuing to operate. As noted in previous public
filings, the most likely course of action is liquidation given the Company's
lack of operating assets and the ever-increasing regulatory, legal, accounting
and administrative costs of being a public company. The Company's Board of
Directors has not, however, formally adopted a plan of liquidation given the
recent lawsuit filed by ChevronTexaco. (See Item 3 to this Form 10-K.) The
Company's general counsel, management and special counsel believe
ChevronTexaco's claims are without merit and that ChevronTexaco is using the
legal system to disrupt the Company's business activities and to coerce the
Company to pay ChevronTexaco a settlement in order to allow the Company to
liquidate. The Company expects that it will incur significant legal costs to
defend itself against ChevronTexaco's lawsuit. The Company's management and
Board of Directors are continuously monitoring the legal situation. Since the
Company's Board of Directors has discussed but not yet formally adopted a plan
of liquidation, the future impacts of both liquidation and continuing operations
are discussed below.
LIQUIDATION
If a decision is made to liquidate, the Company anticipates that it
would distribute some cash and Delta shares to its stockholders in complete
liquidation of their stock as soon as possible while retaining sufficient assets
to reasonably provide for existing and anticipated future liabilities, including
those related to the contingent and litigated environmental claims and other
current litigation. Such provision would include the Company's $4,020
certificate of deposit provided for the letter of credit supporting its
supersedeas bond as required for the Company's appeal of the Long Trust
litigation plus interest (see Item 3 to this Form 10-K) and sufficient assets to
provide a reasonable reserve for the Company's other outstanding litigation
liabilities, if any, including any outstanding contingent environmental
litigation and other liabilities. If any net assets remain after the Company
pays or provides for such remaining liabilities, the net proceeds of such assets
would then be distributed to stockholders as a final distribution. The Company
would probably also file a no action letter with the Securities and Exchange
Commission ("SEC") seeking relief from continuing SEC reporting requirements.
Such a plan of liquidation or any other plan of liquidation would be subject to
prior approval by the Company's stockholders. The primary risks associated with
such a liquidation scenario are as follows:
a. Litigation - As noted above, the Company is a defendant in three
significant unsettled lawsuits. Although the Company does not believe
it has any material liabilities with respect to any of these
lawsuits, any or several of the plaintiffs in these lawsuits could
undertake legal actions to prevent the Company from making
liquidating distributions to its stockholders. Any resulting
litigation could not only cause the Company to incur significant
legal costs but could also delay any distributions to stockholders
for years and/or reduce or eliminate entirely such distributions. If
ChevronTexaco were to prevail on its indemnity claim in its lawsuit
(see Item 3 of this Form 10-K), ChevronTexaco's recovery could
conceivably exceed the Company's net worth and prevent liquidating
distributions to stockholders. ChevronTexaco could also conceivably
sue larger stockholders of the Company after a distribution had been
made. In addition, even if the Company's stockholders approve any
future plan of liquidation, dissident stockholders of the Company
could conceivably also take legal actions to prevent the Company from
implementing any liquidation plan.
b. Tax Risks - As a result of the Delta transaction, the Company
received 9,566,000 shares of Delta's common stock in addition to the
382,289 shares of Delta common stock it previously owned. If Delta's
stock price increases before any distribution to stockholders, the
Company could be subject to federal and state income tax at the
corporate level on the interim appreciation of Delta's stock if the
Company's remaining tax carryforwards are not sufficient to offset
income taxes on such appreciation. Under such circumstance the tax
treatment is the same as if the Company had sold its Delta shares for
their fair market value and then distributed the proceeds to its
stockholders. Such could be the case if there are delays in making
distributions to stockholders and Delta's stock price increases in
the interim. Any resulting gain would essentially constitute phantom
income to the Company since the Company would realize a taxable gain
without receiving any related proceeds.
-18-
c. Continuing Public Company Administrative Burden - If the Company's
directors decide to liquidate, the Company will probably seek relief
from most of its public company reporting requirements. If such a
request is denied by the SEC, the Company would continue incurring
the costs of being a public company while having no operating
revenues to absorb such costs. Such costs are significant and
probably will increase in the future given the myriad of post Enron
regulatory requirements that are currently being mandated. The result
would be a diminution of assets available for distribution to
stockholders.
d. Lack of Liquidity - If the Company's directors decide to liquidate
and the related plan of liquidation is approved by the Company's
stockholders, it is likely that the Company's stock would cease to
trade after the plan of liquidation is filed. In such a case,
stockholders would not be able to trade their stock. Stockholders who
have used their Company stock as collateral for margin loans would
probably be required to provide other collateral to support such
loans. Even if the Company is able to distribute Delta stock as part
of its initial distribution to stockholders without any legal
challenges or other delays, there could be a delay between the date
the Company's stock is delisted and the date when the Company's
stockholders receive Delta shares that could be substituted as
collateral for a margin loan. Stockholders would presumably have to
provide other collateral in the interim.
e. Liquidation of Assets - The Company's primary remaining assets
consist of cash and cash equivalents and the Company's investments in
Penn Octane Corporation (1,343,000 shares) and Delta (9,948,289
shares). Although all of the Company's shares of Delta have recently
been registered and most of the Company's shares of Penn Octane are
already registered, both Penn Octane and Delta are small, thinly
capitalized companies with small trading volumes and the Company may
not be able to sell its Penn Octane stock and/or its Delta stock for
their listed market prices if the Company needs cash to distribute to
its stockholders or to liquidate liabilities. In addition, the
Company owns 45% of Network. Network is a private limited liability
company with no public market for its membership units. As a result,
the Company expects that it would be difficult at the present time to
sell its interest in Network if liquidation is required.
CONTINUING TO OPERATE
If the Company does not liquidate but instead continues to operate, the
Company would still be subject to several of the risks noted above, including
litigation risk, the continuing public company administrative burden, the lack
of liquidity and liquidation of asset risk (if the Company decides to liquidate
its remaining assets). The Company estimates that its annual general and
administrative costs, if it continues to exist as a public company, would be
$700-$900, excluding litigation - related legal costs. In addition, the Company
would lack operating assets, operating personnel (since most of its personnel
have already been severed) and a business to operate. Under such circumstances,
the Company would be subject to many competitive disadvantages if it again
decides to acquire energy assets or other assets and businesses. For example,
few analysts believe it is possible to acquire oil and gas properties at
favorable prices at the present time or in the near future given current high
prices for oil and gas production and reserves. Many energy companies have more
financial resources than the Company and could easily outbid the Company in such
an acquisition scenario. Furthermore, failure by the Company to be engaged
primarily in a business other than that of investing, reinvesting, owning,
holding or trading in securities within one year following closing of the sale
to Delta could subject the Company to federal regulation under the Investment
Company Act of 1940, and this would result in even more significant regulatory
compliance costs and obligations.
In addition, if the Company continues to operate, it would continue to
be subject to the following risk factors:
a. Contingent and litigated environmental liabilities (see Item 3 to
this Form 10-K).
b. Public market for Company's stock - the small trading volumes in the
Company's stock may create liquidation problems for large investors
in the Company.
c. Other risks including general business risks, insurance claims
against the Company in excess of insurance coverage, tax liabilities
resulting from tax audits and litigation risk.
-19-
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The Company currently owns no oil or gas reserves and is thus no longer
directly subject to market risks with respect to oil and gas prices.
At September 30, 2002 and December 13, 2002, the Company owned 9,948,289
shares of Delta and 1,343,600 shares of Penn Octane. Both Delta and Penn Octane
are thinly traded public companies with small market capitalizations. The stock
price of each company has fluctuated significantly in the last three years and
thus the Company's investments in Delta and Penn Octane remain subject to
significant changes in the market prices of these stocks and limited liquidity.
INFLATION AND CHANGING PRICES
The Company currently has no active business and thus does not expect
inflation and changing prices to affect its future results of operations in a
material manner.
NEW ACCOUNTING PRONOUNCEMENTS
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 adopted SFAS No. 142 on
October 1, 2002. The Company does not expect that its adoption of SFAS No. 142
will have a material effect on its future financial position or 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 this statement effective October 1,
2002. The Company does not expect that adoption of this statement will have a
material effect on its future financial position or results of operations.
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 adopted SFAS No 144 effective
October 1, 2002. The Company does not expect that adoption of this statement
will have a material effect on its future financial position or results of
operations.
Statement of Financial Accounting Standards No. 145, Recission of FASB
Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections ("SFAS No. 145") was issued in April 2002. This statement rescinds
SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt, which
required all gains and losses from extinguishment of debt to be aggregated and,
if material, classified as an extraordinary item, net of income taxes. As a
result, the criteria in Accounting Principles Board No. 30 ("APB 30") will now
be used to classify those gains and losses. Any gain or loss on the
extinguishment of debt that was classified as an extraordinary item in prior
periods presented that does not meet the criteria in APB 30 for classification
as an extraordinary item shall be reclassified. The provisions of this Statement
are effective for fiscal years beginning after January 1, 2003 and the Company
expects to adopt SFAS No. 145 on October 1, 2003. The Company does not expect
that adoption of this statement will have a material effect on its future
financial position or results of operations.
Statement of Financial Accounting Standards No. 146, Accounting for Exit
or Disposal Activities ("SFAS No. 146"), was issued in June 2002. SFAS No. 146
addresses significant issues regarding the recognition, measurement and
reporting of disposal activities, including restructuring activities that are
currently accounted in EITF Issue No. 94-3, "Liability Recognition for Certain
Employee Termination Activity." The provisions of SFAS 146 are effective for
exit or disposal activities initiated after December 31, 2002.
-20-
CRITICAL ACCOUNTING POLICIES:
The accounting policies critical to the Company in the future, are as
follows:
Equity Method of Accounting
The Company currently owns approximately 44% of Delta and accounts for
its investment in Delta using the equity method of accounting. Under this
method, the Company is required to increase its investment in Delta by its share
of Delta's income and decrease such investment by its share of Delta's losses
and any distributions from Delta. If Delta incurs future losses, the Company
would thus include its share of such losses in its consolidated statement of
operations. In addition, the Company estimates that its investment in Delta
exceeded the Company's proportional share of Delta's equity by approximately
$6,900 at closing. The Company has allocated such excess to Delta's ownership
interests in offshore California leases and the related potential recovery from
a lawsuit Delta and other owners of offshore California leases have instituted
against the United States for breach of contract. The Company will be required
to evaluate the recoverability of the leases periodically and write them off or
reduce them to the extent it is not deemed recoverable. In addition, if Delta
incurs recurring losses in the future and/or the market value of its stock
declines significantly, the Company's investment in Delta may be impaired and
the Company may then be required to recognize the impairment.
Discontinued Refining Operations
At September 30, 2002, the Company had recorded net refining liabilities
retained of $3,016 and an estimated value of discontinued net refining assets of
$612 resulting in a recorded net liability of $2,406. As noted in Note 13 to the
consolidated financial statements included in Item 8 to this Form 10-K.
ChevronTexaco has sued the Company for environmental remediation costs that have
been estimated at $80,000-$150,000. The Company's accounting policy with respect
to contingent environmental liabilities is to record environmental liabilities
when and if environmental assessment and/or remediation costs are probable and
can be reasonably estimated. Although the Company and its special counsel
believe that ChevronTexaco's claims are utterly without merit, the Company would
be required to record additional environmental liabilities if it becomes
probable that the Company will incur liabilities related to ChevronTexaco's
claims or other environmental liabilities and such liabilities exceed $2,404. As
noted above, if such liabilities exceed the value of the Company's assets, the
Company would not have the financial capability to pay such liabilities. The
Company has classified the estimated realizable value of discontinued net
refining assets and net refining liabilities retained as non current because it
appears that these items will not be realized in the next year given the recent
lawsuit filed against the Company by ChevronTexaco (see Item 3 to this Form
10-K). The amounts and classification of the estimated values of discontinued
net refining assets and net refining liabilities retained could change
significantly in the future as a result of litigation or other factors.
Future Distributions to Stockholders, If Any
If the Company's Board of Directors decides to liquidate the Company, it
is probable that the related plan of liquidation would contemplate distributions
to stockholders of shares of Delta common stock and perhaps of other assets of
the Company. If the Company distributes Delta stock or other assets to
stockholders, the Company will first adjust the book value of the assets to be
distributed to their fair market values, if appropriate, for an indicated
impairment of value, recognizing the resultant loss. The Company would then
record the distribution as a charge to retained earnings equal to the book value
of the assets being distributed.
Changes in the Value Allocated to the Delta's Repurchase Option
As part of the Delta sale, the Company granted Delta an option to
repurchase up to 3,188,667 of its shares for $4.50/share until May 31, 2003. At
closing on May 31, 2002, the Company valued that option at $2,682 using the
Black Scholes method. The Company will be required to account for changes in the
value of this option by recording gains or losses, as applicable, in its
Statement of Operations. At September 30, 2002, the value of option had been
reduced to $432 and the Company had recorded a $2,250 gain. If the option
expires by its own terms or is only partially exercised at expiration, the
Company would then record a gain equal to the remaining book value of the
unexercised options. If Delta exercises the option the Company would record a
gain per share exercised equal to the difference between $4.50 and the book
value per share at the time of exercise.
-21-
Valuation Allowance for Deferred Income Tax Asset
At September 30, 2002, the Company recorded a valuation allowance of
$4,997 offsetting its gross deferred tax asset of $5,792 at that date. That
valuation allowance is based upon the Company's assessment that the Company will
not generate future taxable income to utilize all of its gross deferred tax
assets at September 30, 2002 based on the Company's expectations that it will
incur significant general and administrative expenses liquidating its assets
without earning offsetting revenue. In addition, the Company is a party to
several lawsuits including a complaint for environmental indemnification for
which the Company has recorded no liability. The net deferred tax asset at
September 30, 2002 relates to income that has been recognized for tax purposes
but has not yet been recognized for financial reporting purposes. If
circumstances change such that the Company expects future taxable income, the
Company will revise its valuation allowance, resulting in tax recoveries.
RECENT SALES OF UNREGISTERED SECURITIES: NOT APPLICABLE
-22-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
----
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Statements of Operations for the Years Ended September 30, 2002, 2001 and 2000................ 24
Consolidated Balance Sheets as of September 30, 2002 and 2001.............................................. 25
Consolidated Statements of Cash Flows for the Years Ended September 30, 2002, 2001 and 2000................ 26
Consolidated Statements of Stockholders' Equity and Other Comprehensive Income for the Years
Ended September 30, 2002, 2001 and 2000............................................................. 28
Notes to the Consolidated Financial Statements............................................................. 29
INDEPENDENT AUDITORS' REPORT............................................................................... 61
All other schedules are omitted because they are not applicable or the
required information is shown in the financial statements or notes thereto.
-23-
CASTLE ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
("$000's" Omitted Except Share and Per Share Amounts)
Year Ended September 30,
----------------------------------------
2002 2001 2000
---- ---- ----
Revenues:
Oil and gas sales................................................... $ 9,445 $ 21,144 $ 17,959
Gain on sale of domestic oil and gas properties..................... 1,295
---------- ---------- ----------
10,740 21,144 17,959
---------- ---------- ----------
Expenses:
Oil and gas production.............................................. 3,267 7,399 6,194
General and administrative.......................................... 6,289 5,997 5,755
Depreciation, depletion and amortization............................ 3,151 3,470 3,209
Impairment of unproved properties (Romania)......................... 2,765 832
Loss on sale of unproven Romanian properties........................ 311
---------- ---------- ----------
13,018 19,631 15,990
---------- ---------- ----------
Operating income (loss)................................................. (2,278) 1,513 1,969
---------- ---------- ----------
Other income (expense):
Interest income..................................................... 157 641 784
Other income........................................................ 16 42 25
Impairment provision - marketable securities........................ (388)
Decrease in fair value of option granted to Delta
Petroleum Corporation ........................................... 2,250
Equity in loss of Networked Energy LLC.............................. (176) (99)
Equity in loss of Delta Petroleum Corporation
before June 1,2002............................................... (165)
Equity in estimated loss of Delta Petroleum Corporation
after May 31, 2002............................................... (433)
---------- ---------- ----------
1,261 584 809
---------- ---------- ----------
Income (loss) before provision for (benefit of) income taxes............ (1,017) 2,097 2,778
---------- ---------- ----------
Provision for (benefit of) income taxes:
State............................................................. 30 11 (64)
Federal........................................................... 1,055 370 (2,227)
---------- ---------- ----------
1,085 381 (2,291)
---------- ---------- ----------
Net income (loss)....................................................... ($ 2,102) $ 1,716 $ 5,069
========== ========== ==========
Net income (loss) per share:
Basic............................................................. ($ .32) $ .26 $ .73
========== ========== ==========
Diluted........................................................... ($ .32) $ .25 $ .71
========== ========== ==========
Weighted average number of common and potential dilutive common shares
outstanding:
Basic............................................................. 6,629,376 6,643,724 6,939,350
========== ========== ==========
Diluted........................................................... 6,744,900 6,818,855 7,102,803
========== ========== ==========
The accompanying notes are an integral part of these consolidated financial statements
-24-
CASTLE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
("$000's" Omitted Except Share and Per Share Amounts)
September 30,
-------------------------
2002 2001
---- ----
ASSETS
Current assets:
Cash and cash equivalents......................................................... $ 15,539 $ 5,844
Restricted cash................................................................... 4,230 370
Accounts receivable............................................................... 108 2,787
Marketable securities............................................................. 3,046 6,722
Prepaid expenses and other current assets......................................... 197 277
Estimated realizable value of discontinued net refining assets.................... 612
Deferred income taxes............................................................. 429 1,879
-------- --------
Total current assets............................................................ 23,549 18,491
Estimated realizable value of discontinued net refining assets........................ 612
Property, plant and equipment, net:
Natural gas transmission.......................................................... 51
Furniture, fixtures and equipment................................................. 153 222
Oil and gas properties, net (full cost method):
Proved properties (United States)............................................... 39,843
Unproved properties not being amortized (Romania)............................... 110
Investment in Networked Energy LLC.................................................... 375 401
Investment in Delta Petroleum Corporation............................................. 26,886
Deferred income taxes................................................................. 366
-------- --------
Total assets.................................................................... $ 51,941 $ 59,118
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Dividend payable.................................................................. $ 330 $ 331
Accounts payable.................................................................. 413 3,543
Accrued expenses.................................................................. 821 292
Accrued taxes on appreciation of marketable securities............................ 274 900
Fair value of options granted to Delta Petroleum Corporation...................... 432
Net refining liabilities retained................................................. 3,016
-------- --------
Total current liabilities....................................................... 2,270 8,082
Net refining liabilities retained..................................................... 3,016
Long-term liabilities................................................................. 11 9
-------- --------
Total liabilities............................................................... 5,297 8,091
-------- --------
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, 2002 and 2001......................... 5,752 5,752
Additional paid-in capital........................................................ 67,365 67,365
Accumulated other comprehensive income - unrealized gains on marketable
securities, net of taxes........................................................ 487 1,600
Retained earnings................................................................. 39,707 42,816
-------