<PAGE>
===============================================================================
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                              --------------------

                                Amendment No. 1

                                       to

                                    FORM 10-K

           |X|  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934

                  For the fiscal year ended September 30, 2001

                                       OR

            |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                      THE SECURITIES EXCHANGE ACT OF 1934

      For the transition period from _______________ to _________________

                        Commission file number: 0-10990

                           CASTLE ENERGY CORPORATION
             (Exact name of registrant as specified in its charter)

<TABLE>
<CAPTION>
<S>                                    <C>
              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
  (Address of principal executive                                   19087
              offices)                                            (Zip Code)
</TABLE>


                 Registrant's telephone number: (610) 995-9400

        Securities registered pursuant to Section 12(b) of the Act: None

          Securities registered pursuant to Section 12(g) of the Act:

               Common Stock -- $.50 par value and related Rights

                              --------------------

    Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes |X| No |_|

    Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. |X|.

    As of December 14, 2001, there were 6,632,884 shares of the registrant's
Common Stock ($.50 par value) outstanding. The aggregate market value of
voting stock held by non-affiliates of the registrant as of such date was
$29,637,835 (5,049,035 shares at $5.87 per share).

                      DOCUMENTS INCORPORATED BY REFERENCE:

    Portions of the Proxy Statement for the 2002 Annual Meeting of
Stockholders are incorporated by reference in Items 10, 11, 12 and 13.
===============================================================================

<PAGE>
                           CASTLE ENERGY CORPORATION
                                 2001 FORM 10-K
                               TABLE OF CONTENTS


<TABLE>
<CAPTION>
Item                                                                                                              Page
----                                                                                                              ----
<S>          <C>                                                                                                  <C>
                                                               PART I
                                                               ------
1. and 2.    Business and Properties .............................................................................   3
       3.    Legal Proceedings ...................................................................................   8
       4.    Submission of Matters to a Vote of Security Holders .................................................  11

                                                              PART II
                                                              -------
       5.    Market for the Registrant's Common Equity and Related Stockholder Matters ...........................  12
       6.    Selected Financial Data .............................................................................  12
       7.    Management's Discussion and Analysis of Financial Condition and Results of Operations ...............  14
       8.    Financial Statements and Supplementary Data .........................................................  27
       9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ................  60

                                                              PART III
                                                              --------
      10.    Directors and Executive Officers of the Registrant ..................................................  61
      11.    Executive Compensation ..............................................................................  61
      12.    Security Ownership of Certain Beneficial Owners and Management ......................................  61
      13.    Certain Relationships and Related Transactions ......................................................  61

                                                               PART IV
                                                               -------
      14.    Exhibits, Financial Statement Schedules, and Reports on Form 8-K ....................................  62
</TABLE>



                                       2

<PAGE>
                                     PART I


ITEMS 1. AND 2. BUSINESS AND PROPERTIES

                                  INTRODUCTION

    All statements other than statements of historical fact contained in this
report are forward-looking statements. Forward-looking statements in this
report generally are accompanied by words such as "anticipate," "believe,"
"estimate," or "expect" or similar statements. Although the Company believes
that the expectations reflected in such forward-looking statements are
reasonable, no assurance can be given that such expectations will prove
correct. Factors that could cause the Company's results to differ materially
from the results discussed in such forward-looking statements are disclosed in
this report, including without limitation in conjunction with the expected
cash sources and expected cash uses discussed below. All forward-looking
statements in this Form 10-K are expressly qualified in their entirety by the
cautionary statements in this paragraph.

    Castle Energy Corporation (the "Company") is currently engaged in oil and
gas exploration and production in the United States and Romania. References to
the Company mean Castle Energy Corporation, the parent, and/or one or more of
its subsidiaries. Such references are for convenience only and are not
intended to describe legal relationships. During the period from August of
1989 through September 30, 1995, the Company, through certain subsidiaries,
was primarily engaged in petroleum refining. Indian Refining I Limited
Partnership (formerly Indian Refining Limited Partnership) ("IRLP"), an
indirect wholly-owned subsidiary of the Company, owned the Indian Refinery, an
86,000 barrel per day (B/D) refinery located in Lawrenceville, Illinois
("Indian Refinery"). Powerine Oil Company ("Powerine"), a former indirect
wholly-owned subsidiary of the Company, owned and operated a 49,500 B/D
refinery located in Santa Fe Springs, California ("Powerine Refinery").
By September 30, 1995, the Company's refining subsidiaries had terminated and
discontinued all of their refining operations. For accounting purposes,
refining operations were classified as discontinued operations in the
Company's Consolidated Financial Statements as of September 30, 1995 (see Note
3 to the consolidated financial statements included in Item 8 of this
Form 10-K).

    During the period from December 31, 1992 to May 31, 1999, the Company,
through two of its subsidiaries, was also engaged in natural gas marketing and
transmission operations. During this period one of the Company's subsidiaries
sold natural gas to Lone Star Gas Company ("Lone Star") under a long-term gas
sales contract. The subsidiaries also entered into two long-term gas sales
contracts and one long-term gas supply contract with MG Natural Gas Corp.
("MGNG"), a subsidiary of MG Corp. ("MG"), whose parent is Metallgesellschaft
A.G. ("MGAG"), a large German conglomerate. All of the subsidiaries' gas
contracts terminated on May 31, 1999. The Company has not replaced these
contracts because it sold its pipeline assets to a subsidiary of Union Pacific
Resources Corporation ("UPRC") in May 1997 and because it was unable to
negotiate similar profitable long-term contracts since most gas purchasers now
buy gas on the spot market. The Company is currently operating exclusively in
the exploration and production segment of the energy industry.

    From inception to the present, the Company continues to operate in the
exploration and production segment of the energy business. During the fiscal
years ended September 30, 2001, 2000 and 1999 the Company invested
$15,449,000, $11,226,000 and $23,964,000 respectively, in oil and gas property
acquisition, exploration and development, including $3,707,000 in Romania. The
Company is currently planning to participate in the drilling of a wildcat well
in the Black Sea in the spring or early summer of 2002. As of September 30,
2001, the Company's exploration and production subsidiaries owned interests in
522 producing oil and gas wells located in fourteen states. Of these
interests, 430 were working interests, where the Company is responsible for
operating costs applicable to the well, and 92 were royalty interests, where
the Company bears no expense burden. The subsidiaries operate approximately
half of the wells that are working interests. At September 30, 2001, the
Company's exploration and production assets included proved reserves of
approximately 31 billion cubic feet of natural gas and approximately 3,400,000
barrels of oil.

    In July 2000, the Company engaged Energy Spectrum Advisors of Dallas,
Texas to advise the Company concerning strategic alternatives including the
possible sale of its oil and gas assets. In December 2000, several companies
submitted bids for the Company's domestic oil and gas assets. The total of the
highest bids for all of the Company's properties aggregated approximately
$48,000,000 with an effective date of October 1, 2000. The Company's Board of
Directors decided not to sell its oil and gas assets at the prices offered.

    In August 2000, the Company purchased thirty-five percent (35%) of the
membership interests of Networked Energy LLC ("Network") for $500,000 because
the type of energy services Networked provides appears to be a potential
growth market with significant upside potential. Network is a private company
engaged in the planning, installation and operation of natural gas fueled
energy generating facilities that supply power,

                                       3

<PAGE>
heating and cooling services directly to retail customers with significant
energy consumption to reduce their energy costs - especially during peak usage
periods. Although Networked is not in the exploration and production business,
it is in a line of the energy business related to that of the Company as the
prime fuel for the generators it installs is natural gas.

    On December 11, 2001, the Company entered into a letter of intent to sell
all of its domestic oil and gas assets to Delta Petroleum Company ("Delta")
for $20,000,000 cash and 9,566,000 shares of common stock of Delta, which
during calendar 2002 has closed between $3.35 and $4.48 per share as of March
22, 2002. The effective date of the sale is October 1, 2001 and the expected
closing date is April 30, 2002 or later. The sale is subject to execution of a
definitive purchase and sale agreement by both parties, approval of the
transaction by the boards of directors of the Company and Delta and approval
by Delta's shareholders of the issuance of the Delta shares to Castle.

    In October 1996, the Company commenced a program to repurchase shares of
its common stock at stock prices beneficial to the Company. At December 14,
2001, 4,871,020 shares, representing approximately 69% of previously
outstanding shares, had been repurchased and the Company's Board of Directors
has authorized the purchase of up to 396,946 additional shares.

                     OIL AND GAS EXPLORATION AND PRODUCTION

General

    On June 1, 1999, the Company consummated the purchase of all of the oil
and gas properties of AmBrit Energy Corp. ("AmBrit"). The oil and gas
properties purchased include interests in approximately 180 oil and gas wells
in Alabama, Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Texas and
Wyoming, as well as undrilled acreage in several of these states. The
effective date of the sale was January 1, 1999. The adjusted purchase price
after accounting for all transactions between the effective date, January 1,
1999, and the closing date was $20,170,000. The entire adjusted purchase price
was allocated to "Oil and Gas Properties - Proved Properties". Based upon
reserve reports initially prepared by the Company's petroleum reservoir
engineers, the proved reserves (unaudited) associated with the AmBrit oil and
gas assets approximated 2,000,000 barrels of crude oil and 12,500,000 mcf
(thousand cubic feet) of natural gas, which, together, approximated 150% of
the Company's oil and gas reserves before the acquisition. In addition, the
production acquired initially increased the Company's consolidated production
by approximately 425%.

    In fiscal 1999, the Company entered into two drilling ventures to
participate in the drilling of up to sixteen exploratory wells in south Texas.
During fiscal 2000, the Company participated in the drilling of nine
exploratory wells pursuant to the related joint venture operating agreements.
Eight wells drilled resulted in dry holes and one well was completed as a
producer. The Company has no further drilling obligations under these joint
ventures and has terminated participation in each drilling venture. The total
cost incurred to participate in the drilling of the exploratory wells was
$6,003,000.

    In December 1999, a subsidiary of the Company purchased majority interests
in twenty-six offshore Louisiana wells from Whiting Petroleum Company
("Whiting"), a public company engaged in oil and gas exploration and
development. The adjusted purchase price was $890,000.

    In September 2000, the subsidiary sold its interests in the offshore
Louisiana wells to Delta. The effective date of the sale was July 1, 2000. The
adjusted purchase price of $3,059,000 consisted of $1,122,000 cash plus
382,289 shares of Delta's common stock valued at the closing market price of
$1,937,000 (see Note 8 to the Company's Consolidated Financial Statements
included in Item 8 of this Form 10-K).

    In April 1999, the Company purchased an option to acquire a fifty percent
(50%) interest in three oil and gas concessions granted to a subsidiary of
Costilla Energy Corporation ("Costilla"), a public oil and gas exploration and
production company, by the Romanian government. The Company paid Costilla
$65,000 for the option. In May 1999, the Company exercised the option. As of
September 30, 2001, the Company had participated in the drilling of five
wildcat wells in Romania. Four of those wells resulted in dry holes. Although
the fifth well produced some volumes of natural gas when tested, the Company
has not been able to obtain a sufficiently high gas price to justify future
production and has elected at the present time not to undertake an offset
drilling program in the acreage surrounding the fifth well. The Company has
agreed to participate in the drilling of a sixth well in the Black Sea in the
spring or early summer of 2002. Specific risks for oil and gas exploration in
Romania include the lack of availability of certain types of drilling rigs,
language difficulties in negotiating drilling contracts, the difficulty
ascertaining the environmental regulations governing drilling in the Black
Sea, different drilling procedures and methods used by foreign drilling
contractors, difficulties in obtaining

                                       4

<PAGE>
high quality drilling supplies and parts, cement and fluids, the possibility
of retroactive tax assessment or other levies by foreign governments,
governmental and regulatory procedures with which the Company is not familiar
and the risk of political interference in drilling activities.

    In November and December 1999, the Company acquired additional outside
interests in several Alabama and Pennsylvania wells, which it operates, for
$2,580,000.

    On April 30, 2001, the Company consummated the purchase of several East
Texas oil and gas properties from a private company. The effective date of the
purchase was April 1, 2001. These properties included majority interests in
twenty-one (21) operated producing oil and gas wells and interests in
approximately 6,500 gross acres in three counties in East Texas. The Company
estimated the proved reserves acquired to be approximately 12.5 billion cubic
feet of natural gas and 191,000 barrels of crude oil. The consideration paid,
net of purchase price adjustments, was $10,040,000. The Company used its own
internally generated funds to make the purchase.

Properties

Proved Oil and Gas Reserves

    The following is a summary of the Company's oil and gas reserves as of
September 30, 2001. All estimates of reserves are based upon engineering
evaluations prepared by the Company's independent petroleum reservoir
engineers, Huntley & Huntley and Ralph E. Davis Associates, Inc., in
accordance with the requirements of the Securities and Exchange Commission.
Such estimates include only proved reserves. The Company reports its reserves
annually to the Department of Energy. The Company's estimated reserves as of
September 30, 2001 were as follows:
<TABLE>
<CAPTION>

<S>                                                                   <C>
Net MCF(1) of gas:
    Proved developed ..............................................   26,480,000
    Proved undeveloped ............................................    4,212,000
                                                                      ----------
    Total .........................................................   30,692,000
                                                                      ==========
Net barrels of oil:
    Proved developed ..............................................    1,890,000
    Proved undeveloped ............................................    1,119,000
                                                                      ----------
    Total .........................................................    3,009,000
                                                                      ==========
</TABLE>

---------------

        (1) Thousand cubic feet

Oil and Gas Production

    The following table summarizes the net quantities of oil and gas
production of the Company for each of the three fiscal years in the period
ended September 30, 2001, including production from acquired properties since
the date of acquisition.
<TABLE>
<CAPTION>

                                                Fiscal Year Ended September 30,
                                              ----------------------------------
                                                 2001        2000         1999
                                                 ----        ----         ----
    <S>                                       <C>          <C>         <C>
    Oil - Bbls (barrels) ..................     262,000      279,000     124,000
    Gas - MCF .............................   3,083,000    3,547,000   1,971,000
</TABLE>


Average Sales Price and Production Cost Per Unit

    The following table sets forth the average sales price per barrel of oil
and MCF of gas produced by the Company, including hedging adjustments, and the
average production cost (lifting cost) per equivalent unit of production for
the periods indicated. Production costs include applicable operating costs and
maintenance costs of support equipment and facilities, labor, repairs,
severance taxes, property taxes, insurance, materials, supplies and fuel
consumed in operating the wells and related equipment and facilities.


                                       5

<PAGE>
<TABLE>
<CAPTION>

                                                           Fiscal Year Ended
                                                             September 30,
                                                       -------------------------
                                                        2001      2000     1999
                                                        ----      ----     ----
    <S>                                                <C>       <C>      <C>
    Average Sales Price per Barrel of Oil ............ $27.39    $27.94   $18.36
    Average Sales Price per MCF of Gas ............... $ 4.53    $ 2.87   $ 2.25
    Average Production Cost per Equivalent MCF(1) .... $ 1.59    $ 1.19   $  .70
</TABLE>

---------------

        (1) For purposes of equivalency of units, a barrel of oil is assumed
            equal to six MCF of gas, based upon relative energy content.

    No production was hedged in fiscal 2001.

    The average sales price per barrel of crude oil decreased $4.64 per barrel
for the year ending September 30, 2000 and increased $.11 per barrel for the
year ended September 30, 1999 as a result of hedging. The average sales price
per mcf (thousand cubic feet) of natural gas decreased $.07 for each of the
years ended September 30, 2000 and 1999 as a result of hedging. Oil and gas
sales were not hedged after July 2000.

Productive Wells and Acreage

    The following table presents the oil and gas properties in which the
Company held an interest as of September 30, 2001. The wells and acreage owned
by the Company and its subsidiaries are located primarily in Alabama,
California, Illinois, Louisiana, Mississippi, Montana, New Mexico, Oklahoma,
Pennsylvania, Texas and Wyoming.
<TABLE>
<CAPTION>
                                                                     As of
                                                              September 30, 2001
                                                              ------------------
                                                              Gross(2)    Net(3)
                                                              --------   -------
    <S>                                                       <C>        <C>
    Productive Wells:(1)
    Gas Wells .............................................        521       203
    Oil Wells .............................................        103        49

    Acreage:
    Developed Acreage .....................................    129,517    31,351
    Undeveloped Acreage ...................................     85,686    29,678
</TABLE>

    In addition, one of the Company's subsidiaries has a fifty percent
interest in approximately 3,100,000 gross undeveloped acres in Romania
(approximately 1,550,000 net acres).

---------------
        (1) A "productive well" is a producing well or a well capable of
            production. Fifty-nine wells are dual wells producing oil and gas.
            Such wells are classified according to the dominant mineral being
            produced.

        (2) A gross well or acre is a well or acre in which a working interest
            is owned. The number of gross wells is the total number of wells
            in which a working interest is owned.

        (3) A net well or acre is deemed to exist when the sum of fractional
            working interests owned in gross wells or acres equals one. The
            number of net wells or acres is the sum of the fractional working
            interests owned in gross wells or acres.

Drilling Activity

    The table below sets forth for each of the three fiscal years in the
period ended September 30, 2001 the number of gross and net productive and dry
developmental wells drilled, including wells drilled on acquired properties
since the dates of acquisition.


                                       6

<PAGE>

<TABLE>
<CAPTION>

                                                                  Fiscal Year Ended September 30,
                                 --------------------------------------------------------------------------------------------------
                                                 2001                                     2000                           1999
                                 -------------------------------------    -------------------------------------    ----------------
                                  United States           Romania           United States          Romania          United States
                                 ----------------    -----------------    -----------------    ----------------    ----------------
                                Productive    Dry   Productive    Dry    Productive    Dry    Productive    Dry    Productive   Dry
                                ----------    ---   ----------    ---    ----------    ---    ----------    ---    ----------   ---
<S>                             <C>           <C>   <C>           <C>    <C>           <C>    <C>           <C>    <C>          <C>
Developmental:
Gross .......................       17          4       --         --          9                  --         --         5         3
Net .........................        4        1.3       --         --        4.5                  --         --       2.3       1.2
Exploratory:
Gross .......................                           --          3*         1           8      --         2         --        --
Net .........................                           --        1.5*        .5        3.75      --         1         --        --
</TABLE>


    All wells drilled by the Company in fiscal 1999 were drilled in the United
States.
---------------

        *   One well, in which the Company has a fifty percent (50%) interest,
            produced some volumes of natural gas when tested but the Company
            has not been able to obtain a price for its production that makes
            future operations economical.

                                  REGULATIONS

    Since the Company's subsidiaries have disposed of their refineries and
third parties have assumed environmental liabilities associated with the
refineries, the Company's current activities are not subject to environmental
regulations that generally pertain to refineries, e.g., the generation,
treatment, storage, transportation and disposal of hazardous wastes, the
discharge of pollutants into the air and water and other environmental laws.
Nevertheless, the Company has some contingent environmental exposures. See
Items 3 and 7 and Note 12 to the consolidated financial statements included in
Item 8 of this Form 10-K.

    The oil and gas exploration and production operations of the Company are
subject to a number of local, state and federal environmental laws and
regulations. To date, compliance with such regulations by the Company's
natural gas marketing and transmission and exploration and production
subsidiaries has not resulted in material expenditures.

    Most states in which the Company conducts oil and gas exploration and
production activities have laws regulating the production and sale of oil and
gas. Such laws and regulations generally are intended to prevent waste of oil
and gas and to protect correlative rights and opportunities to produce oil and
gas as between owners of interests in a common reservoir. Most states also
have regulations requiring permits for the drilling of wells and regulations
governing the method of drilling, casing and operating wells, the surface use
and restoration of properties upon which wells are drilled and the plugging
and abandonment of wells. In recent years there has been a significant
increase in the amount of state regulation, including increased bonding,
plugging and operational requirements. Such increased state regulation has
resulted in, and is anticipated to continue to result in, increased legal and
compliance costs being incurred by the Company. Based on past costs and even
considering recent increases, management of the Company does not believe such
legal and compliance costs will have a material adverse effect on the
financial condition or results of operations of the Company although
compliance requirements continue to absorb an increasing percentage of
management's time.

    The Company plans to participate in the drilling of a wildcat well in the
Black Sea in the spring or early summer of 2002. Participation in the drilling
of this well will expose the Company to several risks not commonly associated
with the Company's domestic onshore operations including drilling offshore,
using foreign contractors to drill, political and governmental regulatory
risks and possible delays in obtaining permits, parts and supplies. In
addition, if the well is successful, a pipeline may have to be installed to
transport the crude oil or natural gas discovered to onshore collection
facilities.

    The Company is also subject to various state and Federal laws regarding
environmental and ecological matters because it acquires, drills and operates
oil and gas properties. To alleviate the environmental risk, the Company
carries $25,000,000 of liability insurance and $3,000,000 of special
operator's extra expense (blowout) insurance for wells it drills, including
the well planned to be drilled in the Black Sea.


                                       7

<PAGE>
                        EMPLOYEES AND OFFICE FACILITIES


    As of November 30, 2001, the Company, through its subsidiaries, employed
30 personnel. The Company also established an Oklahoma City office in February
of 2000.

    The Company leases certain offices as follows:

        Office Location               Function
        Radnor, PA                    Corporate Headquarters
        Blue Bell, PA                 Accounting and Land
        Mt. Pleasant, PA              Gas Production Office
        Pittsburgh, PA                Drilling and Exploration Office
        Tuscaloosa, Alabama           Oil and Gas Production Office
        Oklahoma City, Oklahoma       Legal and International Operations

    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 commitments of the Company are set forth in Note 13 to the
Consolidated Financial Statements in Item 8.

ITEM 3. LEGAL PROCEEDINGS

Contingent Environmental Liabilities

    In December 1995, IRLP, an inactive subsidiary of the Company, sold its
refinery, the Indian Refinery, to American Western Refining L.P. ("American
Western"), an unaffiliated party. As part of the related purchase and sale
agreement, American Western assumed all environmental liabilities and
indemnified IRLP with respect thereto. Subsequently, American Western filed
for bankruptcy and sold the Indian Refinery to an outside party pursuant to a
bankruptcy proceeding. The outside party has substantially dismantled the
Indian Refinery. American Western recently filed a Plan of Liquidation.
American Western anticipates that the Plan of Liquidation expects to be
confirmed in January 2002.

    During fiscal 1998, the Company was informed that the United States
Environmental Protection Agency ("EPA") had investigated offsite acid sludge
waste found near the Indian Refinery and had investigated and remediated
surface contamination on the Indian Refinery property. Neither the Company nor
IRLP was initially named with respect to these two actions.

    In October 1998, the EPA named the Company and two of its inactive
refining subsidiaries as potentially responsible parties for the expected
clean-up of the Indian Refinery. In addition, eighteen other parties were
named including Texaco Refining and Marketing, Inc. ("Texaco"), the refinery
operator for over 50 years. A subsidiary of Texaco had owned the refinery
until December of 1988. The Company subsequently responded to the EPA
indicating that it was neither the owner nor the operator of the Indian
Refinery and thus not responsible for its remediation.

    In November 1999, the Company received a request for information from the
EPA concerning the Company's involvement in the ownership and operation of the
Indian Refinery. The Company responded to the EPA information request in
January 2000.

    On August 7, 2000, the Company received notice of a claim against it and
two of its inactive refining subsidiaries from Texaco and its parent. Texaco
had made no previous claims against the Company although the Company's
subsidiaries had owned the refinery from August 1989 until December 1995. In
its claim, Texaco demanded that the Company and its former subsidiaries
indemnify Texaco for all liability resulting from environmental contamination
at and around the Indian Refinery. In addition, Texaco demanded that the
Company assume Texaco's defense in all matters relating to environmental
contamination at and around the Indian Refinery, including lawsuits, claims
and administrative actions initiated by the EPA and indemnify Texaco for costs
that Texaco has already incurred addressing environmental contamination at the
Indian Refinery. Finally, Texaco also claimed that the Company and two of its
inactive subsidiaries are liable to Texaco under the Federal Comprehensive
Environmental Response Compensation and Liability Act as owners and operators
of the Indian Refinery. The Company responded to Texaco disputing the factual
and theoretical basis for Texaco's claims against the Company. The Company's
management and special counsel subsequently met with representatives of Texaco
but the parties disagreed concerning Texaco's claims.


                                       8

<PAGE>
    The Company and its special counsel, Reed Smith LLP, believe that Texaco's
claims are utterly without merit and the Company intends to vigorously defend
itself against Texaco's claims and any lawsuits that may follow. In addition
to the numerous defenses that the Company has against Texaco's contractual
claim for indemnity, the Company and its special counsel believe that by the
express language of the agreement which Texaco construes to create an
indemnity, Texaco has irrevocably elected to forgo all rights of contractual
indemnification it might otherwise have had against any person, including the
Company.

    In September 1995, Powerine sold the Powerine Refinery to Kenyen Resources
("Kenyen"), an unaffiliated party. In January 1996, Powerine merged into a
subsidiary of Energy Merchant Corp. ("EMC"), an unaffiliated party, and EMC
assumed all environmental liabilities. In August 1998, EMC sold the Powerine
Refinery to a third party, which, we are informed, continues to seek financing
to restart the Powerine Refinery.

    In July of 1996, the Company was named a defendant in a class action
lawsuit concerning emissions from the Powerine Refinery. In April of 1997, the
court granted the Company's motion to quash the plaintiff's summons based upon
lack of jurisdiction and the Company is no longer involved in the case.

    Although the environmental liabilities related to the Indian Refinery and
Powerine Refinery have been transferred to others, there can be no assurance
that the parties assuming such liabilities will be able to pay them. American
Western, owner of the Indian Refinery, filed for bankruptcy and is in the
process of liquidation. EMC, which assumed the environmental liabilities of
Powerine, sold the Powerine Refinery to an unrelated party, which we
understand is still seeking financing to restart that refinery. Furthermore,
as noted above, the EPA named the Company as a potentially responsible party
for remediation of the Indian Refinery and has requested and received relevant
information from the Company. Estimated gross undiscounted clean-up costs for
this refinery are at least $80,000,000 - $150,000,000 according to third
parties. If the Company were found liable for the remediation of the Indian
Refinery, it could be required to pay a percentage of the clean-up costs.
Since the Company's subsidiary only operated the Indian Refinery five years,
whereas Texaco and others operated it over fifty years, the Company would
expect that its share of remediation liability would be proportional to its
years of operation, although such may not be the case. Furthermore, as noted
above, Texaco has claimed that the Company indemnified it for all
environmental liabilities related to the Indian Refinery. If Texaco were to
sue the Company on this theory and prevail in court, the Company could be held
responsible for the entire estimated clean up costs of $80,000,000 -
$150,000,000 or more. In such a case, this cost would be far in excess of the
Company's financial capability.

    An opinion issued by the U.S. Supreme Court in June 1998 in the comparable
matter of United States v. Bestfoods, 524 U.S. 51, 118 S.Ct. 1876 (1998), and
a recent opinion by the U.S. Appeals Court for the Fifth Circuit in Aviall
Services, Inc. v. Cooper Industries Inc., 263 F.3rd 134 (5th Cir. 2001)
vacated and reh'g granted, 278 F.3d 416 (Dec. 19, 2001) support the Company's
positions. Nevertheless, if funds for environmental clean-up are not provided
by these former and/or present owners, it is possible that the Company and/or
one of its former refining subsidiaries could be named parties in additional
legal actions to recover remediation costs. In recent years, government and
other plaintiffs have often sought redress for environmental liabilities from
the party most capable of payment without regard to responsibility or fault.
Whether or not the Company is ultimately held liable in such a circumstance,
should litigation involving the Company and/or IRLP occur, the Company would
probably incur substantial legal fees and experience a diversion of management
resources from other operations.

    Although the Company does not believe it is liable for any of its
subsidiaries' clean-up costs and intends to vigorously defend itself in such
regard, the Company cannot predict the ultimate outcome of these matters due
to inherent uncertainties.

General

Long Trusts Lawsuit

    In November 2000, the Company and three of its subsidiaries were
defendants in a jury trial in Rusk County, Texas. The plaintiffs in the case,
the Long Trusts, are non-operating working interest owners in wells previously
operated by Castle Texas Production Limited Partnership ("CTPLP"), an inactive
exploration and production subsidiary of the Company. The wells were among
those sold to UPRC in May 1997. The Long Trusts claimed that CTPLP did not
allow them to sell gas from March 1, 1996 to January 31, 1997 as required by
applicable joint operating agreements, and they sued CTPLP and the other
defendants, claiming (among other things) breach of contract, breach of
fiduciary duty, conversion and conspiracy. The plaintiffs sought actual
damages, exemplary damages, pre-judgment and post-judgment interest,
attorney's fees and court costs. CTPLP counterclaimed for approximately
$150,000 of unpaid joint interests billings, interest, attorneys' fees and
court costs.


                                       9

<PAGE>
    After a three-week trial, the District Court in Rusk County submitted 36
questions to the jury which covered all of the claims and counterclaims in the
lawsuit. Based upon the jury's answers, the District Court entered judgement
granting plaintiffs' claims against the Company and its subsidiaries, as well
as CTPLP's counterclaim against the plaintiffs. The District Court issued an
amended judgement on September 5, 2001 which became final December 19, 2001.
The net amount awarded to the plaintiffs was approximately $2,700,000. The
Company and its subsidiaries have filed a notice of appeal with the Tyler
Court of Appeals and will continue to vigorously contest this matter.

    Jenkens & Gilchrist, special counsel to the Company on this matter, does
not consider an unfavorable outcome to this lawsuit probable. The Company's
management and special counsel believe that several of the plaintiffs' primary
legal theories are contrary to established Texas law and that the Court's
charge to the jury was fatally defective. They further believe that any
judgment for plaintiffs based on those theories or on the jury's answers to
certain questions in the charge cannot stand and will be reversed on appeal.
As a result, the Company has not accrued any liability for this litigation.
Nevertheless, to pursue the appeal, the Company and its subsidiaries will be
required to post a bond to cover the net amount of damages awarded to the
plaintiffs and to maintain that bond until the resolution of the appeal (which
may take several years). The Company has included the letter of credit to
support the bond, estimated at approximately $3,000,000, in its line of credit
with a major energy bank. See Note 21 to the consolidated financial statements
which are included in Item 8 to this Form 10-K.

Larry Long Litigation

    In May 1996, Larry Long, representing himself and allegedly "others
similarly situated," filed suit against the Company, three of the Company's
natural gas marketing and transmission and exploration and
production subsidiaries, Atlantic Richfield Company ("ARCO"), B&A Pipeline
Company, a former subsidiary of ARCO ("B&A"), and MGNG in the Fourth Judicial
District Court of Rusk County, Texas. The plaintiff originally claimed, among
other things, that the defendants underpaid non-operating working interest
owners, royalty interest owners and overriding royalty interest owners with
respect to gas sold to Lone Star pursuant to the Lone Star Contract. Although
no amount of actual damages was specified in the plaintiff's initial
pleadings, it appeared that, based upon the volumes of gas sold to Lone Star,
the plaintiff may have been seeking actual damages in excess of $40,000,000.

    After some initial discovery, the plaintiff's pleadings were significantly
amended. Another purported class representative, Travis Crim, was added as a
plaintiff, and ARCO, B&A and MGNG were dropped as defendants. Although it is
not completely clear from the amended petition, the plaintiffs apparently
limited their proposed class of plaintiffs to royalty owners and overriding
royalty owners in leases owned by the Company's exploration and production
subsidiary limited partnership. In amending their pleadings, the plaintiffs
revised their basic claim to seeking royalties on certain operating fees paid
by Lone Star to the Company's natural gas marketing subsidiary limited
partnership.

    In April 2000, Larry Long withdrew as a named plaintiff and in September
2000, the Company and the remaining named plaintiff agreed to settle the case
for a payment of $250,000 by the Company. As of December 27, 2001, the Company
had paid $259,000, representing the $250,000 settlement amount plus $9,000 of
interest, to the plaintiffs and their lawyers.

MGNG Litigation

    On May 4, 1998, CTPLP, a subsidiary of the Company, filed a lawsuit
against MGNG and MG Gathering Company ("MGC"), two subsidiaries of MG, in the
district court of Harris County, Texas. One of the Company's exploration and
production subsidiaries sought to recover gas measurement and transportation
expenses charged by the defendants in breach of a certain gas purchase
contract. Improper charges exceeded $750,000 before interest. In October of
1998, MGNG and MGC filed a suit in Harris County, Texas. This suit sought
indemnification from two of the Company's subsidiaries in the event CTPLP won
its lawsuit against MGNG and MGC. The MG entities cited no basis for their
claim of indemnification. The management of the Company and special counsel
retained by the Company believe that the Company's subsidiary is entitled to
at least $750,000 plus interest and that the Company's two subsidiaries have
no indemnification obligations to MGNG or MGC. The parties participated in
mediation but were not able to resolve the issue.

    In October 1999, MGNG filed a second lawsuit against the Company and three
of its subsidiaries claiming $772,000 was owed to MGNG under a gas supply
contract between one of the Company's subsidiaries and MGNG. The suit was
filed in the district court of Harris County, Texas. The Company and its
subsidiaries believed that they do not owe $772,000 and were entitled to
legally offset some or all of the $772,000 claimed

                                       10

<PAGE>
against amounts owed to CTPLP by MGNG for improper gas measurement and
transportation deductions. The Castle entities answered this suit denying
MGNG's claims based partially on the right of offset.

    In September 2000, the parties agreed to settle all lawsuits. Under the
terms of the settlement the amount claimed by MGNG under a gas supply contract
was reduced by $325,000 and the net amount payable to MGNG was set at $400,000
and the parties signed mutual releases. The Company paid MGNG $400,000 in
November 2001.

Pilgreen Litigation

    As part of the AmBrit purchase, Castle Exploration Company, Inc. ("CECI")
acquired a 10.65% overriding royalty interest ("ORRI") in the Pilgreen #2ST
gas well in Texas. Because of title disputes, AmBrit and other interest owners
had previously filed claims against the operator of the Pilgreen well, and
CECI acquired post January 1, 1999 rights in that litigation. Although revenue
attributed to the ORRI has been suspended by the operator since first
production, because of recent related appellate decisions and settlement
negotiations, the Company believes that revenue attributable to the ORRI
should be released to CECI in the near future. As of September 30, 2001,
approximately $415,000 attributable to CECI's share of the ORRI revenue was
suspended. The Company's policy is to recognize the suspended revenue only
when and if it is received.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

    The Company did not hold a meeting of stockholders or otherwise submit any
matter to a vote of stockholders during the fourth quarter of fiscal 2001.


                                       11

<PAGE>
                                    PART II


ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
        MATTERS

Principal Market

    The Company's Common Stock is quoted on the Nasdaq National Market ("NNM")
under the trading symbol "CECX."

Stock Price and Dividend Information

Stock Price:

    On December 29, 1999, the Company's Board of Directors declared a stock
split in the form of a 200% stock dividend applicable to all stockholders of
record on January 12, 2000. The additional shares were paid on January 31,
2000 and the Company's shares first traded at post split prices on February 1,
2000. The stock split applied only to the Company's outstanding shares on
January 12, 2000 (2,337,629 shares) and did not apply to treasury shares
(4,491,017 shares) on that date. As a result of the stock split 4,675,258
additional shares were issued. All share changes have been recorded
retroactively in these data and elsewhere in this Form 10-K.

    The table below presents the high and low sales prices of the Company's
Common Stock as reported by the NNM for each of the quarters during the three
fiscal years ended September 30, 2001.
<TABLE>
<CAPTION>

                                                                                       2001              2000             1999
                                                                                   -------------    --------------    -------------
                                                                                   High     Low     High      Low     High     Low
                                                                                   ----     ---     ----      ---     ----     ---
     <S>                                                                          <C>      <C>     <C>       <C>      <C>     <C>
     First Quarter (December 31)...............................................   $7.73    $5.92   $ 9.67    $5.50    $6.46   $5.63
     Second Quarter (March 31).................................................   $6.94    $5.60   $10.56    $4.81    $5.96   $5.25
     Third Quarter (June 30)...................................................   $6.92    $5.67   $ 6.50    $4.63    $6.42   $5.00
     Fourth Quarter (September 30).............................................   $6.47    $4.21   $ 7.75    $6.25    $6.08   $5.50
</TABLE>


    The final sale of the Company's Common Stock as reported by the NNM on
November 30, 2001 was at $5.87.

Dividends:

    On June 30, 1997, the Company's Board of Directors adopted a policy of
paying regular quarterly cash dividends of $.05 per share on the Company's
common stock. Commencing July 15, 1997, dividends have been paid quarterly. As
with any company, the declaration and payment of future dividends are subject
to the discretion of the Company's Board of Directors and will depend on
various factors - including a covenant in the Company's letter of credit
facility that limits dividends to 50% of the Company's net income.

Approximate Number of Holders of Common Stock

    As of November 30, 2001, the Company's Common Stock was held by
approximately 3,000 stockholders.

ITEM 6. SELECTED FINANCIAL DATA

    During the five fiscal years ended September 30, 2001, the Company
consummated a number of transactions affecting the comparability of the
financial information set forth below. In May 1997, the Company sold its Rusk
County, Texas oil and gas properties and pipeline to UPRC and one of its
subsidiaries. In June 1999, CECI acquired all of the oil and gas assets of
AmBrit. See Item 7 - "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and Note 4 to the Company's Consolidated
Financial Statements included in Item 8 of this Form 10-K.


                                       12

<PAGE>
    The following selected financial data have been derived from the
Consolidated Financial Statements of the Company for each of the five years
ended September 30, 2001. The information should be read in conjunction with
the Consolidated Financial Statements and notes thereto included in Item 8 of
this Form 10-K.
<TABLE>
<CAPTION>

                                                                                       For the Fiscal Year Ended September 30,
                                                                                  -------------------------------------------------
                                                                                      (in Thousands, except per share amounts)
                                                                                   2001       2000       1999      1998       1997
                                                                                   ----       ----       ----      ----       ----
     <S>                                                                          <C>       <C>        <C>        <C>       <C>
     Net sales:
         Natural gas marketing and transmission...............................                         $50,067    $70,001   $64,606
         Exploration and production...........................................    $21,144   $17,959    $ 7,190    $ 2,603   $ 7,113
     Gross Margin [exclusive of depreciation and amortization]:
         Natural gas marketing and transmission
         (gas sales less gas purchases).......................................                         $19,005    $26,747   $24,640
         Exploration and production
         (oil and gas sales less production expenses).........................    $13,745   $11,765    $ 4,802    $ 1,828   $ 5,173
     Income from continuing operations........................................    $ 2,097   $ 2,778    $11,222    $15,260   $31,529
     Income from continuing operations per share
         outstanding (diluted)................................................    $   .25   $   .71    $   .99    $  1.22   $  1.55
     Dividends declared per common shares outstanding.........................    $   .20   $   .20    $   .25    $   .15   $   .10
</TABLE>

<TABLE>
<CAPTION>

                                                                                                     September 30,
                                                                                   ------------------------------------------------
                                                                                    2001      2000       1999      1998       1997
                                                                                    ----      ----       ----      ----       ----
     <S>                                                                           <C>      <C>        <C>        <C>       <C>
     Total assets..............................................................   $59,118   $63,295    $60,796    $67,004   $82,717
     Long-term obligations.....................................................         0         0          0          0         0
     Redeemable preferred stock................................................         0         0          0          0         0
     Capital leases............................................................         0         0          0          0         0
</TABLE>


    Share data have been retroactively restated to reflect the 200% stock
dividend that was effective January 31, 2000.


                                       13

<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
        RESULTS OF OPERATIONS

                   ("$000's" Omitted Except Per Unit Amounts)
-------------------------------------------------------------------------------

RESULTS OF OPERATIONS

GENERAL

    From August 1989 to September 30, 1995, two of the Company's subsidiaries
conducted refining operations. By December 12, 1995, the Company's refining
subsidiaries had sold all of their refining assets. In addition, Powerine
merged into a subsidiary of EMC and was no longer a subsidiary of the Company.
The Company's other refining subsidiary, IRLP, owns no refining assets and is
in the process of liquidation. As a result, the Company has accounted for its
refining operations as discontinued operations in the Company's financial
statements as of September 30, 1995 and retroactively. Accordingly, discussion
of results of operations has been confined to the results of continuing
operations and the anticipated impact, if any, of liquidation of the Company's
remaining inactive refining subsidiary and contingent environmental
liabilities of the Company or its refining subsidiaries.

    Also, as noted above, CECI acquired the oil and gas properties of AmBrit
on June 1, 1999. The oil and gas reserves associated with the acquisition were
estimated at approximately 12.5 billion cubic feet of natural gas and
2,000,000 barrels of crude oil, roughly 150% of the reserves owned by the
Company before the acquisition. Furthermore, as a result of the acquisition,
the Company's production of oil and gas increased by approximately 425%. This
acquisition impacted consolidated operations for the last four months of
fiscal 1999 only.

    Gas marketing sales and purchases ceased effective May 31, 1999 by virtue
of the scheduled termination of its subsidiaries' gas sales and gas purchase
contracts with Lone Star and MGNG. The Company has not replaced these
contracts although it continues to seek similar gas marketing acquisitions. As
a result, natural gas marketing operations impacted consolidated operations
for all of fiscal 1999 and none of fiscal 2000 or fiscal 2001.

Fiscal 2001 vs Fiscal 2000

OIL AND GAS SALES

    Oil and gas sales increased $3,185 or 17.7% from fiscal 2000 to fiscal
2001. An analysis of the increase is as follows:
<TABLE>
<CAPTION>

                                                                                                 Fiscal Year Ended
                                                                                                   September 30,
                                                                                                   -------------          Increase
                                                                                                 2001          2000      (Decrease)
                                                                                                 ----          ----      ----------
     <S>                                                                                      <C>           <C>          <C>
     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
                                                                                                                          =========
</TABLE>



                                       14

<PAGE>
    For the year ended September 30, 2001, the Company's net production
averaged 718 barrels of crude per day and 8,447 mcfe of natural gas per day
versus 764 barrels of crude oil per day and 9,718 mcf of natural gas per day
for the year ended September 30, 2000.

    The decline in production volumes is primarily attributable to the
depletion of the Company's oil and gas reserves and the fact that all but one
of the exploratory wells drilled in fiscal 2000 and 2001 by the Company
resulted in dry holes rather than production. The decline in production would
have been greater by 467,000 mcfe had the Company not acquired twenty-one
producing East Texas properties in April 2001 (see Items 1 and 2 above).

    At the present time, natural gas spot prices are averaging less than
$3.00/mcf - far less than the average price of $4.53/mcf for the year ended
September 30, 2001 and the record prices of $9.00/mcf received for some
production in January 2001. In addition, current crude prices are slightly
below $20.00 per barrel - significantly less than the average price of $27.39
received by the Company for the year ended September 30, 2001. Since the
Company has not hedged its production and since most credible experts are not
predicting significant increases for oil and gas prices in the short term, the
Company expects that its oil and gas revenues will decrease significantly in
fiscal 2002 unless the Company successfully drills or acquires new reserves
and/or oil and as prices increase significantly. If the Company consummates
the intended sale of its domestic oil and gas properties to Delta (see Items 1
and 2 above), oil and gas price or volume increases will affect both
operations until closing of the sale and the ultimate purchase price the
Company receives. Net cash flow between October 1, 2001, the effective date,
and the closing date, would be retained by the Company but would reduce the
purchase price paid by Delta.

    Oil and gas production expenses increased $1,205 or 19.5% from fiscal 2000
to fiscal 2001. The increase is primarily attributable to the acquisition of
twenty-one (21) producing properties in East Texas in April 2001. For the year
ended September 30, 2001 oil and gas production expenses, net of 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:
<TABLE>
<CAPTION>

                                                                                                         Year Ended September 30,
                                                                                                      -----------------------------
                                                                                                                          Increase
                                                                                                       2001      2000    (Decrease)
                                                                                                       ----      ----    ----------
     <S>                                                                                              <C>       <C>      <C>
     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
                                                                                                      ======    ======      =====
</TABLE>


    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.


                                       15

<PAGE>
    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).

    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
reserves.

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:
<TABLE>
<CAPTION>

                                                                    Year Ended
                                                                   September 30,
                                                                   -------------
                                                                   2001    2000
                                                                   ----    ----
     <S>                                                           <C>     <C>
     Litigation recovery (costs) ...............................           ($45)
     Miscellaneous .............................................    $42      70
                                                                    ---    ----
                                                                    $42    $ 25
                                                                    ===    ====
</TABLE>


PROVISION FOR INCOME TAXES

    The tax provisions (benefit) for the years ended September 30, 2001 and
2000 consist of the following components:
<TABLE>
<CAPTION>

                                                                  Year Ended
                                                                 September 30,
                                                                ---------------
                                                                2001     2000
                                                                ----     ----
     <S>                                                       <C>      <C>
     1.  Decrease in net deferred tax asset using 36%
           Federal and state blended tax rate .............    $ 808    $   948
     2.  Change in valuation allowance ....................     (431)    (3,204)
     4.  Other (primarily revisions of previous
           estimates) .....................................        4        (35)
                                                               -----    -------
                                                               $ 381    ($2,291)
                                                               =====    =======
</TABLE>


    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

                                       16

<PAGE>
portion of the deferred tax asset would more likely than not be realized based
upon estimates of future taxable income and upon the projected taxable income
resulting from the anticipated sale of its oil and gas assets to Delta and,
accordingly, decreased the valuation allowance by $431 to $3,559.

    If recent decreases in oil and gas prices continue and if the sale of the
Company's oil and gas assets to Delta is not consummated, the Company may be
required to increase its valuation allowance.

    The tax provision for the year ended September 30, 2000 consists primarily
of deferred taxes of $948 related to timing differences originating in fiscal
2000 and the reversal of a $3,204 valuation reserve from fiscal 1999. The
reversal of the valuation reserve resulted because of positive evidence that
the Company would be able to generate sufficient taxable income in the future
to utilize its deferred tax asset. Such positive evidence consists primarily
of the increased value of the Company's oil and gas reserves as a result of
substantially higher oil and gas prices.

EARNINGS PER SHARE

    Since November 1996, the Company has repurchased 4,871,020 or 69% of its
common shares. As a result of these share acquisitions, earnings per share are
significantly higher than they would be if no shares had been repurchased.

Fiscal 2000 vs Fiscal 1999

OIL AND GAS SALES

    Oil and gas sales increased $11,247 or 167.6% from fiscal 1999 to fiscal
2000. An analysis of the increase is as follows:
<TABLE>
<CAPTION>

                                                      Year Ended September 30,
                                                -------------------------------------
                                                   2000         1999        Increase
                                                   ----         ----        --------
     <S>                                        <C>          <C>           <C>
     Production (Net):
      Barrels of crude oil..................       279,000      124,000       155,000
      Mcf of natural gas....................     3,547,000    1,971,000     1,576,000
      Equivalent net of natural gas.........     5,221,000    2,715,000     2,506,000
     Oil and Gas Sales:
      Before hedging........................    $   19,487   $    6,862    $   12,625
      Effect of hedging.....................        (1,528)        (150)       (1,378)
                                                ----------   ----------    ----------
      Net of hedging........................    $   17,959   $    6,712    $   11,247
                                                ==========   ==========    ==========
     Average Price/MCFE:
      Before hedging........................    $     3.73   $     2.53    $     1.20
      Effect of hedging.....................         (0.29)       (0.06)        (0.23)
                                                ----------   ----------    ----------
      Net...................................    $     3.44   $     2.47    $      .97
                                                ==========   ==========    ==========
     An analysis of the increase in oil and
      gas sales is as follows:
     Analysis of Increase Before Hedging:
      Price (2,715,000 mcfe x $1.20/mcfe)...                 $    3,258
      Volume (2,506,000 mcfe x $3.73/mcfe)..                      9,347
      Rounding..............................                         20
                                                             ----------
                                                             $   12,625
                                                             ==========
     Analysis of Increase After Hedging:
      Price (2,715,000 mcfe x $.97/mcfe)....                 $    2,634
      Volume (2,506,000 mcfe x $3.44/mcfe)..                      8,621
      Rounding..............................                         (8)
                                                             ----------
                                                             $   11,247
                                                             ==========
</TABLE>


    The increase in production volumes is primarily attributable to the
acquisition of the AmBrit properties on June 1, 1999. As a result of this
acquisition, the production volumes attributable to the AmBrit properties
contributed twelve months of oil and gas sales for the year ended September
30, 2000 versus only four months of oil and gas sales for the year ended
September 30, 1999.


                                       17

<PAGE>
    For the year ended September 30, 2000, net production averaged 764 barrels
of crude oil a day and 9,718 mcf of natural gas per day. A year ago the
Company had anticipated that such volumes would attain approximately 1,000
barrels of crude oil and approximately 13,000 mcf of natural gas per day. The
Company has not attained 1,000 net barrels a day of crude oil or 13,000 net
mcf of natural gas per day because it drilled eight dry holes out of nine
exploratory wells drilled in two exploratory drilling ventures in the United
States and because both of its wildcat wells drilled in Romania also resulted
in unproductive wells.

Oil and Gas Production Expenses

    Oil and gas production expenses increased $4,284 or 224% from fiscal 1999
to fiscal 2000. The increase is primarily attributable to the acquisition of
the AmBrit Energy Corp. ("AmBrit") properties in June 1999. For the year ended
September 30, 2000 oil and gas production expenses, net of non-operator
reimbursements, were $1.19 per equivalent mcf sold versus only $.70 per
equivalent mcf sold for the year ended September 30, 1999. The increase
results primarily from two factors. The Company is not the operator for most
of the wells it acquired from AmBrit and, as a result, must pay the operator
of such wells monthly administrative reimbursement fees pursuant to the terms
of the governing joint operating agreements. Some of these fees are
substantial and the aggregate amount of such fees is much greater than that
payable on the Company's non-AmBrit properties. A second factor contributing
to the increase is the fact that the average age of the Company's producing
properties is increasing - especially given the unsuccessful results of the
Company's exploratory drilling programs. Mature wells typically carry a higher
production expense burden than do newer wells that have not yet been
significantly depleted.

GENERAL AND ADMINISTRATIVE COSTS

    General and administrative costs increased $1,000 or 96.3% from fiscal
1999 to fiscal 2000. The increase is primarily attributable to the Company's
establishment of an Oklahoma City office in February 2000, increased legal,
consulting and reservoir engineering fees and increased employee costs. Also,
see "Corporate General and Administrative Expenses" below.

DEPRECIATION, DEPLETION AND AMORTIZATION

    Depreciation, depletion and amortization increased $1,163 or 56.8% from
fiscal 1999 to fiscal 2000. The components of depreciation, depletion and
amortization were as follows:
<TABLE>
<CAPTION>

                                                           Year Ended September 30,
                                                           ------------------------
                                                           2000     1999     Increase
                                                           ----     ----     --------
     <S>                                                  <C>      <C>       <C>
     Depreciation and amortization of furniture and
      fixtures and equipment .........................    $  219   $  109     $  110
     Depreciation, depletion and amortization of oil
      and gas properties .............................     2,990    1,937      1,053
                                                          ------   ------     ------
                                                          $3,209   $2,046     $1,163
                                                          ======   ======     ======
</TABLE>


    Depreciation and amortization of furniture and fixtures and equipment
increased $110 from fiscal 1999 to fiscal 2000 primarily because of
depreciation related to new vehicles purchased in late fiscal 1999 and early
fiscal 2000 and because of amortization of computer software commencing in the
first quarter of fiscal 2000.

    For the year ended September 30, 2000, the depletion rate per equivalent
mcf was $.57 in fiscal 2000 versus $.71 in fiscal 1999. The net decrease is
the result of offsetting factors. The depletion rate indirectly decreased
because of substantially higher energy prices at September 30, 2000 versus
those at September 30, 1999. As a result of such higher prices, the Company's
net economic oil and gas reserves increased substantially from 1999 to 2000
and related depreciation, depletion and amortization decreased substantially
because more equivalent mcfs of gas were allocated to essentially the same
depletable costs. This decrease was offset by the Company's expenditure of
approximately $7,600 in the acquisition of drilling acreage and drilling of
eight dry holes in the United States and two unproductive wells in Romania.
These expenditures increased the depletion rate because the related costs of
these drilling ventures were added to the Company's amortization base without
a concomitant increase in oil and gas reserves to be depleted.

IMPAIRMENT OF UNPROVED PROPERTIES

    The Company recorded an impairment reserve for unproved property in fiscal
2000 because the Company drilled an unproductive well on one of its three
Romanian concessions and does not plan to drill any additional onshore wells
on that concession hence it provided a reserve for the costs allocated to that
concession.


                                       18

<PAGE>
    See Note 10 to the Consolidated Financial Statements included in Item 8 of
this Form 10-K concerning impairment of the Company's domestic oil and gas
reserves.

CORPORATE GENERAL AND ADMINISTRATIVE EXPENSES

    Corporate, general and administrative expenses increased $395 or 9.6% from
fiscal 1999 to fiscal 2000. The decrease is primarily attributable to
decreased insurance and legal costs. The $395 decrease in corporate, general
and administrative expenses was, however, offset by an increase of $1,000 in
exploration and production general and administrative expenses. (See above.) A
significant portion of the general and administrative expenses allocated to
corporate overhead in fiscal 1999 have been allocated to exploration and
production general and administrative costs in fiscal 2000 and are expected to
be so allocated in the future.

OTHER INCOME (EXPENSE)

    Interest income decreased $917 or 53.9% from fiscal 1999 to fiscal 2000.
The decrease is primarily attributable to a decrease in the average balance of
cash outstanding during the periods being compared.

    The composition of other income (expense) for the years ended September
30, 2000 and 1999 is as follows:
<TABLE>
<CAPTION>

                                                                         Year Ended
                                                                        September 30,
                                                                        -------------
                                                                        2000    1999
                                                                        ----    ----
     <S>                                                                <C>     <C>
     Litigation recovery (costs) ....................................   ($45)   $ 355
     Write-down of investment in Penn Octane Corporation preferred
      stock .........................................................            (423)
     Market price adjustment of investment in Penn Octane
      Corporation common stock ......................................             431
     Miscellaneous ..................................................     70      (11)
                                                                         ---    -----
                                                                         $25    $ 352
                                                                         ===    =====
</TABLE>


PROVISION FOR INCOME TAXES

    The tax provision (benefit) for the years ended September 30, 2000 and
1999 consist of the following components:
<TABLE>
<CAPTION>

                                                                       Year Ended
                                                                      September 30,
                                                                      -------------
                                                                      2000      1999
                                                                      ----      ----
     <S>                                                            <C>        <C>
     1.  Increase in net deferred tax asset using 36% Federal
         and state blended tax rate .............................   ($2,256)
     2.  Utilization of deferred tax asset, net of related
         valuation reserves, using 36% blended Federal and state
         tax rate ...............................................              $2,765
     3.  A tax provision of 2% on all net income in excess of
         that required to realize the net deferred tax asset.
         (This 2% rate represents alternative minimum Federal
         corporate taxes the Company must pay despite having tax
         carryforwards and credits available to offset regular
         Federal corporate tax) .................................                  71
     4.  Other (primarily revisions of previous estimates) ......       (35)      120
                                                                    -------    ------
                                                                    $ 2,291    $2,956
                                                                    =======    ======
</TABLE>


    The tax provision for the year ended September 30, 2000, consists
primarily of deferred taxes of $948 related to timing differences originating
in fiscal 2000 and the reversal of a $3,204 valuation reserve from fiscal
1999. The reversal of the valuation reserve resulted because of positive
evidence that the Company will be able to generate sufficient taxable income
in the future to utilize its deferred tax asset. Such positive evidence
consists primarily of the increased value of the Company's oil and gas
reserves as a result of substantially higher oil and gas prices.

    The tax provision for the year ended September 30, 1999 consists of
utilization of the $2,765 of remaining net deferred tax assets at September
30, 1998, $71 of Federal alternative minimum taxes on net income in excess of
that required to fully utilize the $2,765 net deferred tax asset using a 36%
blended tax rate and $120 of other taxes related to revisions to the prior
year's taxable income. The fiscal 1999 blended Federal and state income tax
rate was 26%, which is lower than the statutory rate due to the utilization of
statutory depletion and tax credits.

                                       19

<PAGE>
The Company did not record a net deferred tax asset at September 30, 1999
because it determined that future taxable income was less certain given the
Company's large exploratory and wildcat drilling programs, the expiration of
the Lone Star Contract, contingent environmental liabilities and other
factors.

EARNINGS PER SHARE

      Since November 1996, the Company has repurchased 4,831,020 or 69% of its
common shares. As a result of these share acquisitions, earnings per share are
significantly higher than they would be if no shares had been repurchased.

LIQUIDITY AND CAPITAL RESOURCES

    During the year ended September 30, 2001, the Company generated $11,884
from operating activities. During the same period the Company invested $15,449
in oil and gas properties and $572 to reacquire shares of its common stock. In
addition, it paid $1,326 in stockholder dividends. At September 30, 2001, the
Company had $5,844 of unrestricted cash, $10,409 of working capital and no
long-term debt.

Discontinued Refining Operations

    Although the Company's former and present subsidiaries have exited the
refining business and third parties have assumed environmental liabilities, if
any, of such subsidiaries, the Company and several of its subsidiaries remain
liable for contingent environmental liabilities (see Item 3 and Note 12 to the
consolidated financial statements included in Item 8 of this Form 10-K).

    As noted previously, the Company entered into a letter of intent to sell
all of its domestic oil and gas properties to Delta. Closing of the
transaction is anticipated between March 31, 2002 and June 30, 2002. The
Company's expected uses and sources of funds assuming this transaction closes
on April 30, 2002 are as follows:
<TABLE>
<CAPTION>

     Expected Uses of Funds
      ----------------------
     <S>                                                                  <C>
     Funds to support bond for appeal of verdict in Long Trusts
      Lawsuit............................................................ $3,000
     Reduction of trade payables.........................................  1,025
     Estimated drilling costs for wildcat in Black Sea (excludes
      completion costs if well successful)...............................  1,000
     Dividends to shareholders...........................................    990
     Recompletions and reworks on existing wells.........................    600
                                                                          ------
                                                                          $6,615
                                                                          ======
</TABLE>


    If sufficient funds are available, the Company may also consider an
additional investment in Networked. The Company does not expect to undertake
any significant developmental drilling since it has entered into a letter of
intent to sell its oil and gas properties to Delta for a fixed price (see
Items 1 and 2 above) effective October 1, 2001. The Company may also continue
to repurchase its shares if funds are available.

    In November of 2001 the Company entered into a line of credit with an
energy bank. (See Note 21 to the consolidated financial statements). The
Company may draw on this line to drill new wells or acquire oil and gas
properties and to provide letters of credit for certain bonding obligations.
The Company may not continue to use this line of credit, however, because it
has entered into a letter of intent to sell all of its oil and gas properties
to Delta effective October 1, 2001.
<TABLE>
<CAPTION>

     Expected Sources of Funds
      -------------------------
     <S>                                                                 <C>
     Proceeds of sale of oil/gas properties to Delta at closing.......   $15,500
     Unrestricted cash - September 30, 2001...........................     5,844
     Letter of credit portion of credit facility......................     3,000
                                                                         -------
                                                                         $24,344
                                                                         =======
</TABLE>


    The Company expects only marginally positive cash flow from operations
during the period from October 1, 2001 to April 30, 2002 given current low oil
and gas prices. If such prices increase, the Company may be able to fund some
of its expected expenditures from cash flow from oil and gas operations.
Conversely, the Company could experience negative cash flow from oil and gas
operations if oil and gas prices decrease from present levels.


                                       20

<PAGE>
    In addition, the Company owns marketable securities which had a market
value (also book value) of $6,722 at September 30, 2001 and the Company could
liquidate these and use the proceeds to fund planned expenditures if needed.
Most of the marketable securities owned by the Company, however, are the
common stocks of Delta (382,289 shares) and Penn Octane Corporation ("Penn
Octane"), a small public company involved in the sale of liquid propane gas in
Mexico (1,343,600 shares). Both of these companies are thinly traded and
volatile and the Company may, therefore, not be able to liquidate its shares
in Delta and Penn Octane at recorded values - especially if such shares must
be liquidated quickly in the market.

    If the sale to Delta is consummated as planned, the Company will also
receive 9,566,000 shares of Delta common stock.

    The closing of the sale of the Company's domestic oil and gas properties
to Delta is subject to numerous conditions, including execution of a
definitive agreement by December 31, 2001, approval of the sale by the
Company's and Delta's boards of directors and approval by Delta's
shareholders. Accordingly, there can be no assurance that the contemplated
sale will close or that it will close when anticipated. In addition, economic
conditions could change between the present time and closing and either Delta
or the Company may not conclude the transaction, although the party failing to
close could be subject to significant penalties pursuant to the terms of the
letter of intent.

    If the Delta transaction does not close, the Company's expected uses and
sources of funds for the period October 1, 2001 to September 30, 2002 are
approximately as follows:
<TABLE>
<CAPTION>

     Expected Uses of Funds
      ----------------------
     <S>                                                                 <C>
     Developmental drilling..........................................    $ 5,286
     Funds to support bond for appeal of verdict in Long Trusts
      lawsuit........................................................      3,000
     Reduction of trade payables.....................................      1,025
     Estimated drilling costs for wildcat well in the Black Sea......      1,000
     Recompletions and reworks on existing wells.....................        600
     Dividends to shareholders.......................................      1,320
                                                                         -------
                                                                         $12,231
                                                                         =======
</TABLE>


    As noted above, the Company may also consider additional investments in
Networked and further repurchase of its shares if sufficient cash is
available. In addition, the Company may consider acquisitions of other
properties or exploration and production companies, as it has in the past.

    In addition, if the sale to Delta is consummated as planned, the Company
expects that severance obligations will be triggered with respect to those
employees who are eventually terminated as a result of the sale. At the
present time the Company has severance agreements with all of its employees
except its Chief Executive Officer. Such agreements generally provide for one
month of severance pay for each full year of employment with the Company, with
a minimum of three (3) months severance. The Company expects that most of its
employees, except for 5 or 6 pumpers and production personnel, will be
terminated and entitled to severance benefits in the aggregate of
approximately $900 - $1,000.
<TABLE>
<CAPTION>

     Expected Sources of Funds
      -------------------------
     <S>                                                                 <C>
     Unrestricted cash - September 30, 2001...........................   $ 5,844
     Letter of credit portion of credit facility......................     3,000
     Expected minimum cash available for drilling under credit
        facility ($12,500-$3,000 letter of credit)....................     9,500
                                                                         -------
                                                                         $18,344
                                                                         =======
</TABLE>


    The amount that can be borrowed under the Company's line of credit will be
determined by the energy bank making the loan based upon its parameters and
will probably change based upon past production, changes in oil and gas prices
and other factors.

    In addition, the same comments, as above, apply concerning the Company's
possible use of its marketable securities or cash flow from operations to fund
expected expenditures.


                                       21

<PAGE>
    The Company's future operations are subject to the following risks:

    a.   Failure of Delta Transaction to Close

         There are several reasons why the Delta transaction may not
         ultimately close - including but not limited to failure of the
         parties to enter into a definitive purchase and sale agreement,
         failure to approve the transaction by the boards of directors of
         Delta and/or the Company or both, failure of the Delta shareholders
         to approve the transaction and failure of either party to consummate
         the transaction. In addition, the Securities and Exchange Commission
         may review Delta's proxy to its shareholders and such review may
         delay closing.

         If the transaction does not close the Company may miss drilling or
         acquisition opportunities and may suffer the loss of key employees -
         thus impeding its future operations. The Company has only thirty
         employees. It cannot simply switch gears from a divestiture mode to
         an acquisition mode without major disruption to its operations as can
         much larger exploration and production companies. The Company may
         find it difficult to retain key employees given that it has formally
         put its assets up for sale twice in the last year. Loss of key
         employees could negatively impact the Company's ability to meet the
         myriad of accounting and regulatory requirements to which the Company
         is subject as a public company.

    b.   Contingent Environmental Liabilities

         Although the Company has never itself conducted refining operations
         and its refining subsidiaries have exited the refining business and
         the Company does not anticipate any required expenditures related to
         discontinued refining operations, interested parties could seek
         redress from the Company for claimed environmental liabilities. In
         the past, government and other plaintiffs have often named the most
         financially capable parties in such cases regardless of the existence
         or extent of actual liability. As a result, there exists the
         possibility that the Company could be named for any environmental
         claims related to discontinued refining operations of its present and
         former refining subsidiaries.

         The Company was informed that the EPA has investigated offsite acid
         sludge waste found near the Indian Refinery and was also remediating
         surface contamination in the Indian Refinery property. Neither the
         Company nor IRLP was initially named with respect to these two
         actions.

         In October 1998, the EPA named the Company and two of its
         subsidiaries as potentially responsible parties for the expected
         clean-up of the Indian Refinery. In addition, eighteen other parties
         were named including Texaco, the refinery operator for over 50 years.
         The Company subsequently responded to the EPA indicating that it was
         neither the owner nor operator of the Indian Refinery and thus not
         responsible for its remediation. In November 1999, the Company
         received a request for information from the EPA concerning the
         Company's involvement in the ownership and operation of the Indian
         Refinery. The Company responded to the EPA in January 2000 and has
         received no further correspondence from the EPA. On August 7, 2000,
         the Company received notice of a claim against it and two of its
         inactive refining subsidiaries from Texaco and its parent. In its
         claim, Texaco demanded that the Company and its former subsidiaries
         indemnify Texaco for all liability resulting from environmental
         contamination at and around the Indian Refinery. In addition, Texaco
         demanded that the Company assume Texaco's defense in all matters
         relating to environmental contamination at and around the Indian
         Refinery, including lawsuits, claims and administrative actions
         initiated by the EPA as well as indemnify Texaco for costs that
         Texaco had already incurred addressing environmental contamination at
         the Indian Refinery. Finally, Texaco also claimed that the Company
         and its two inactive subsidiaries are liable to Texaco under the
         Federal Comprehensive Environmental Response Compensation and
         Liability Act as owners and operators of the Indian Refinery. The
         Company's management and special counsel subsequently met and
         continue to discuss Texaco's claims with representatives of Chevron/
         Texaco but the parties disagree concerning the validity of Texaco's
         claims. The Company and its special counsel, Reed Smith LLP, believe
         that Texaco's claims are utterly without merit and the Company
         intends to vigorously defend itself against Texaco's claims and any
         lawsuits that may follow.

         Estimated undiscounted clean-up costs for the Indian Refinery are
         $80,000 to $150,000 according to third parties. If the Company were
         found liable for the remediation of the Indian Refinery, it could be
         required to pay a percentage of the clean-up costs. Since the
         Company's subsidiary only

                                       22

<PAGE>
         operated the Indian Refinery five years whereas Texaco and others
         operated it over 50 years, the Company would expect that its share of
         any remediation liability would be proportional to its years of
         operation although such may not be the case. Although the Company
         does not believe it has any liabilities with respect to the
         environmental liabilities of the refineries, a court of competent
         jurisdiction may find otherwise. A June 1998 decision by the U.S.
         Supreme Court in the comparable case of United States v. Bestfoods,
         524 U.S. 51, 118 S.Ct. 1876 (1998), and a recent opinion by the U.S.
         Appeals Court for the Fifth Circuit in Aviall Services, Inc. v.
         Cooper Industries Inc., 263 F.3rd 134 (5th Cir. 2001) vacated and
         reh'g granted, 278 F.3d 416 (Dec. 19, 2001) support the Company's
         positions.

         The above estimate of expected cash resources and cash uses assumes
         no expenditure for contingent environmental liabilities or legal
         defense costs related to the Indian Refinery. If the Company is sued
         and related legal proceedings continue longer than expected
         (environmental litigation often continues 3-5 years or more) and/or
         the Company is found liable for a portion of the environmental
         remediation of either the Indian Refinery or Powerine Refinery,
         estimated cash uses will be increased and such increase could be
         significant.

    c.   IRLP Vendor Liabilities:

         IRLP owes its vendors approximately $5,000. Its only major asset was
         a $5,388 note due from the purchaser of the Indian Refinery, American
         Western. IRLP has agreed to settle its $5,388 note for $612 in
         exchange for a covenant of the EPA not to sue IRLP. These provisions
         are included in the Plan of Liquidation of American Western which
         American Western expects to be confirmed in January 2002. Assuming
         American Western's Plan of Liquidation is confirmed, IRLP will be
         able to pay its creditors only a small portion of the amounts owed to
         them.

    d.   Public Market for the Company's Stock:

         Although there presently exists a market for the Company's stock,
         such market is volatile and the Company's stock is thinly traded.
         Such volatility may adversely affect the market price and liquidity
         of the Company's common stock.

         In addition, the Company, through its stock repurchase program, has
         repurchased 4,871,020 shares or 69% of its outstanding common stock
         since November of 1996 and was the major market maker in the
         Company's stock for much of the period. If the Company ceases
         repurchasing shares, the market value of the Company's stock may be
         adversely affected.

    e.   Foreign Operating Risks

         As of September 30, 2001, the Company had incurred $3,597 drilling
         five wildcat wells (resulting in dry holes or uneconomic wells) on
         three Romanian concessions. The Company plans to drill a sixth
         wildcat well in the Black Sea in the spring or early summer of 2002.
         The Company's Romanian operations are subject to certain foreign
         country risks over which the Company has no control - including
         political risk, currency risk, the risk of additional taxation and
         the possibility that foreign operating requirements and procedures
         may reduce or eliminate estimated profitability.

    f.   Exploration and Production Reserve Risk

         The Company plans to participate in the drilling of a sixth Romanian
         wildcat well in the Black Sea whether or not it closes the sale of
         its domestic properties to Delta (see page 2). The planned wildcat
         well in the Black Sea involves high risk wildcat drilling where the
         probability of discovering commercial oil and gas reserves is less
         than twenty percent (20%). If the sale to Delta or a similar sale
         does not occur, the Company may also participate in the drilling of
         several domestic development wells and recompletions of existing
         wells to other producing zones. Drilling investments are essentially
         sunk cost. Reserve risk is the possibility that the reserves
         discovered, if any, will not approximate those the Company has
         estimated before drilling. If commercial reserves are not found or
         not found in the quantities anticipated, the Company's future
         operations and cash flow will be adversely affected and the Company
         could be required to record an impairment provision for its oil and
         gas properties pursuant to the full cost accounting method. (See Note
         2 to the financial statements included as Item 8 to this Form 10-K).


                                       23

<PAGE>
    g.   Exploration and Production Price Risk

         The Company did not hedge any of its anticipated future oil and gas
         production because the cost to do so appeared excessive when compared
         to the risk involved. As a result, the Company remains exposed to
         future oil and gas price changes with respect to all of its
         anticipated future oil and gas production. Such exposure could be
         considerable given the volatility of oil and gas prices. For example,
         from January 2001 to November 2001, crude oil prices decreased
         approximately 25% and natural gas prices decreased approximately 65%.
         Current oil and gas prices are low and are generally not predicted to
         increase appreciably over the next 2-4 years. In the past crude oil
         prices and gas prices have shown general volatility over short
         periods of time and it is possible that prices could change
         significantly and suddenly as they have in the past.

         The Company follows the full-cost method of accounting for oil and
         gas properties and equipment costs. Under this method of accounting
         net capitalized costs, less related deferred income taxes, in excess
         of the present value of net future cash inflows (oil and gas sales
         less production expenses) from proved reserves, tax effected and
         discounted at 10% and the cost of properties not being amortized, if
         any, are charged to expense (full cost ceiling test). If at a future
         reporting date oil and gas prices decline below the prices used to
         perform the full cost ceiling test at September 30, 2001, the Company
         estimates that it would likely incur a charge to expense.

    h.   Exploration and Production Operating Risk

         All of the Company's current oil and gas properties are onshore
         properties with relatively low operating risk. Nevertheless, the
         Company faces the risks encountered from operating over 250 oil and
         gas wells in several states - including the risks of oil and gas
         spills, resulting environmental damage, third party liability claims
         related to operations, including claims by landowners where the
         operated wells are located, and general operating risks.

    i.   Other Risks

         In addition to the specific risks noted above, the Company is subject
         to general business risks, including insurance claims in excess of
         insurance coverage, tax liabilities resulting from tax audits and the
         risks associated with the increased litigation that appear to affect
         most corporations.

    j.   Future of the Company

         In the last three years the regulatory burdens and related costs of
         being a public company have increased significantly. New requirements
         have been added by the Securities and Exchange Commission, the Nasdaq
         stock market and the Financial Accounting Standards Board at an
         accelerated pace including but not limited to requiring reviews of
         quarterly financial statements, increased Audit Committee procedures
         and protocol and compliance with new accounting and disclosure
         requirements. This has resulted in increased fees paid by the Company
         and diversion of management's efforts. In short, the Company's
         current level of operations are not sufficiently large to bear the
         Company's current general and administrative burden. In addition, the
         Company's high oil and gas production expense burden is at least
         partially attributable to the fact that the Company's fixed
         production costs are not spread over a larger number of and more
         productive oil and gas wells. As a result of these and other factors,
         the Company has not only aggressively sought to acquire properties to
         achieve a critical mass over which to apply its general and
         administrative expenses but has also sought to sell it properties
         when the conditions appeared most favorable. Although the Company has
         purchased approximately $34,000 of producing properties in the last
         three years, it has still not achieved the critical mass necessary to
         support its general and administrative burden.

         As noted earlier, the Company has entered into a letter of intent to
         sell all of its domestic oil and gas properties to Delta on terms the
         Company's management consider favorable. The Company's management
         considers such a transaction prudent given the uncertainty of oil and
         gas prices and the significant costs to operate a public company. If
         the Delta transaction fails to close as planned, the Company expects
         to continue to seek similar transactions on similar or better terms.
         The Company may also seek a merger with another company although to
         date the claims made by Texaco against the Company have hindered this
         process. Nevertheless, there can be no assurance that the Company
         will be able to succeed in this endeavor and the Company's management
         and board of directors may decide to continue to seek future
         acquisitions in the oil and gas sector when conditions are favorable
         and to attain the needed critical mass in that manner.


                                       24

<PAGE>
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK

    The Company has not hedged its anticipated oil and gas production and thus
remains at risk with respect to the prices it receives for such production. If
oil and gas prices increase, the Company's oil and gas revenues will increase.
Conversely, if oil and gas prices decrease, the Company's oil and gas revenues
will also decrease. Oil and gas prices are currently much lower than they have
been in several months and many forecasters are anticipating continued lower
oil and gas prices for several years. There can be, however, no assurance that
such prices will increase in the future or even remain at current levels given
recent oil and gas price volatility.

INFLATION AND CHANGING PRICES

Exploration and Production

    Oil and gas sales are determined by markets locally and worldwide and
often move inversely to inflation. Whereas operating expenses related to oil
and gas sales may be expected to parallel inflation, such costs have often
tended to move more in response to oil and gas sales prices than in response
to inflation.

NEW ACCOUNTING PRONOUNCEMENTS

    Statement of Financial Accounting Standards No. 133, as amended,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS No.
133"), was issued by the Financial Accounting Standards Board in June 1998.
Subsequently, SFAS No. 138 "Accounting for Certain Derivative Instruments"
("SFAS No. 138"), an amendment of SFAS No. 133, was issued. SFAS 133 and SFAS
138 standardize the accounting for derivative instruments, including certain
derivative instruments embedded in other contracts. Under the standard,
entities are required to carry all derivative instruments in the statement of
financial position at fair value. The accounting for changes in the fair value
(i.e., gains or losses) of a derivative instrument depends on whether such
instrument has been designated and qualifies as part of a hedging relationship
and, if so, depends on the reason for holding it. If certain conditions are
met, entities may elect to designate a derivative instrument as a hedge of
exposures to changes in fair values, cash flows, or foreign currencies. If the
hedged exposure is a fair value exposure, the gain or loss on the derivative
instrument is recognized in earnings in the period of change together with the
offsetting loss or gain on the hedged item attributable to the risk being
hedged. If the hedged exposure is a cash flow exposure, the effective portion
of the gain or loss on the derivative instrument is reported initially as a
component of other comprehensive income (not included in earnings) and
subsequently reclassified into earnings when the forecasted transaction
affects earnings. Any amounts excluded from the assessment of hedge
effectiveness, as well as the ineffective portion of the gain or loss, is
reported in earnings immediately. Accounting for foreign currency hedges is
similar to the accounting for fair value and cash flow hedges. If the
derivative instrument is not designated as a hedge, the gain or loss is
recognized in earnings in the period of change. The Company adopted SFAS No.
133 and SFAS No. 138 effective October 1, 2000. The Company ceased hedging its
oil and gas production in July 2000. At September 30, 2001 and 2000, the
Company had no freestanding derivative instruments in place and had no
embedded derivative instruments. As a result, the Company's adoption of SFAS
No. 133 and SFAS No. 138 had no impact on its results of operations or
financial condition.

    Statement of Financial Accounting Standards No. 141, "Business
Combinations" ("SFAS No. 141") and Statement of Financial Accounting Standards
No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142") were issued
in July 2001. SFAS No. 141 requires that all business combinations entered
into subsequent to June 30, 2001 be accounted for under the purchase method of
accounting and that certain acquired intangible assets in a business
combination be recognized and reported as assets apart from goodwill. SFAS No.
142 requires that amortization of goodwill be replaced with periodic tests of
the goodwill's impairment at least annually in accordance with the provisions
of SFAS No. 142 and that intangible assets other than goodwill be amortized
over their useful lives. The Company adopted SFAS No. 141 in July 2001 and
will adopt SFAS No. 142 in the first quarter of fiscal 2003. The Company does
not believe that its future adoption of SFAS No. 142 will have a material
effect on its results of operations.

    In June 2001, the FASB issued Statement No. 143, "Accounting for Asset
Retirement Obligations" ("SFAS No. 143"), which provides accounting
requirements for retirement obligations associated with tangible long-lived
assets, including: 1) the timing of liability recognition; 2) initial
measurement of the liability; 3) allocation of asset retirement cost to
expense; 4) subsequent measurement of the liability; and 5) financial
statement disclosures. SFAS No. 143 requires that asset retirement cost be
capitalized as part of the cost of the related long-lived asset and
subsequently allocated to expense using a systematic and rational method. Any
transition adjustment resulting from the adoption of SFAS No. 143 would be
reported as a cumulative effect of a change in accounting principle. The
Company will adopt the statement effective October 1, 2002. At this time,

                                       25

<PAGE>
the Company cannot reasonably estimate the effect of the adoption of this
statement on either its 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 will adopt SFAS No 144
effective October 1, 2002. At this time the Company is unable to determine
what the future impact of adopting this statement will have on its financial
position or results of operations.


                                       26

<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

<TABLE>
<CAPTION>

                                                                            Page
                                                                            ----
<S>                                                                         <C>
CONSOLIDATED FINANCIAL STATEMENTS:
Consolidated Statements of Operations for the Years Ended September 30,
  2001, 2000 and 1999....................................................    28
Consolidated Balance Sheets as of September 30, 2001 and 2000 ...........    29
Consolidated Statements of Cash Flows for the Years Ended September 30,
  2001, 2000 and 1999....................................................    30
Consolidated Statements of Stockholders' Equity and Other Comprehensive
  Income for the Years Ended September 30, 2001, 2000 and 1999...........    32
Notes to the Consolidated Financial Statements ..........................    33
INDEPENDENT AUDITORS' REPORT ............................................    59
</TABLE>


    All other schedules are omitted because they are not applicable or the
required information is shown in the financial statements or notes thereto.


                                       27

<PAGE>
                           CASTLE ENERGY CORPORATION

                     CONSOLIDATED STATEMENTS OF OPERATIONS

             ("$000's" Omitted Except Share and Per Share Amounts)


<TABLE>
<CAPTION>

                                                  Year Ended September 30,
                                           -------------------------------------
                                              2001          2000         1999
                                              ----          ----         ----
<S>                                        <C>           <C>          <C>
Revenues:
 Natural gas marketing and
  transmission:
   Gas sales...........................                               $   50,067
 Exploration and production:
   Oil and gas sales...................    $   21,144    $   17,959        6,712
                                           ----------    ----------   ----------
                                               21,144        17,959       56,779
                                           ----------    ----------   ----------
Expenses:
 Natural gas marketing and
  transmission:
   Gas purchases.......................                                   31,062
   General and administrative..........                                       35
   Transportation......................                                    1,123
   Depreciation and amortization.......                                    6,284
                                                                      ----------
                                                                          38,504
                                                                      ----------
 Exploration and production:
   Oil and gas production..............         7,399         6,194        1,910
   General and administrative..........         1,828         2,038        1,038
   Depreciation, depletion and
  amortization.........................         3,470         3,209        2,046
   Impairment of foreign unproved
  properties...........................         2,765           832
                                           ----------    ----------   ----------
                                               15,462        12,273        4,994
                                           ----------    ----------   ----------
 Corporate general and administrative..         4,169         3,717        4,112
                                           ----------    ----------   ----------
                                               19,631        15,990       47,610
                                           ----------    ----------   ----------
Operating income.......................         1,513         1,969        9,169
                                           ----------    ----------   ----------
Other income (expense):
 Interest income.......................           641           784        1,701
 Other income..........................            42            25          352
 Equity in loss of Networked Energy LLC           (99)
                                           ----------    ----------   ----------
                                                  584           809        2,053
                                           ----------    ----------   ----------
Income before provision for (benefit
  of) income taxes.....................         2,097         2,778       11,222
                                           ----------    ----------   ----------
Provision for (benefit of) income
  taxes:
 State.................................            11           (64)          79
 Federal...............................           370        (2,227)       2,877
                                           ----------    ----------   ----------
                                                  381        (2,291)       2,956
                                           ----------    ----------   ----------
Net income.............................    $    1,716    $    5,069   $    8,266
                                           ==========    ==========   ==========
Net income per share:
 Basic.................................    $      .26    $      .73   $     1.01
                                           ==========    ==========   ==========
 Diluted...............................    $      .25    $      .71   $      .99
                                           ==========    ==========   ==========
Weighted average number of common and
  potential dilutive shares
  outstanding:
 Basic.................................     6,643,724     6,939,350    8,205,501
                                           ==========    ==========   ==========
 Diluted...............................     6,818,855     7,102,803    8,347,932
                                           ==========    ==========   ==========
</TABLE>





The accompanying notes are an integral part of these consolidated financial
                                   statements

                                       28

<PAGE>
                           CASTLE ENERGY CORPORATION

                          CONSOLIDATED BALANCE SHEETS

             ("$000's" Omitted Except Share and Per Share Amounts)


<TABLE>
<CAPTION>

                                                               September 30,
                                                            -------------------
                                                              2001       2000
                                                              ----       ----
                          ASSETS
<S>                                                         <C>        <C>
Current assets:
 Cash and cash equivalents ..............................   $  5,844   $ 11,525
 Restricted cash ........................................        370      1,742
 Accounts receivable ....................................      2,787      3,758
 Marketable securities ..................................      6,722     10,985
 Prepaid expenses and other current assets ..............        277        251
 Estimated realizable value of discontinued net refining
  assets.................................................        612        800
 Deferred income taxes ..................................      1,879      2,256
                                                            --------   --------
   Total current assets..................................     18,491     31,317
Property, plant and equipment, net:
 Natural gas transmission ...............................         51         55
 Furniture, fixtures and equipment ......................        222        258
 Oil and gas properties, net (full cost method):
   Proved properties.....................................     39,843     29,218
   Unproved properties not being amortized...............        110      1,447
Investment in Networked Energy LLC ......................        401        500
Note receivable - Penn Octane Corporation ...............                   500
                                                            --------   --------
Total assets ............................................   $ 59,118   $ 63,295
                                                            ========   ========
           LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
 Dividend payable .......................................   $    331   $    333
 Accounts payable .......................................      3,543      2,433
 Accrued expenses .......................................        292        265
 Accrued taxes on appreciation of marketable securities .        900      2,628
 Stock subscription payable .............................                   150
 Net refining liabilities retained ......................      3,016      3,204
                                                            --------   --------
   Total current liabilities.............................      8,082      9,013
Long-term liabilities ...................................          9          6
                                                            --------   --------
   Total liabilities.....................................      8,091      9,019
                                                            --------   --------
Commitments and contingencies ...........................
Stockholders' equity:
 Series B participating preferred stock; par value -
  $1.00;
   10,000,000 shares authorized; no shares issued
 Common stock; par value - $0.50; 25,000,000 shares
  authorized;
   11,503,904 shares issued at September 30, 2001 and
  2000...................................................      5,752      5,752
 Additional paid-in capital .............................     67,365     67,365
 Accumulated other comprehensive income - unrealized
  gains on marketable
   securities, net of taxes..............................      1,600      4,671
 Retained earnings ......................................     42,816     42,422
                                                            --------   --------
                                                             117,533    120,210
 Treasury stock at cost - 4,871,020 shares at September
  30, 2001 and 4,791,020
   shares at September 30, 2000..........................    (66,506)   (65,934)
                                                            --------   --------
   Total stockholders' equity............................     51,027     54,276
                                                            --------   --------
   Total liabilities and stockholders' equity............   $ 59,118   $ 63,295
                                                            ========   ========
</TABLE>





The accompanying notes are an integral part of these consolidated financial
                                   statements

                                       29

<PAGE>
                           CASTLE ENERGY CORPORATION

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

             ("$000's" Omitted Except Share and Per Share Amounts)


<TABLE>
<CAPTION>

                                                   Year Ended September 30,
                                               --------------------------------
                                                 2001        2000        1999
                                                 ----        ----        ----
<S>                                            <C>         <C>        <C>
Cash flows from operating activities:
 Net income.................................   $  1,716    $  5,069   $   8,266
                                               --------    --------   ---------
Adjustments to reconcile net income to cash
  provided by operating activities:
   Depreciation, depletion and amortization.      3,470       3,209       8,330
   Impairment of foreign unproved properties      2,765         832
   Deferred income taxes (benefit)..........        377      (2,256)      2,765
   Unrealized gain on marketable securities.                               (481)
   Impairment of Penn Octane preferred stock                                423
   Equity in loss of Networked Energy LLC...         99
   Changes in assets and liabilities:
    (Increase) decrease in restricted cash..      1,372        (972)       (157)
    Decrease in accounts receivable.........        971       1,414       3,209
    Decrease in prepaid transportation......                              1,123
    (Increase) decrease in prepaid expenses
    and other current assets................        (26)        343        (301)
    Decrease in other assets................                     29
    Decrease in prepaid gas purchases.......                                852
    Increase (decrease) in accounts payable.      1,110        (436)     (5,740)
    Increase (decrease) in accrued expenses.         27        (537)       (861)
    Increase in other long-term liabilities.          3           6
                                               --------    --------   ---------
     Total adjustments......................     10,168       1,632       9,162
                                               --------    --------   ---------
     Net cash flow provided by operating
  activities................................     11,884       6,701      17,428
                                               --------    --------   ---------
Cash flows from investment activities:
 Investment in note receivable - Penn Octane
  Corporation...............................                   (500)
 Investment in marketable securities........        (34)                   (269)
 Proceeds from sale of oil and gas assets...         48       1,427
 Realization from (liquidation of)
  discontinued net refining assets..........                                900
 Acquisition of AmBrit oil and gas
  properties................................                            (20,170)
 Investment in other oil and gas properties.    (15,449)    (11,226)     (3,794)
 Investment in Networked Energy LLC.........       (150)       (350)
 Purchase of furniture, fixtures and
  equipment.................................        (82)       (173)        (98)
 Other......................................                    (35)
                                               --------    --------   ---------
     Net cash used in investing activities..    (15,667)    (10,857)    (23,431)
                                               --------    --------   ---------
</TABLE>


                            (continued on next page)




The accompanying notes are an integral part of these consolidated financial
                                   statements

                                       30

<PAGE>
                           CASTLE ENERGY CORPORATION

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

                               ("$000's" Omitted)

                         (continued from previous page)


<TABLE>
<CAPTION>

                                                                                                        Year Ended September 30,
                                                                                                    -------------------------------
                                                                                                      2001        2000       1999
                                                                                                      ----        ----       ----
<S>                                                                                                 <C>         <C>        <C>
Cash flows from financing activities:
 Acquisition of treasury stock..................................................................        (572)     (5,208)    (6,919)
 Dividends paid to stockholders.................................................................      (1,326)     (1,363)    (1,681)
 Proceeds from exercise of stock options........................................................                                255
                                                                                                    --------    --------   --------
     Net cash (used in) financing activities....................................................      (1,898)     (6,571)    (8,345)
                                                                                                    --------    --------   --------
Net (decrease) in cash and cash equivalents.....................................................      (5,681)    (10,727)   (14,348)
Cash and cash equivalents - beginning of period.................................................      11,525      22,252     36,600
                                                                                                    --------    --------   --------
Cash and cash equivalents - end of period.......................................................    $  5,844    $ 11,525   $ 22,252
                                                                                                    ========    ========   ========
Supplemental disclosures of cash flow information are as follows:
 Cash paid during the period:
   Income taxes.................................................................................    $     11    $    188   $    108
                                                                                                    ========    ========   ========
   Accrued dividends............................................................................    $    331    $    333   $    368
                                                                                                    ========    ========   ========
 Conversion of Penn Octane Corporation note and accrued interest receivable to marketable
  securities....................................................................................    $    521               $  1,000
                                                                                                    ========               ========
 Unrealized gain (loss) on investment in available-for-sale marketable securities...............    ($ 3,071)   $  2,275   $  2,396
                                                                                                    ========    ========   ========
 Exchange of oil/gas properties for Delta Petroleum Company common stock........................                $  1,937
                                                                                                                ========
</TABLE>





The accompanying notes are an integral part of these consolidated financial
                                   statements

                                       31

<PAGE>
                           CASTLE ENERGY CORPORATION

                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

                         AND OTHER COMPREHENSIVE INCOME

                  ("$000's" Omitted Except Per Share Amounts)


<TABLE>
<CAPTION>

                                                    Years Ended September 30, 2001, 2000 and 1999
                   ----------------------------------------------------------------------------------------------------------------
                                                                         Accumulated
                       Common Stock      Additional                         Other                       Treasury Stock
                     -----------------     Paid-In     Comprehensive    Comprehensive   Retained      ------------------
                     Shares     Amount     Capital         Income       Income (Loss)   Earnings      Shares      Amount     Total
                     ------     ------     -------         ------       -------------   --------      ------      ------     -----
<S>                <C>          <C>       <C>          <C>              <C>             <C>         <C>          <C>        <C>
Balance -
  September 30,
  1998.........     6,803,646   $3,402     $67,122                                       $34,836    3,862,917    ($53,807)  $51,553
Stock acquired.                                                                                       419,300      (6,919)   (6,919)
Options
  exercised....        25,000       12         243                                                                              255
Dividends
  declared
  ($.25 per
  share).......                                                                           (2,048)                            (2,048)
Comprehensive
  income
 Net income....                                           $ 8,266                          8,266                              8,266
 Other
  comprehensive
  income:
   Unrealized
    gain (loss) on
    marketable
    securities,
    net of tax                                              2,396          $ 2,396                                            2,396
                                                          -------
                                                          $10,662
                   ----------   ------     -------        =======          -------       -------    ---------    --------   -------
Balance -
  September 30,
  1999.........     6,828,646    3,414      67,365                           2,396        41,054    4,282,217     (60,726)   53,503
Stock split
  ratio
  retroactively
  applied......     4,675,258    2,338                                                    (2,338)
                   ----------   ------     -------                         -------       -------    ---------    --------   -------
Balance -
  September 30,
  1999 -
  restated.....    11,503,904    5,752      67,365                           2,396        38,716    4,282,217     (60,726)   53,503
Stock acquired.                                                                                       508,803      (5,208)   (5,208)
Dividends
  declared
  ($.20 per
  share).......                                                                           (1,363)                            (1,363)
Comprehensive
  income
 Net income....                                           $ 5,069                          5,069                              5,069
 Other
  comprehensive
  income:
   Unrealized
    gain on
    marketable
    securities,
    net of tax.                                             2,275            2,275                                            2,275

                                                          -------
                                                          $ 7,344
                   ----------   ------     -------        =======          -------       -------    ---------    --------   -------
Balance -
  September 30,
  2000.........    11,503,904    5,752      67,365                           4,671        42,422    4,791,020     (65,934)   54,276
Stock acquired.                                                                                        80,000        (572)     (572)
Dividends
  declared
  ($.20 per
  share).......                                                                           (1,322)                            (1,322)
Comprehensive
  income
 Net income....                                           $ 1,716                          1,716                              1,716


 Other
  comprehensive
  income (loss):
   Unrealized
    gain (loss)
    on marketable
    securities,
    net of tax.                                            (3,071)          (3,071)                                          (3,071)
                                                          -------
                                                          ($1,355)
                   ----------   ------     -------        =======          -------       -------    ---------    --------   -------
Balance -
  September 30,
  2001.........    11,503,904   $5,752     $67,365                         $ 1,600       $42,816    4,871,020    ($66,506)  $51,027
                   ==========   ======     =======                         =======       =======    =========    ========   =======
</TABLE>





The accompanying notes are an integral part of these consolidated financial
                                   statements

                                       32

<PAGE>
                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

NOTE 1 - BUSINESS AND ORGANIZATION

Business

    Castle Energy Corporation (the "Company") is a public company incorporated
in Delaware. Mr. Joseph L. Castle II, Chairman of the Board and Chief
Executive Officer, and his wife own approximately twenty-three percent (23%)
of the Company's outstanding common stock at September 30, 2001.

    The Company's only line of business at September 30, 2001 and at present
is oil and gas exploration and production. The Company's operations are
conducted in the United States and in Romania. Prior to September 30, 1995,
several of the Company's subsidiaries and former subsidiaries were involved in
the refining business. These subsidiaries discontinued refining operations
effective September 30, 1995; however, several contingencies related to
closure of these refining assets are still outstanding. From December 1992 to
May 31, 1999, several of the Company's subsidiaries were involved in the
natural gas marketing business and from December 1992 to May 1997, another
subsidiary was involved in the gas transmission business. In May 1997, the
Company sold its gas transmission pipeline. All of the related long-term gas
sales and gas purchase contracts applicable to the Company's natural gas
marketing business expired by their terms on May 31, 1999.

    On December 11, 2001, the Company entered into a letter of intent to sell
all of its domestic oil and gas properties to another public oil and gas
exploration company. See Note 21.

    References to the Company mean Castle Energy Corporation, the parent, and/
or one or more of its subsidiaries. Such references are used for convenience
and are not intended to describe legal relationships.

Oil and Gas Exploration and Production

    In June 1999, the Company acquired all of the oil and gas assets of AmBrit
Energy Corp. ("AmBrit"). The AmBrit oil and gas assets included interests in
approximately 180 wells located in eight states. The proved oil and gas
reserves associated with the AmBrit acquisition were estimated to be
approximately 12.5 billion cubic feet of natural gas and 2,000,000 barrels of
crude oil or approximately one hundred and fifty percent (150%) of the
Company's proved reserves before such acquisition. See Note 4.

    During fiscal 2000, the Company participated in the drilling of nine
exploratory wells in south Texas pursuant to two drilling ventures with other
exploration and production companies. Eight of the wells drilled resulted in
dry holes while the ninth well was completed as a producing well. During
fiscal 2000 and 2001, the Company participated in the drilling of five wildcat
wells in Romania. Four of the wells drilled resulted in dry holes. The fifth
well produced some volumes of natural gas when tested. The Company considered
participating in a four well drilling program offsetting the fifth well but
has currently decided not to do so because of the current low prices
obtainable for production and the potential costs of constructing a pipeline
to transport production to potential purchasers. The Company has also agreed
to participate in the drilling of a sixth well in the Black Sea in the spring
or early summer of 2002. In December 1999, the Company acquired majority
interests in twenty-six (26) offshore Louisiana wells. The Company then sold
these wells to Delta Petroleum Company ("Delta"), a public company involved in
oil and gas exploration and development, in September 2000.

    In April 2001, the Company consummated the purchase of twenty-one (21)
operated producing East Texas oil and gas properties from a private company.

    See Note 4.

Natural Gas Marketing

    In December 1992, the Company acquired a long-term natural gas sales
contract with Lone Star Gas Company ("Lone Star Contract"). The Company also
entered into a gas sales contract and one gas purchase contract with MG
Natural Gas Corp. ("MGNG"), a subsidiary of MG Corp. ("MG"), which, in turn,
is a United States subsidiary of Metallgesellschaft A.G. ("MGAG"), a German
conglomerate. In May 1997, the Company sold its Rusk County, Texas natural gas
pipeline to a subsidiary of UPRC and thus exited the gas transmission business
while still conducting gas marketing operations. Effective May 31, 1999, the
aforementioned gas sales and gas purchases contracts expired by their own
terms and were not replaced by other third party gas marketing business.

                                       33
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

Refining

IRLP

    The Company indirectly entered the refining business in 1989 when one of
its subsidiaries acquired the operating assets of an idle refinery located in
Lawrenceville, Illinois (the "Indian Refinery"). The Indian Refinery was
subsequently operated by one of the Company's subsidiaries, Indian Refining I
Limited Partnership ("IRLP"), until September 30, 1995 when it was shut down.
On December 12, 1995, IRLP sold the Indian Refinery assets to American Western
Refining, L.P. ("American Western"). American Western subsequently filed for
bankruptcy and sold the Indian Refinery to an outside party which has
substantially dismantled it. American Western subsequently filed a Plan of
Liquidation which it expects to be confirmed by the governing bankruptcy court
in January 2002. If the Plan is confirmed, IRLP expects to receive $612 which
it would then distribute to its vendors.

Powerine

    In October 1993, a former subsidiary of the Company purchased Powerine Oil
Company ("Powerine"), the owner of a refinery located in Santa Fe Springs,
California (the "Powerine Refinery"), from MG. On September 29, 1995, Powerine
sold substantially all of its refining plant to Kenyen Projects Limited
("Kenyen"). On January 16, 1996, Powerine merged into a subsidiary of Energy
Merchant Corp. ("EMC"), an unaffiliated entity, and EMC acquired the refinery
from Kenyen. EMC subsequently sold the refinery to an outside party which, we
are informed, continues to seek financing to restart it.

    As a result of the transactions with American Western, Kenyen and EMC, the
Company's refining subsidiaries disposed of their interests in the refining
business. The results of refining operations were shown as discontinued
operations in the Consolidated Statement of Operations for the year ended
September 30, 1995 and retroactively. Discontinued refining operations have
not impacted operations since fiscal 1995. Amounts on the balance sheet
reflect the remaining assets and liabilities that are pending final resolution
of related contingencies.

Investment In Networked Energy LLC

    In August 2000, the Company purchased thirty-five percent (35%) of the
membership interests of Networked Energy LLC ("Network") for $500. Network is
a private company engaged in the operation of energy facilities that supply
power, heating and cooling services directly to retail customers.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

General

    The significant accounting policies discussed are limited to those
applicable to the business segments in which the Company operated during the
fiscal years ended September 30, 2001, 2000 and 1999 - natural gas marketing
and transmission and exploration and production. References should be made to
previous Forms 10-K for summaries of accounting principles applicable to the
discontinued refining segment.

Principles of Consolidation

    The consolidated financial statements presented include the accounts of
the Company and all of its subsidiaries. All intercompany transactions have
been eliminated in consolidation.

Revenue Recognition

Natural Gas Marketing

    Revenues were recorded when deliveries were made. Essentially all of the
Company's deliveries were made under two long-term gas sales contracts, the
Lone Star Contract and a gas sales contract with MGNG. These contracts expired
May 31, 1999.

Exploration and Production

    Oil and gas revenues are recorded under the sales method when oil and gas
production volumes are delivered to the purchaser. Reimbursement of costs from
well operations is netted against the related oil and gas production expenses.


                                       34
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

Cash and Cash Equivalents

    The Company considers all highly liquid investments, such as time deposits
and money market instruments, purchased with a maturity of three months or
less, to be cash equivalents.

Natural Gas Transmission

    Natural gas transmission assets included gathering systems and pipelines
and were depreciated on a straight-line basis over fifteen years, their
estimated useful life.

Marketable Securities

    The Company currently classifies its investment securities as available-
for-sale securities. Pursuant to Statement of Financial Accounting Standards
No. 115 ("SFAS 115"), such securities are measured at fair market value in the
financial statements with unrealized gains or losses recorded in other
comprehensive income until the securities are sold or otherwise disposed of.
At such time gain or loss is included in earnings. Prior to July 1, 1999, the
Company classified its investment securities as trading securities and
included the difference between cost and fair market value in earnings.

Prepaid Gas Purchases

    Prepaid gas purchases represented payments made by one of the Company's
subsidiaries for gas that the subsidiary was required to take but did not. All
prepaid gas purchases related to gas purchases from MGNG. Under the terms of
the related gas purchase contracts, the subsidiary was entitled to and did
make up the prepaid gas, i.e., to take it and not pay for it, once it had
taken the required minimum contract volume for the contract year. Prepaid gas
purchase costs were expensed as the subsidiary took delivery of the prepaid
gas.

Furniture, Fixtures and Equipment

    Furniture, fixtures and equipment are depreciated on a straight-line basis
over the estimated useful lives of the assets. Furniture, fixtures and
equipment are depreciated on a straight-line basis over periods of three to
ten years and rolling stock is depreciated on a straight-line basis over four
to five years.

Oil and Gas Properties

    The Company follows the full-cost method of accounting for oil and gas
properties and equipment costs. Under this method of accounting, all
productive and nonproductive costs incurred in the acquisition, exploration
and development of oil and gas reserves are capitalized. Capitalized costs are
amortized on a composite unit-of-production method by country using estimates
of proved reserves. Capitalized costs which relate to unevaluated oil and gas
properties are not amortized until proved reserves are associated with such
costs or impairment of the related property occurs. Management and drilling
fees earned in connection with the transfer of oil and gas properties to a
joint venture and proceeds from the sale of oil and gas properties are
recorded as reductions in capitalized costs unless such sales are material and
involve a significant change in the relationship between the cost and the
value of the remaining proved reserves, in which case a gain or loss is
recognized. None of the joint ventures in which the Company participates are
legal entities. The Company accounts for all unincorporated entities involved
in oil and gas exploration and production using proportionate gross financial
statement presentation. Under the proportionate gross basis, the Company
records its share of assets and liabilities on the balance sheet and related
operating data in its income statement. Expenditures for repairs and
maintenance of wellhead equipment are expensed as incurred. Net capitalized
costs, less related deferred income taxes, in excess of the present value of
net future cash inflows (oil and gas sales less production expenses) from
proved reserves, tax-effected and discounted at 10%, and the cost of
properties not being amortized, if any, are charged to current expense.
Amortization and excess capitalized costs, if any, are computed separately for
the Company's investment in Romania.

Environmental Costs

    The Company is subject to extensive federal, state and local environmental
laws and regulations. These laws, which are constantly changing, regulate the
discharge of materials into the environment and may require the Company to
remove or mitigate the environmental effects of the disposal or release of
petroleum or chemical substances at various sites. Environmental expenditures
are expensed or capitalized depending on their future

                                       35
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

expected economic benefit to the Company. Expenditures that relate to an
existing condition caused by past operations and that have no future economic
benefits are expensed. Liabilities for expenditures are recorded when
environmental assessment and/or remediation is probable and the costs can be
reasonably estimated. Environmental liabilities are accrued on an undiscounted
basis unless the aggregate amount of the obligation and the amount and timing
of the cash payments are fixed and reliably determined for that site.

Impairment of Long-Term Assets

    The Company reviewed its long-term assets other than oil and gas
properties for impairment whenever events or changes in circumstances
indicated that the carrying amount of an asset may not be recoverable. If the
sum of the expected future cash flows expected to result from the use of the
asset and its eventual disposition were less than the carrying amount of the
asset, an impairment loss would have been recognized. Measurement of an
impairment loss would be based on the fair market value of the asset.
Impairment for oil and gas properties is computed in the manner described
above under "Oil and Gas Properties." The Company currently has no significant
long-term assets except for its oil and gas properties, for which impairment
is recorded pursuant to full cost accounting as described above.

Hedging Activities

Natural Gas Marketing

    The Company used hedging strategies to hedge its future natural gas
purchase requirements for its gas sales contracts with Lone Star and MGNG (see
Note 1). The Company hedged future commitments using natural gas swaps, which
were accounted for on a settlement basis. Gains and losses from hedging
activities were included in the item being hedged, the cost of gas purchased
for the Lone Star Contract or for the contract with MGNG. In order to qualify
as a hedge, the change in fair market value of the hedging instrument had to
be highly correlated with the corresponding change in the hedged item.

Exploration and Production

    The Company used hedging strategies to hedge a significant portion of its
crude oil and natural gas production through July 31, 2000. The Company used
futures contracts to hedge such production. Gains and losses from hedging
activities were deferred and debited or credited to the item being hedged, oil
and gas sales, when they occurred. In order to qualify as a hedge the change
in fair market value of the hedging instrument was highly correlated with the
corresponding change in the hedged item. When the hedging instrument ceased to
qualify as a hedge, changes in fair value were charged against or credited to
earnings.

Gas Contracts

    The purchase price allocated to the Lone Star Contract was capitalized and
amortized over the term of the related contract, 6.5 years.

Gas Balancing

    Gas balancing activities have been immaterial during the periods reported.

Investment In Networked

    The Company's investment in Network (the Company owns 35% of Network) is
recorded on the equity method. Under this method, the Company records its
share of Network's income or loss with an offsetting entry to the carrying
value of the Company's investment. Cash distributions, if any, are recorded as
reductions in the carrying value of the Company's investment.

    The Company's investment in Network exceeded the fair value of the
Company's share of Network's assets by $350. Such excess (goodwill) is being
amortized on a straight-line method over forty (40) years.

Comprehensive Income

    Comprehensive income includes net income and all changes in an
enterprise's other comprehensive income including, among other things,
unrealized gains and losses on certain investments in debt and equity
securities.


                                       36
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

Stock Based Compensation

    SFAS 123, "Accounting for Stock-Based Compensation," allows an entity to
continue to measure compensation costs in accordance with Accounting Principle
Board Opinion No. 25 ("APB 25"). The Company has elected to continue to
measure compensation cost in accordance with APB 25 and to comply with the
required disclosure-only provisions of SFAS 123.

Income Taxes

    The Company follows Statement of Financial Accounting Standards No. 109
("SFAS 109"), "Accounting for Income Taxes." SFAS 109 is an accounting
approach that requires the recognition of deferred tax assets and liabilities
for the expected future tax consequences of events that have been recognized
in the Company's financial statements and tax returns. In estimating future
tax consequences, SFAS 109 generally considers all expected future events
other than anticipated enactments of changes in the tax law or tax rates. SFAS
109 also requires that deferred tax assets, if any, be reduced by a valuation
allowance based upon whether realization of such deferred tax asset is or is
not more likely than not. (See Note 17)

Earnings Per Share

    Basic earnings per common share are based upon the weighted average number
of common shares outstanding. Diluted earnings per common share are based upon
maximum possible dilution calculated using average stock prices during the
year.

Reclassifications

    Certain reclassifications have been made to make the periods presented
comparable.

Use of Estimates

    The preparation of financial statements in accordance with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosures of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from these estimates.

New Accounting Pronouncements

    Statement of Financial Accounting Standards No. 133, as amended,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS No.
133"), was issued by the Financial Accounting Standards Board in June 1998.
Subsequently, SFAS No. 138 "Accounting for Certain Derivative Instruments"
("SFAS No. 138"), an amendment of SFAS No. 133, was issued. SFAS 133 and SFAS
138 standardize the accounting for derivative instruments, including certain
derivative instruments embedded in other contracts. Under the standard,
entities are required to carry all derivative instruments in the statement of
financial position at fair value. The accounting for changes in the fair value
(i.e., gains or losses) of a derivative instrument depends on whether such
instrument has been designated and qualifies as part of a hedging relationship
and, if so, depends on the reason for holding it. If certain conditions are
met, entities may elect to designate a derivative instrument as a hedge of
exposures to changes in fair values, cash flows, or foreign currencies. If the
hedged exposure is a fair value exposure, the gain or loss on the derivative
instrument is recognized in earnings in the period of change together with the
offsetting loss or gain on the hedged item attributable to the risk being
hedged. If the hedged exposure is a cash flow exposure, the effective portion
of the gain or loss on the derivative instrument is reported initially as a
component of other comprehensive income (not included in earnings) and
subsequently reclassified into earnings when the forecasted transaction
affects earnings. Any amounts excluded from the assessment of hedge
effectiveness, as well as the ineffective portion of the gain or loss, is
reported in earnings immediately. Accounting for foreign currency hedges is
similar to the accounting for fair value and cash flow hedges. If the
derivative instrument is not designated as a hedge, the gain or loss is
recognized in earnings in the period of change. The Company adopted SFAS No.
133 and SFAS No. 138 effective October 1, 2000. The Company ceased hedging its
oil and gas production in July 2000. At September 30, 2001 and 2000, the
Company had no freestanding derivative instruments in place and had no
embedded derivative instruments. As a result, the Company's adoption of SFAS
No. 133 and SFAS No. 138 had no impact on its results of operations or
financial condition.


                                       37
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

    Statement of Financial Accounting Standards No. 141, "Business
Combinations" ("SFAS No. 141") and Statement of Financial Accounting Standards
No. 142, "Goodwill and Other Intangible Assets" ("SFAS No. 142") were issued
in July 2001. SFAS No. 141 requires that all business combinations entered
into subsequent to June 30, 2001 be accounted for under the purchase method of
accounting and that certain acquired intangible assets in a business
combination be recognized and reported as assets apart from goodwill. SFAS
No. 142 requires that amortization of goodwill be replaced with periodic tests
of the goodwill's impairment at least annually in accordance with the
provisions of SFAS No. 142 and that intangible assets other than goodwill be
amortized over their useful lives. The Company adopted SFAS No. 141 in July
2001 and will adopt SFAS No. 142 in the first quarter of fiscal 2003. The
Company does not believe that its future adoption of SFAS No. 142 will have a
material effect on its results of operations.

    In June 2001, the FASB issued Statement No. 143, "Accounting for Asset
Retirement Obligations" ("SFAS No. 143"), which provides accounting
requirements for retirement obligations associated with tangible long-lived
assets, including: 1) the timing of liability recognition; 2) initial
measurement of the liability; 3) allocation of asset retirement cost to
expense; 4) subsequent measurement of the liability; and 5) financial
statement disclosures. SFAS No. 143 requires that asset retirement cost be
capitalized as part of the cost of the related long-lived asset and
subsequently allocated to expense using a systematic and rational method. Any
transition adjustment resulting from the adoption of SFAS No. 143 would be
reported as a cumulative effect of a change in accounting principle. The
Company will adopt the statement effective October 1, 2002. At this time, the
Company cannot reasonably estimate the effect of the adoption of this
statement on either its financial position or results of operations.

    In August 2001, the FASB issued Statement No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" ("SFAS No. 144"), which will be
effective for financial statements issued for fiscal years beginning after
December 15, 2001 and interim periods within those fiscal years. SFAS No. 144
requires that long-lived assets to be disposed of by sale be measured at the
lower of the carrying amount or fair value less cost to sell, whether reported
in continuing operations or in discontinued operations. SFAS No. 144 broadens
the reporting of discontinued operations to include all components of an
entity with operations that can be distinguished from the rest of the entity
and that will be eliminated from the ongoing operations of the entity in a
disposal transaction. After its effective date, SFAS No. 144 will be applied
to those transactions where appropriate. The Company will adopt SFAS No 144
effective October 1, 2002. At this time the Company is unable to determine
what the future impact of adopting this statement will have on its financial
position or results of operations.


                                       38
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

NOTE 3 - DISCONTINUED REFINING OPERATIONS

    Effective September 30, 1995, the Company's refining subsidiaries
discontinued their refining operations.

    An analysis of the assets and liabilities related to the refining segment
for the period October 1, 1998 to September 30, 2001 is as follows:
<TABLE>
<CAPTION>

                                               Estimated
                                            Realizable Value       Net Refining
                                            of Discontinued        Liabilities
                                          Net Refining Assets        Retained
                                          -------------------    ---------------
     <S>                                  <C>                    <C>
     Balance - October 1, 1998 ........         $ 3,623                $ 5,129
     Reduction in estimated MG SWAP
      litigation recovery .............            (129)                  (129)
     Collection of MG SWAP litigation
      proceeds ........................            (575)                  (575)
     Additional recovery in connection
      with the Powerine Arbitration ...                                    900
     Reduction in estimated
      recoverable value of note
      receivable from American Western           (2,119)
     Adjustment of vendor liabilities .                                 (2,119)
     Other ............................                                     (1)
                                                -------                -------
     Balance - September 30, 1999 .....             800                  3,205
     Cash transactions ................                                   (153)
     Adjustment of vendor liabilities .                                    152
                                                -------                -------
     Balance - September 30, 2000 .....             800                  3,204
     Cash transactions ................                                    (80)
     Adjustment of vendor liabilities .                                     80
     Adjustments resulting from
      American Western's Plan of
      Liquidation .....................            (188)                  (188)
                                                -------                -------
     Balance - September 30, 2001 .....         $   612                $ 3,016
                                                =======                =======
</TABLE>


    As of September 30, 2001, the estimated realizable value of discontinued
net refining assets consists of $612 of estimated recoverable proceeds from
the American Western note. The estimated value of net refining liabilities
retained consisted of net vendor liabilities of $1,281 and accrued costs
related to discontinued refining operations of $2,155, offset by cash of $420.

    "Estimated realizable value of discontinued net refining assets" is based
on the transactions consummated by the Company with American Western and
transactions consummated by American Western and IRLP subsequently with others
and includes management's best estimates of the amounts expected to be
realized upon the complete disposal of the refining segment. "Net refining
liabilities retained" includes management's best estimates of amounts expected
to be paid and amounts expected to be realized on the settlement of this net
liability. The amounts the Company ultimately realizes or pays could differ
materially from such amounts.

    See Notes 12 and 13.

NOTE 4 - ACQUISITIONS AND DISPOSITIONS

    On June 1, 1999, the Company consummated the purchase of all of the oil
and gas properties of AmBrit. The oil and gas properties purchased include
interests in approximately 180 oil and gas wells in Alabama, Louisiana,
Mississippi, Montana, New Mexico, Oklahoma, Texas and Wyoming, as well as
undrilled acreage in several of these states. The effective date of the sale
for purposes of determining the purchase price was January 1, 1999. The
adjusted purchase price after accounting for all transactions between the
effective date, January 1, 1999, and the closing date was $20,170. The entire
adjusted purchase price was allocated to "Oil and Gas Properties - Proved
Properties". Based upon reserve reports initially prepared by the Company's
petroleum reservoir engineers, the proved reserves (unaudited) associated with
the AmBrit oil and gas assets approximated

                                       39
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

2,000,000 barrels of crude oil and 12,500,000 mcf (thousand cubic feet) of
natural gas, which, together, approximated 150% of the Company's oil and gas
reserves before the acquisition. In addition, the production acquired
initially increased the Company's consolidated production by approximately
425%.

    The results of operations on a pro-forma basis as though the oil and gas
properties of AmBrit had been acquired as of the beginning of the periods
indicated are as follows:
<TABLE>
<CAPTION>

                                                   Year Ended September 30, 1999
                                                   -----------------------------
                                                            (Unaudited)
     <S>                                           <C>
     Revenues..................................            $   62,719
     Net income................................            $    7,958
     Net income per share......................            $      .95
     Shares outstanding (diluted)..............             8,347,932
</TABLE>


    These proforma results are presented for comparative purposes only and are
not necessarily indicative of the results which would have been obtained had
the acquisition been consummated as presented.

    Operations related to the AmBrit oil and gas properties have been included
in the Company's Consolidated Statements of Operations since June 1, 1999, the
closing date of the AmBrit acquisition.

Investment in Drilling Joint Ventures

    In fiscal 1999, the Company entered into two drilling ventures to
participate in the drilling of up to sixteen exploratory wells in south Texas.
During fiscal 2000, the Company participated in the drilling of
nine exploratory wells pursuant to the related joint venture operating
agreements. Eight wells drilled resulted in dry holes and one well was
completed as a producer. The Company has no further drilling obligations under
these joint ventures and has terminated participation in each drilling
venture. The total cost incurred to participate in the drilling of the
exploratory wells was $6,003.

Offshore Louisiana Property Acquisition

    In December 1999, a subsidiary of the Company purchased majority interests
in twenty-six offshore Louisiana wells from Whiting Petroleum Company
("Whiting"), a public company engaged in oil and gas exploration and
development. The adjusted purchase price was $890.

    In September 2000, the subsidiary of the Company sold its interests in the
offshore Louisiana wells to Delta. The effective date of the sale was July 1,
2000. The adjusted purchase price of $3,059 consisted of $1,122 cash plus
382,289 shares of Delta's common stock valued at the market price or $1,937
(see Note 8).

Investment in Romanian Concessions

    In April 1999, the Company purchased an option to acquire a fifty percent
(50%) interest in three oil and gas concessions granted to a subsidiary of
Costilla Energy Corporation ("Costilla"), a public oil and gas exploration and
production company, by the Romanian government. The Company paid Costilla $65
for the option. In May 1999, the Company exercised the option. As of September
30, 2001, the Company had participated in the drilling of five onshore wildcat
wells. Four of those wells resulted in dry holes. Although the fifth well
produced some volumes of natural gas when tested, the Company has not been
able to obtain a sufficiently high gas price to justify future production and
has elected at the present not to undertake an offset drilling program where
the fifth well was drilled. As a result, the Company recorded impairment
provisions of $2,765 and $832 for the years ended September 30, 2001 and 2000,
respectively, for costs incurred for the five onshore wells. The Company has
agreed to participate in the drilling of a sixth well, offshore, in the
Black Sea in the spring or early summer of 2002.

    See Note 10.

Other Exploration and Production Investments

    In November and December 1999, the Company acquired additional outside
interests in several Alabama and Pennsylvania wells, which it operates, for
$2,580.


                                       40
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

East Texas Property Acquisition

    On April 30, 2001, the Company consummated the purchase of several East
Texas oil and gas properties from a private company. The effective date of the
purchase was April 1, 2001. These properties included majority interests in
twenty-one (21) operated producing oil and gas wells and interests in
approximately 6,500 gross acres in three counties in East Texas. The Company
estimates the proved reserves acquired were approximately 12.5 billion cubic
feet of natural gas and 191,000 barrels of crude oil. The consideration paid,
net of purchase price adjustments, was $10,040. The Company used its own
internally generated funds to make the purchase.

NOTE 5 - RESTRICTED CASH

    Restricted cash consists of the following:
<TABLE>
<CAPTION>

                                                                  September 30,
                                                                   -------------
                                                                  2001     2000
                                                                  ----     ----
     <S>                                                          <C>     <C>
     Funds supporting letters of credit for offshore
      Louisiana wells .........................................           $1,519
     Drilling deposits in escrow - Romania ....................   $  7         4
     Funds supporting letters of credit issued for
      operating bonds .........................................    209       219
     Funds escrowed for litigation settlement .................    154
                                                                  ----    ------
                                                                  $370    $1,742
                                                                  ====    ======
</TABLE>


    The drilling deposits in escrow in Romania are to be used only to conduct
exploratory drilling activities in Romania and cannot be withdrawn or used for
other purposes by the Company.

    The funds escrowed for litigation settlement pertain to Larry Long
Litigation (see Note 13).

NOTE 6 - ACCOUNTS RECEIVABLE

    Based upon past customer experiences, the limited number of customer
accounts receivable relationships, and the fact that the Company's
subsidiaries can generally offset unpaid accounts receivable against an
outside owner's share of oil and gas revenues, management believes
substantially all receivables are collectible. All of the Company's accounts
receivable at September 30, 2001 and 2000 consisted of exploration and
production trade receivables.

NOTE 7 - NOTE RECEIVABLE - PENN OCTANE

    In January 2000, the Company invested $500 in a note due from Penn Octane
Corporation ("Penn Octane"), a public company involved in the sale of liquid
propane gas into Mexico. The note was originally due on December 15, 2000 and
bore interest at 9%, payable quarterly.

    In December 2000, the Company agreed to extend the note until June 15,
2002. In return, Penn Octane increased the interest rate on the note to 13.5%
and issued to the Company warrants to acquire an additional 62,500 shares of
Penn Octane common stock at $3.00 per share. Subsequently, the interest rate
was increased to 16.5% and the exercise price on the 62,500 options issued was
reduced to $2.50 per share.

    Effective September 14, 2001, the Company exercised options to acquire
275,933 shares of common stock of Penn Octane by exchanging its $500 note plus
$21 of accrued interest for the shares.

NOTE 8 - MARKETABLE SECURITIES

    The Company's investment in marketable securities consists of common
shares of Penn Octane, Delta and Chevron/Texaco.


                                       41
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

    At September 30, 1998, the Company accounted for its investment as trading
securities. In March 1999, the Company began to account for its investment as
available-for-sale securities. The Company's investments in Penn Octane, Delta
and Chevron/Texaco common stock and options to buy Penn Octane stock were as
follows:
<TABLE>
<CAPTION>

                                                                                       Common Stock
                                                                                   --------------------
                                                                                  Penn Octane     Delta    Chevron/Texaco    Total
                                                                                  -----------     -----    --------------    -----
     <S>                                                                          <C>            <C>       <C>              <C>
     September 30, 2001:
      Cost.....................................................................      $2,271      $1,937         $14         $ 4,222
      Unrealized gain (loss)...................................................       3,308        (808)                      2,500
                                                                                     ------      ------         ---         -------
      Book value (market value)................................................      $5,579      $1,129         $14         $ 6,722
                                                                                     ======      ======         ===         =======
     September 30, 2000:
      Cost.....................................................................      $1,750      $1,937                     $ 3,687
      Unrealized gain..........................................................       7,298                                   7,298
                                                                                     ------      ------         ---         -------
      Book value (market value)................................................      $9,048      $1,937                     $10,985
                                                                                     ======      ======         ===         =======
</TABLE>


    The fair market values of Penn Octane, Delta and Chevron/Texaco shares
were based on one hundred percent (100%) of the closing price on September 28,
2001, the last trading day in the Company's fiscal year ending September 30,
2001.

    At September 30, 2001 and 2000, the fair market values of the Penn Octane
shares include $164 and $1,641, respectively, related to options to acquire
Penn Octane common stock held by the Company. The value of such options was
computed using the Black-Scholes method (see Note #16).

    The Company owned 1,343,600 shares of Penn Octane, 382,289 shares of Delta
and 177 shares of Chevron/Texaco at September 30, 2001. Of these 501,000
shares of Penn Octane and all 177 shares of Chevron/Texaco were registered.
The remaining shares are either in the process of being registered or the
Company has registration rights with respect to such shares. At September 30,
2001, the Company also owned options to purchase 74,067 common shares of Penn
Octane common stock at $2.50 per share.

    At September 30, 2000, the Company owned 1,067,667 shares of Penn Octane
and 382,289 shares of Delta, as well as options to purchase 454,167 common
shares of Penn Octane at exercise prices of $1.75 to $6.00 per share.

NOTE 9 - FURNITURE, FIXTURES AND EQUIPMENT

    Furniture, fixtures and equipment are as follows:
<TABLE>
<CAPTION>

                                                                 September 30,
                                                                  -------------
                                                                  2001    2000
                                                                  ----    ----
     <S>                                                         <C>      <C>
     Cost:
      Furniture and fixtures ..................................  $ 693    $ 660
      Automobile and trucks ...................................    269      222
                                                                 -----    -----
                                                                   962      882
     Accumulated depreciation .................................   (740)    (624)
                                                                 -----    -----
                                                                 $ 222    $ 258
                                                                 =====    =====
</TABLE>



                                       42
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

NOTE 10 - OIL AND GAS PROPERTIES (Unaudited)

    Oil and gas properties consist of the following:
<TABLE>
<CAPTION>

                                                                                                        September 30, 2001
                                                                                                -----------------------------------
                                                                                                United States   Romania     Total
                                                                                                -------------   -------     -----
     <S>                                                                                        <C>             <C>        <C>
     Proved properties...................................................................         $ 56,100                 $ 56,100
     Less: Accumulated depreciation, depletion and amortization .........................          (16,257)                 (16,257)
                                                                                                  --------                 --------
     Proved properties...................................................................           39,843                   39,843
     Unproved properties not being amortized.............................................                       $ 3,707       3,707
     Impairment of unproved properties...................................................                        (3,597)     (3,597)
                                                                                                  --------      -------    --------
                                                                                                  $ 39,843      $   110    $ 39,953
                                                                                                  ========      =======    ========
</TABLE>

<TABLE>
<CAPTION>

                                                                                                        September 30, 2000
                                                                                                -----------------------------------
                                                                                                United States   Romania     Total
                                                                                                -------------   -------     -----
     <S>                                                                                        <C>             <C>        <C>
     Proved properties...................................................................         $ 42,127                 $ 42,127
     Less: Accumulated depreciation, depletion and amortization .........................          (12,909)                 (12,909)
                                                                                                  --------                 --------
     Proved properties...................................................................           29,218                   29,218
     Unproved properties not being amortized.............................................                        $2,279       2,279
     Impairment of unproved properties...................................................                          (832)       (832)
                                                                                                  --------       ------    --------
                                                                                                  $ 29,218       $1,447    $ 30,665
                                                                                                  ========       ======    ========
</TABLE>

    Capital costs incurred by the Company in oil and gas activities are as
follows:
<TABLE>
<CAPTION>

                                                                                          Year Ended September 30,
                                                                         ----------------------------------------------------------
                                                                                    2001                            2000
                                                                        ----------------------------    ---------------------------
                                                                         United                         United
                                                                         States    Romania    Total     States    Romania    Total
                                                                         ------    -------    -----     ------    -------    -----
     <S>                                                                <C>        <C>       <C>        <C>       <C>       <C>
     Acquisition of properties:
      Proved properties .............................................   $10,002              $10,002    $3,642              $ 3,642
      Unproved properties ...........................................       346                  346       678    $  999      1,677
     Exploration.....................................................     1,560    $1,428      2,988     2,966       346      3,312
     Development.....................................................     2,113                2,113     2,595                2,595
                                                                        -------    ------    -------    ------    ------    -------
                                                                        $14,021    $1,428    $15,449    $9,881    $1,345    $11,226
                                                                        =======    ======    =======    ======    ======    =======
</TABLE>

<TABLE>
<CAPTION>

                                                      Year Ended September 30,
                                                    ----------------------------
                                                                1999
                                                    ----------------------------
                                                     United
                                                     States    Romania    Total
                                                     ------    -------    -----
     <S>                                            <C>        <C>       <C>
     Acquisition of properties:
      Proved properties ..........                  $21,029              $21,029
      Unproved properties ........                      928     $934       1,862
     Exploration .................
     Development .................                    1,073                1,073
                                                    -------     ----     -------
                                                    $23,030     $934     $23,964
                                                    =======     ====     =======
</TABLE>



                                       43
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

    For the years ended September 30, 1999, 2000 and 2001, the Company
incurred development costs related to booked proved undeveloped reserves of
$773, $2,324 and $1,347 respectively.

    Results of operations, excluding corporate overhead and interest expense,
from the Company's oil and gas producing activities are as follows:
<TABLE>
<CAPTION>

                                                      Year Ended September 30,
                                                     ---------------------------
                                                      2001       2000      1999
                                                      ----       ----      ----
     <S>                                             <C>       <C>        <C>
     Revenues:
      Crude oil, condensate, natural gas
       liquids and natural gas sales .............   $21,144   $17,959    $6,712
                                                     -------   -------    ------
     Costs and expenses:
      Production costs............................   $ 7,399   $ 6,194     1,910
      Depreciation, depletion and
       amortization...............................     3,348     2,990     1,937
      Impairment of foreign unproved
       properties.................................     2,765       832
                                                     -------   -------    ------
      Total costs and expenses....................    13,512    10,016     3,847
                                                     -------   -------    ------
     Income tax provision (benefit)...............     1,387    (6,553)      753
                                                     -------   -------    ------
     Income from oil and gas producing
       activities.................................   $ 6,245   $16,569    $2,112
                                                     =======   =======    ======
</TABLE>


    The income tax provision is computed at the effective tax rate for the
related fiscal year.



    Assuming conversion of oil and gas production into common equivalent units
of measure on the basis of energy content, depletion rates per equivalent MCF
(thousand cubic feet) of natural gas were as follows:
<TABLE>
<CAPTION>

                                                         Year Ended September 30,
                                                         ------------------------
                                                          2001     2000    1999
                                                          ----     ----    ----
     <S>                                                  <C>     <C>      <C>
     Depletion rate per equivalent MCF
      of natural gas..................................    $0.72   $0.57    $0.71
                                                          =====   =====    =====
</TABLE>


    The increase in the depletion rate in fiscal 2001 resulted primarily
because the Company's reserves qualitites decreased significantly as a result
of lower oil and gas prices at September 30, 2001. The decrease in reserve
quantities without a similar decrease in related costs resulted in a higher
depletion rate. In addition, in fiscal 2001, the Company acquired significant
East Texas reserves at a higher cost per mcfe than the cost for the Company's
existing reserves at the time of the acquisition (see Note 4).

    The decrease in the depletion rate in fiscal 2000 resulted primarily
because the Company's reserve quantities increased significantly as a result
of higher oil and gas prices at September 30, 2000. The increase in reserve
quantities without a similar increase in costs resulted in the lower depletion
rate.

    Under the full cost method of accounting, the net book value of oil and
gas properties less related deferred income taxes (the "costs to be
recovered"), may not exceed a calculated "full cost ceiling." The ceiling
limitation is the discounted estimated after-tax future net revenues from oil
and gas properties. The ceiling is imposed separately by country. In
calculating future net revenues, current prices and costs are generally held
constant indefinitely. The costs to be recovered are compared to the ceiling
on a quarterly basis. If the costs to be recovered exceed the ceiling, the
excess is written off as an expense, except as discussed in the following
paragraph.

    If, subsequent to the end of the reporting period, but prior to the
applicable financial statements being published, prices increase to levels
such that the ceiling would exceed the costs to be recovered, a write down
otherwise indicated at the end of the reporting period is not required to be
reported. A write down indicated at the end of a reporting period is also not
required if the value of additional reserves proved up on properties after the
end of the reporting period, but prior to the publishing of the financial
statements, would result in the ceiling exceeding the costs to be recovered,
as long as the properties were owned at the end of the reporting period.


                                       44
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

    An expense recorded in one period may not be reversed in a subsequent
period even though higher oil and gas prices may have increased the ceiling
applicable to the subsequent period.

    Based on oil and natural gas cash market prices as of September 30, 2001,
the Company's costs to be recovered for its domestic reserves exceeded the
related ceiling values by $437. However, the cash market prices of natural gas
subsequently increased significantly. Based on cash market prices of oil and
natural gas as at December 18, 2001, the Company determined that there was no
impairment of its domestic oil and gas properties. Accordingly, the Company
did not record a reduction in the carrying value of its domestic oil and gas
properties at September 30, 2001.

    See Note 21.

NOTE 11 - PROVED OIL AND GAS RESERVES AND RESERVE VALUATION (UNAUDITED)

    Reserve estimates are based upon subjective engineering judgements made by
the Company's independent petroleum reservoir engineers, Huntley & Huntley and
Ralph E. Davis Associates, Inc. and may be affected by the limitations
inherent in such estimations. The process of estimating reserves is subject to
continuous revisions as additional information is made available through
drilling, testing, reservoir studies and production history. There can be no
assurance such estimates will not be materially revised in subsequent periods.

    Estimated quantities of proved reserves and changes therein, all of which
are domestic reserves, are summarized below:
<TABLE>
<CAPTION>

                                                          ("000's" Omitted)
                                                      -------------------------
                                                                   Natural Gas
                                                     Oil (BBLS)       (MCF)
                                                     ----------    ------------
     <S>                                             <C>           <C>
     Proved developed and undeveloped reserves:
         As of October 1, 1998 ....................       255            15,324
             Acquisitions .........................     2,021            12,529
             Revisions of previous estimates ......      (122)            2,520
             Production ...........................      (124)           (1,971)
                                                       ------           -------
         As of September 30, 1999 .................     2,030            28,402
             Acquisitions .........................     1,063             6,639
             Divestitures .........................      (974)             (236)
             Discoveries ..........................         1               317
             Revisions of previous estimates ......     2,894            12,728
             Production ...........................      (279)           (3,547)
                                                       ------           -------
         As of September 30, 2000 .................     4,735            44,303
             Acquisitions .........................       266            10,183
             Revisions of previous estimates ......    (1,730)          (20,711)
             Production ...........................      (262)           (3,083)
                                                       ------           -------
         As of September 30, 2001 .................     3,009            30,692
                                                       ======           =======
     Proved developed reserves:
         September 30, 1998 .......................       162            13,589
                                                       ======           =======
         September 30, 1999 .......................     1,788            23,547
                                                       ======           =======
         September 30, 2000 .......................     2,963            35,815
                                                       ======           =======
         September 30, 2001 .......................     1,890            26,480
                                                       ======           =======
</TABLE>


    Although the Company has participated in the drilling of five exploratory
wells in Romania, no proved reserves have yet been assigned to any of these
wells. As a result, all of the Company's proved oil and gas reserves are
located in the United States.


                                       45
<PAGE>


                            CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

    The following is a standardized measure of discounted future net cash
flows and changes therein relating to estimated proved oil and gas reserves,
as prescribed in Statement of Financial Accounting Standards No. 69. The
standardized measure of discounted future net cash flows does not purport to
present the fair market value of the Company's oil and gas properties. An
estimate of fair value would also take into account, among other factors, the
likelihood of future recoveries of oil and gas in excess of proved reserves,
anticipated future changes in prices of oil and gas and related development
and production costs, a discount factor based on market interest rates in
effect at the date of valuation and the risks inherent in reserve estimates.
<TABLE>
<CAPTION>

                                                         September 30,
                                                -------------------------------
                                                  2001       2000        1999
                                                  ----       ----        ----
     <S>                                        <C>        <C>         <C>
     Future cash inflows...................     $130,289   $371,784    $118,794
     Future production costs...............      (41,193)   (87,162)    (42,934)
     Future development costs..............       (8,585)   (12,620)     (4,229)
     Future income tax expense.............      (10,892)   (84,445)     (8,538)
                                                --------   --------    --------
     Future net cash flows.................       69,619    187,557      63,093
     Discount factor of 10% for estimated
      timing of future cash flows .........      (33,599)   (96,438)    (21,849)
                                                --------   --------    --------
     Standardized measure of discounted
      future cash flows ...................     $ 36,020   $ 91,119    $ 41,244
                                                ========   ========    ========
</TABLE>


    The future cash flows were computed using the applicable year-end prices
and costs that related to then existing proved oil and gas reserves in which
the Company has interests. The estimates of future income tax expense are
computed at the blended rate (Federal and state combined) of 36%.

    The following were the sources of changes in the standardized measure of
discounted future net cash flows:
<TABLE>
<CAPTION>

                                                               September 30,
                                                       ------------------------------
                                                         2001       2000       1999
                                                         ----       ----       ----
     <S>                                               <C>        <C>         <C>
     Standardized measure, beginning of year.......    $ 91,119   $ 41,244    $ 9,946
     Sale of oil and gas, net of production costs..     (13,745)   (11,083)    (4,324)
     Net changes in prices.........................     (62,271)    45,757      2,163
     Sale of reserves in place.....................                 (1,457)
     Purchase of reserves in place.................       7,662      6,757     22,215
     Changes in estimated future development costs.       1,518     (5,039)     2,405
     Development costs incurred during the period
      that reduced future development costs .......       2,113      2,595      1,073
     Revisions in reserve quantity estimates.......     (27,596)    76,355      1,438
     Discoveries of reserves.......................                    963
     Net changes in income taxes...................      31,054    (32,031)       745
     Accretion of discount.........................       9,112      4,286        995
     Other:
         Change in timing of production............        (944)   (36,168)    12,055
         Other factors.............................      (2,002)    (1,060)    (7,467)
                                                       --------   --------    -------
     Standardized measure, end of year.............    $ 36,020   $ 91,119    $41,244
                                                       ========   ========    =======
</TABLE>


    See Note 21.

    The Company estimates that it will spend approximately $5,678, $35 and $0
to develop booked proved undeveloped reserves in the fiscal years ended
September 30, 2002, 2003 and 2004, respectively.


                                       46
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

NOTE 12 - CONTINGENT ENVIRONMENTAL LIABILITY

    In December 1995, IRLP, an inactive subsidiary of the Company, sold its
refinery, the Indian Refinery, to American Western, an unaffiliated party. As
part of the related purchase and sale agreement, American Western assumed all
environmental liabilities and indemnified IRLP with respect thereto.
Subsequently, American Western filed for bankruptcy and sold the Indian
Refinery to an outside party pursuant to a bankruptcy proceeding. The outside
party has substantially dismantled the Indian Refinery.

    American Western recently filed a Plan of Liquidation. American Western
anticipates that the Plan of Liquidation will be confirmed in January 2002.

    During fiscal 1998, the Company was informed that the United States
Environmental Protection Agency ("EPA") had investigated offsite acid sludge
waste found near the Indian Refinery and had investigated and remediated
surface contamination on the Indian Refinery property. Neither the Company nor
IRLP was initially named with respect to these two actions.

    In October 1998, the EPA named the Company and two of its inactive
refining subsidiaries as potentially responsible parties for the expected
clean-up of the Indian Refinery. In addition, eighteen other parties were
named including Texaco Refining and Marketing, Inc. ("Texaco"), the refinery
operator for over 50 years. A subsidiary of Texaco had owned the refinery
until December of 1988. The Company subsequently responded to the EPA
indicating that it was neither the owner nor the operator of the Indian
Refinery and thus not responsible for its remediation.

    In November 1999, the Company received a request for information from the
EPA concerning the Company's involvement in the ownership and operation of the
Indian Refinery. The Company responded to the EPA information request in
January 2000.

    On August 7, 2000, the Company received notice of a claim against it and
two of its inactive refining subsidiaries from Texaco and its parent. Texaco
had made no previous claims against the Company although the Company's
subsidiaries had owned the refinery from August 1989 until December 1995. In
its claim, Texaco demanded that the Company and its former subsidiaries
indemnify Texaco for all liability resulting from environmental contamination
at and around the Indian Refinery. In addition, Texaco demanded that the
Company assume Texaco's defense in all matters relating to environmental
contamination at and around the Indian Refinery, including lawsuits, claims
and administrative actions initiated by the EPA and indemnify Texaco for costs
that Texaco has already incurred addressing environmental contamination at the
Indian Refinery. Finally, Texaco also claimed that the Company and two of its
inactive subsidiaries are liable to Texaco under the Federal Comprehensive
Environmental Response Compensation and Liability Act as owners and operators
of the Indian Refinery. The Company responded to Texaco disputing the factual
and theoretical basis for Texaco's claims against the Company. The Company's
management and special counsel subsequently met with representatives of Texaco
but the parties disagreed concerning Texaco's claims.

    The Company and its special counsel, Reed Smith LLP, believe that Texaco's
claims are utterly without merit and the Company intends to vigorously defend
itself against Texaco's claims and any lawsuits that may follow. In addition
to the numerous defenses that the Company has against Texaco's contractual
claim for indemnity, the Company and its special counsel believe that by the
express language of the agreement which Texaco construes to create an
indemnity, Texaco has irrevocably elected to forgo all rights of contractual
indemnification it might otherwise have had against any person, including the
Company.

    In September 1995, Powerine sold the Powerine Refinery to Kenyen Resources
("Kenyen"), an unaffiliated party. In January 1996, Powerine merged into a
subsidiary of Energy Merchant Corp. ("EMC"), an unaffiliated party, and EMC
assumed all environmental liabilities. In August 1998, EMC sold the Powerine
Refinery to a third party, which, we are informed, continues to seek financing
to restart the Powerine Refinery.

    In July of 1996, the Company was named a defendant in a class action
lawsuit concerning emissions from the Powerine Refinery. In April of 1997, the
court granted the Company's motion to quash the plaintiff's summons based upon
lack of jurisdiction and the Company is no longer involved in the case.


                                       47
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

    Although the environmental liabilities related to the Indian Refinery and
Powerine Refinery have been transferred to others, there can be no assurance
that the parties assuming such liabilities will be able to pay them. American
Western, owner of the Indian Refinery, filed for bankruptcy and is in the
process of liquidation. EMC, which assumed the environmental liabilities of
Powerine, sold the Powerine Refinery to an unrelated party, which we
understand is still seeking financing to restart that refinery. Furthermore,
as noted above, the EPA named the Company as a potentially responsible party
for remediation of the Indian Refinery and has requested and received relevant
information from the Company. Estimated gross undiscounted clean up costs for
this refinery are at least $80,000 - $150,000 according to third parties. If
the Company were found liable for the remediation of the Indian Refinery, it
could be required to pay a percentage of the clean-up costs. Since the
Company's subsidiary only operated the Indian Refinery five years, whereas
Texaco and others operated it over fifty years, the Company would expect that
its share of remediation liability would be proportional to its years of
operation, although such may not be the case. Furthermore, as noted above,
Texaco has claimed that the Company indemnified it for all environmental
liabilities related to the Indian Refinery. If Texaco were to sue the Company
on this theory and prevail in court, the Company could be held responsible for
the entire estimated clean up costs of $80,000-$150,000 or more. In such a
case, this cost would be far in excess of the Company's financial capability.

    An opinion 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), and
a recent opinion by the U.S. Appeals Court for the Fifth Circuit in Aviall
Services, Inc. v. Cooper Industries Inc., 263 F.3rd 134 (5th Cir. 2001)
vacated and reh'g granted, 278 F.3d 416 (Dec. 19, 2001) support the Company's
positions. Nevertheless, if funds for environmental clean-up are not provided
by these former and/or present owners, it is possible that the Company and/or
one of its former refining subsidiaries could be named parties in additional
legal actions to recover remediation costs. In recent years, government and
other plaintiffs have often sought redress for environmental liabilities from
the party most capable of payment without regard to responsibility or fault.
Whether or not the Company is ultimately held liable in such a circumstance,
should litigation involving the Company and/or IRLP occur, the Company would
probably incur substantial legal fees and experience a diversion of management
resources from other operations.

    Although the Company does not believe it is liable for any of its
subsidiaries' clean-up costs and intends to vigorously defend itself in such
regard, the Company cannot predict the ultimate outcome of these matters due
to inherent uncertainties.

NOTE 13 - COMMITMENTS, CONTINGENCIES AND LINE OF CREDIT

Operating Lease Commitments

    The Company has the following noncancellable operating lease commitments
and noncancellable sublease rentals at September 30, 2001:
<TABLE>
<CAPTION>

                                                          Lease         Sublease
     Year Ending September 30,                         Commitments       Rentals
     -------------------------                         -----------      --------
     <S>                                               <C>              <C>
     2002............................................    $  473         $     65
     2003............................................       470               66
     2004............................................       240
     2005............................................        76
                                                         ------         --------
     2006............................................    $1,259         $    131
                                                         ======         ========
</TABLE>


    Rent expense for the years ended September 30, 2001, 2000 and 1999 was
$456, $412 and $386, respectively.

Severance/Retention Obligations

    The Company has severance agreements with substantially all of its
employees, including five of its officers, that provide for severance
compensation in the event substantially all of the Company's or its
subsidiaries' assets are sold and the employees are terminated as a result of
such sale. Such termination severance commitments aggregated $1,101 at
September 30, 2001. No severance obligations were owed to employees at
September 30, 2001.


                                       48
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

Letters of Credit

    At September 30, 2001, the Company had issued letters of credit of $209
for oil and gas drilling, operating and plugging bonds. The letters of credit
are renewed semi-annually or annually.

Line of Credit

    See Note 21.

Legal Proceedings

Contingent Environmental Liabilities

        See Note 12.

General

Long Trusts Lawsuit

    In November 2000, the Company and three of its subsidiaries were
defendants in a jury trial in Rusk County, Texas. The plaintiffs in the case,
the Long Trusts, are non-operating working interest owners in wells previously
operated by Castle Texas Production Limited Partnership ("CTPLP"), an inactive
exploration and production subsidiary of the Company. The wells were among
those sold to Union Pacific Resources Corporation ("UPRC") in May 1997. The
Long Trusts claimed that CTPLP did not allow them to sell gas from March 1,
1996 to January 31, 1997 as required by applicable joint operating agreements,
and they sued CTPLP and the other defendants, claiming (among other things)
breach of contract, breach of fiduciary duty, conversion and conspiracy. The
plaintiffs sought actual damages, exemplary damages, pre-judgment and post-
judgment interest, attorney's fees and court costs. CTPLP counterclaimed for
approximately $150 of unpaid joint interests billings, interest, attorneys'
fees and court costs.

    After a three-week trial, the District Court in Rusk County submitted 36
questions to the jury which covered all of the claims and counterclaims in the
lawsuit. Based upon the jury's answers, the District Court entered judgement
granting plaintiffs' claims against the Company and its subsidiaries, as well
as CTPLP's counterclaim against the plaintiffs. The District Court issued an
amended judgement on September 5, 2001, which became final in December 2001.
The net amount awarded to the plaintiffs was approximately $2,700. The Company
and its subsidiaries have filed a notice of appeal with the Tyler Court of
Appeals and will continue to vigorously contest this matter.

    Jenkens and Gilchrest, special counsel to the Company does not consider an
unfavorable outcome to this lawsuit probable. The Company's management and
special counsel believe that several of the plaintiffs' primary legal theories
are contrary to established Texas law and that the Court's charge to the jury
was fatally defective. They further believe that any judgment for plaintiffs
based on those theories or on the jury's answers to certain questions in the
charge cannot stand and will be reversed on appeal. As a result, the Company
has not accrued any liability for this litigation. Nevertheless, to pursue the
appeal, the Company and its subsidiaries will be required to post a bond to
cover the net amount of damages awarded to the plaintiffs and to maintain that
bond until the resolution of the appeal (which may take several years). The
Company has included the letter of credit to support the bond, estimated at
approximately $3,000, in its line of credit with a major energy bank.

    See Note 21.

Larry Long Litigation

    In May 1996, Larry Long, representing himself and allegedly "others
similarly situated," filed suit against the Company, three of the Company's
natural gas marketing and transmission and exploration and production
subsidiaries, Atlantic Richfield Company ("ARCO"), B&A Pipeline Company, a
former subsidiary of ARCO ("B&A"), and MGNG in the Fourth Judicial District
Court of Rusk County, Texas. The plaintiff originally claimed, among other
things, that the defendants underpaid non-operating working interest owners,
royalty interest owners and overriding royalty interest owners with respect to
gas sold to Lone Star pursuant to the Lone Star Contract. Although no amount
of actual damages was specified in the plaintiff's initial pleadings, it
appeared that, based upon the volumes of gas sold to Lone Star, the plaintiff
may have been seeking actual damages in excess of $40,000.


                                       49
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

    After some initial discovery, the plaintiff's pleadings were significantly
amended. Another purported class representative, Travis Crim, was added as a
plaintiff, and ARCO, B&A and MGNG were dropped as defendants. Although it is
not completely clear from the amended petition, the plaintiffs apparently
limited their proposed class of plaintiffs to royalty owners and overriding
royalty owners in leases owned by the Company's exploration and production
subsidiary limited partnership. In amending their pleadings, the plaintiffs
revised their basic claim to seeking royalties on certain operating fees paid
by Lone Star to the Company's natural gas marketing subsidiary limited
partnership.

    In April 2000, Larry Long withdrew as a named plaintiff and in September
2000, the Company and the remaining named plaintiff agreed to settle the case
for a payment of $250 by the Company. In July 2001, the Company deposited $250
plus accrued interest of $9 in a litigation settlement account. As of
September 30, 2001, $106 had been disbursed from the account.

    See Note 21.

MGNG Litigation

    On May 4, 1998, CTPLP, a subsidiary of the Company, filed a lawsuit
against MGNG and MG Gathering Company ("MGC"), two subsidiaries of MG, in the
district court of Harris County, Texas. One of the Company's exploration and
production subsidiaries sought to recover gas measurement and transportation
expenses charged by the defendants in breach of a certain gas purchase
contract. Improper charges exceeded $750 before interest. In October of 1998,
MGNG and MGC filed a suit in Harris County, Texas. This suit sought
indemnification from two of the Company's subsidiaries in the event CTPLP won
its lawsuit against MGNG and MGC. The MG entities cited no basis for their
claim of indemnification. The management of the Company and special counsel
retained by the Company believe that the Company's subsidiary is entitled to
at least $750 plus interest and that the Company's two subsidiaries have no
indemnification obligations to MGNG or MGC. The parties participated in
mediation but were not able to resolve the issue.

    In October 1999, MGNG filed a second lawsuit against the Company and three
of its subsidiaries claiming $772 was owed to MGNG under a gas supply contract
between one of the Company's subsidiaries and MGNG. The suit was filed in the
district court of Harris County, Texas. The Company and its subsidiaries
believed that they do not owe $772 and were entitled to legally offset some or
all of the $772 claimed against amounts owed to CTPLP by MGNG for improper gas
measurement and transportation deductions. The Castle entities answered this
suit denying MGNG's claims based partially on the right of offset.

    In September 2000, the parties agreed to settle all lawsuits. Under the
terms of the settlement the amount claimed by MGNG under a gas supply contract
was reduced by $325 and the net amount payable to MGNG was set at $400 and the
parties signed mutual releases.

    See Note 21.

Pilgreen Litigation

    As part of the AmBrit purchase, Castle Exploration Company, Inc. ("CECI")
acquired a 10.65% overriding royalty interest ("ORRI") in the Pilgreen #2ST
gas well in Texas. Because of title disputes, AmBrit and other interest owners
had previously filed claims against the operator of the Pilgreen well, and
CECI acquired post January 1, 1999 rights in that litigation. Although revenue
attributed to the ORRI has been suspended by the operator since first
production, because of recent related appellate decisions and settlement
negotiations, the Company believes that revenue attributable to the ORR should
be released to CECI in the near future. As of September 30, 2001,
approximately $415 attributable to CECI's share of the ORRI revenue was
suspended. The Company's policy is to recognize the suspended revenue only
when and if it is received.

GAMXX

    On February 27, 1998, the Company entered into an agreement with Alexander
Allen, Inc. ("AA") concerning amounts owed to the Company by AA and its
subsidiary, GAMXX Energy, Inc. ("GAMXX"). The Company had made loans to GAMXX
through 1991 in the aggregate amount of approximately $8,000. When

                                       50
 <PAGE>


                          CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

GAMXX was unable to obtain financing, the Company recorded a one hundred
percent loss provision on its loans to GAMXX in 1991 and 1992 while still
retaining its lender's lien against GAMXX.

    Pursuant to the terms of the GAMXX Agreement, the Company was to receive
$1,000 cash in settlement for its loans when GAMXX closed on its financing.
GAMXX expected such closing not later than May 31, 1998 but failed to do so.
As a result, the Company elected to terminate the GAMXX Agreement. Pursuant to
the Agreement, GAMXX agreed to assist the Company in selling GAMXX's assets or
the Company's investment in GAMXX. The Company is currently seeking to dispose
of its lender's interest in GAMXX and recover some of the loan to GAMXX.

    The Company has carried its loans to GAMXX at zero for the last eight
years. The Company will record any proceeds as "other income" if and when it
collects such amount.

Hedging Activities

    Until June 1, 1999, the Company's natural gas marketing subsidiary
utilized natural gas swaps to reduce its exposure to changes in the market
price of natural gas. Effective May 31, 1999 all natural gas marketing
contracts terminated by their own terms. As a result of these hedging
transactions, the cost of gas purchases increased $609 for the year ended
September 30, 1999.

    On June 1, 1999, the Company acquired all of the oil and gas assets of
AmBrit (see Note 4) and thereafter commenced hedging sales of the related oil
and gas production. As of September 30, 1999, the Company had hedged
approximately 54% of its anticipated consolidated crude oil production and
approximately 39% of its anticipated consolidated natural gas production for
the period from October 1, 1999 to September 30, 2000. The Company used
futures contracts to hedge such production. The average hedged prices for
crude oil and natural gas, which are based upon futures price on the New York
Mercantile Exchange, were $19.85 per barrel of crude oil and $2.66 per mcf of
gas. The Company accounted for these futures contracts as hedges and the
differences between the hedged price and the exchange price increased or
decreased the oil and gas revenues resulting from the sale of production by
the Company. Oil and gas production was not hedged after July 2000 production.
As a result of these hedging transactions, oil and gas sales decreased $1,528
and $150 for the fiscal years ended September 30, 2000 and 1999, respectively.

    At September 30, 2001 and December 14, 2001, the Company had not hedged
its anticipated future oil and gas production.

NOTE 14 - EMPLOYEE BENEFIT PLAN

401(K) PLAN

    On October 1, 1995, the Company adopted a 401(k) plan (the "Plan") for its
employees and those of its subsidiaries. All employees are eligible to
participate. Employees participating in the Plan can authorize the Company to
contribute up to 15% of their gross compensation to the Plan. The Company
matches such voluntary employee contributions up to 3% of employee gross
compensation. Employees' contributions to the Plan cannot exceed thresholds
set by the Secretary of the Treasury. Vesting of Company contributions is
immediate. During the years ended September 30, 2001, 2000 and 1999, the
Company's contributions to the Plan aggregated $50, $46 and $37, respectively.

Post-Retirement Benefits

    Neither the Company nor its subsidiaries provide any other post-retirement
plans for employees.

NOTE 15 - STOCKHOLDERS' EQUITY

    On December 29, 1999, the Company's Board of Directors declared a stock
split in the form of a 200% stock dividend applicable to all stockholders of
record on January 12, 2000. The additional shares were paid on January 31,
2000 and the Company's shares first traded at post-split prices on February 1,
2000. The stock split applied only to the Company's outstanding shares on
January 12, 2000 (2,337,629 shares) and did not apply to treasury shares
(4,491,017 shares) on that date. As a result of the stock split, 4,675,258
additional shares were issued and the Company's common stock book value was
increased $2,338 to reflect additional par value

                                       51
<PAGE>
                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

applicable to the additional shares issued to effect the stock split. All
share changes, including those affecting the recorded book value of common
stock, have been recorded retroactively.

    From November 1996 until September 30, 2001, the Company's Board of
Directors authorized the Company to purchase up to 5,267,966 of its
outstanding shares of common stock on the open market. As of September 30,
2001, 4,871,020 shares (13,973,054 shares before taking into account the 200%
stock dividend effective January 31, 2000) had been repurchased at a cost of
$66,506. The repurchased shares are held in treasury.

    On June 30, 1997, the Company's Board of Directors approved a dividend
policy of $.20 per share per year, payable quarterly. The dividend policy
remains in effect until rescinded or changed by the Board of Directors.
Quarterly dividends of $.05 per share have subsequently been paid.

    See Note 21

NOTE 16 - STOCK OPTIONS AND WARRANTS

    Option and warrant activities during each of the three years ended
September 30, 2001 are as follows (in whole units):
<TABLE>
<CAPTION>

                                           Incentive
                                              Plan         Other
                                            Options       Options       Total
                                            -------       -------       -----
     <S>                                   <C>          <C>           <C>
     Outstanding at October 1, 1998......     195,000       20,000      215,000
     Issued..............................      15,000                    15,000
     Exercised...........................     (25,000)                  (25,000)
     Repurchased.........................     (10,000)                  (10,000)
                                           ----------   ----------    ---------
     Outstanding at September 30, 1999...     175,000       20,000      195,000
     Effect of 200% stock dividend
      (see Note 15) .....................     350,000       40,000      390,000
     Issued..............................     105,000                   105,000
                                           ----------   ----------    ---------
     Outstanding at September 30, 2000...     630,000       60,000      690,000
     Issued..............................      60,000                    60,000
                                           ----------   ----------    ---------
     Outstanding at September 30, 2001...     690,000       60,000      750,000
                                           ==========   ==========    =========
     Exercisable at September 30, 2001...     690,000       60,000      750,000
                                           ==========   ==========    =========
     Reserved at September 30, 2001......   1,687,500       60,000    1,747,500
                                           ==========   ==========    =========
     Reserved at September 30, 2000......   1,687,500       60,000    1,747,500
                                           ==========   ==========    =========
     Reserved at September 30, 1999......   1,687,500       60,000    1,747,500
                                           ==========   ==========    =========
     Exercise prices at:
      September 30, 2001.................  $     3.42-  $     3.79
                                           $     8.58
      September 30, 2000.................  $     3.42-  $     3.79
                                           $     8.58
      September 30, 1999.................  $     3.42-  $     3.79
                                           $     5.75
      Exercise Termination Dates.........   5/17/2003-   4/23/2007    5/17/2003-
                                            1/02/2011                 1/02/2011
</TABLE>


    In fiscal 1993, the Company adopted the 1992 Executive Equity Incentive
Plan (the "Incentive Plan"). The purpose of the Incentive Plan is to increase
the ownership of common stock of the Company by those non-union key employees
(including officers and directors who are officers) and outside directors who
contribute to the continued growth, development and financial success of the
Company and its subsidiaries, and to attract and retain key employees and
reward them for the Company's profitable performance.


                                       52
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

    The Incentive Plan provides that an aggregate of 1,687,500 shares (after
taking into account the 200% stock dividend effective January 31, 2000) of
common stock of the Company will be available for awards in the form of stock
options, including incentive stock options and non-qualified stock options
generally at prices at or in excess of market prices at the date of grant.

    The Incentive Plan also provides that each outside director of the Company
will annually be granted an option to purchase 15,000 shares of common stock
at fair market value on the date of grant.

    The Company applies Accounting Principles Board Opinion Number 25 in
accounting for options and warrants and accordingly recognizes no compensation
cost for its stock options and warrants for grants with an exercise price
equal to the current fair market value. The following reflect the Company's
pro-forma net income and net income per share had the Company determined
compensation costs based upon fair market values of options and warrants at
the grant date pursuant to SFAS 123 as well as the related disclosures
required by SFAS 123.

    A summary of the Company's stock option and warrant activity from October
1, 1998 to September 30, 2001 is as follows:
<TABLE>
<CAPTION>

                                                                        Weighted
                                                                        Average
                                                             Options     Price
                                                             -------     -----
     <S>                                                     <C>        <C>
     Outstanding - October 1, 1998 .......................   215,000     $12.96
     Issued ..............................................    15,000      17.25
     Exercised ...........................................   (25,000)     10.25
     Repurchased .........................................   (10,000)     10.75
                                                             -------    -------
     Balance - September 30, 1999 ........................   195,000      13.75
     Effect of 200% stock dividend (see Note 15) .........   390,000      (9.17)
     Issued ..............................................   105,000       7.89
                                                             -------    -------
     Outstanding - September 30, 2000 ....................   690,000       5.09
     Issued ..............................................    60,000       7.00
                                                             -------    -------
     Outstanding - September 30, 2001 ....................   750,000    $  5.24
                                                             =======    =======
</TABLE>


    At September 30, 2001, exercise prices for outstanding options ranged from
$3.42 to $8.58. The weighted average remaining contractual life of such
options was 5.6 years.

    The per share weighted average fair values of stock options issued during
fiscal 2001, 2000 and fiscal 1999 were $2.41, $3.29 and $4.56, respectively,
on the dates of issuance using the Black-Scholes option pricing model with the
following weighted average assumptions: average expected dividend yield - 3.0%
in 2001, 3.0% in 2000 and 3.5% in 1999; risk free interest rate - 3.50% in
2001, 5.54% in 2000 and 6.32% in 1999; expected life of 10 years in 2001, 2000
and 1999 and volatility factor of .38 in 2001, .44 in 2000, and .22 in 1999.

    The Black-Scholes option valuation model was developed for use in
estimating the fair value of traded options which have no vesting restrictions
and are fully transferable. In addition, option valuation models require the
input of highly subjective assumptions including the expected stock price
volatility. Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes in
the subjective input assumptions can materially affect the fair value
estimate, in management's opinion, the existing models do not necessarily
provide a reliable single measure of the fair value of its employee stock
options.


                                       53
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

    Proforma net income and earnings per share had the Company accounted for
its options under the fair value method of SFAS 123 is as follows:
<TABLE>
<CAPTION>

                                                      Year Ending September 30,
                                                      -------------------------
                                                       2001     2000      1999
                                                       ----     ----      ----
     <S>                                              <C>      <C>       <C>
     Net income as reported........................   $1,716   $5,069    $8,266
     Adjustment required by SFAS 123...............     (145)    (346)     (152)
                                                      ------   ------    ------
     Pro-forma net income..........................   $1,571   $4,723    $8,114
                                                      ======   ======    ======
     Pro-forma net income per share:
      Basic........................................   $ 0.24   $  .68    $  .99
                                                      ======   ======    ======
      Diluted......................................   $ 0.23   $  .66    $  .97
                                                      ======   ======    ======
</TABLE>


NOTE 17 - INCOME TAXES

    Provisions for (benefit of) income taxes consist of:
<TABLE>
<CAPTION>

                                                           September 30,
                                                     --------------------------
                                                     2001      2000       1999
                                                     ----      ----       ----
     <S>                                             <C>     <C>         <C>
     Provision for (benefit of) income taxes:
      Current:
         Federal..................................   $   4   ($    35)   $  193
         State....................................                           (2)
      Deferred:
         Federal..................................     786        922     2,209
         State....................................      22         26        68
     Adjustment to the valuation allowance for
       deferred taxes:
      Federal.....................................    (419)    (3,115)      475
      State.......................................     (12)       (89)       13
                                                     -----   --------    ------
                                                     $ 381   ($ 2,291)   $2,956
                                                     =====   ========    ======
</TABLE>


    Deferred tax assets (liabilities) are comprised of the following at
September 30, 2001 and 2000:
<TABLE>
<CAPTION>

                                                                September 30,
                                                              -----------------
                                                               2001      2000
                                                               ----      ----
     <S>                                                     <C>        <C>
     Operating losses and tax credit carryforwards .......   $ 4,715    $ 4,993
     Statutory depletion carryovers ......................     3,903      3,689
     Depletion accounting ................................    (5,341)    (3,602)
     Discontinued net refining operations ................       866        866
     Losses in foreign subsidiaries ......................     1,295        300
                                                             -------    -------
                                                               5,438      6,246
     Valuation allowance .................................    (3,559)    (3,990)
                                                             -------    -------
                                                             $ 1,879    $ 2,256
                                                             =======    =======
     Deferred tax assets - current .......................   $ 1,879    $ 2,256
                                                             -------    -------
                                                             $ 1,879    $ 2,256
                                                             =======    =======
</TABLE>


    At September 30, 2001, the Company determined that a portion of the
deferred tax asset would more likely than not be realized based upon estimates
of future taxable income and upon the projected taxable income

                                       54
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

resulting from the anticipated sale of its oil and gas assets to Delta and
accordingly decreased the valuation allowance by $431 to $3,559.

    If recent decreases in oil and gas prices continue and if the sale of the
Company's oil and gas assets to Delta is not consummated, the Company may be
required to increase its valuation allowance.

    See Note 21.

    At September 30, 2000, the Company determined that it was more likely than
not that a portion of the deferred tax assets would be realized, based on
current projections of taxable income due to higher commodity prices at
September 30, 2000, and the valuation allowance was decreased by $3,204 to a
total valuation allowance of $3,990.

    The income tax provision (benefit) differs from the amount computed by
applying the statutory federal income tax rate to income before income taxes
as follows:
<TABLE>
<CAPTION>

                                                      Year Ended September 30,
                                                     --------------------------
                                                     2001      2000      1999
                                                     ----      ----      ----
     <S>                                             <C>     <C>        <C>
     Tax at statutory rate.......................    $ 734   $   972    $ 3,928
     State taxes, net of federal benefit.........        7       (42)        51
     Revision of tax estimates and
      contingencies..............................       50                 (151)
     Statutory depletion.........................                        (1,330)
     Increase (decrease) in valuation
      allowance..................................     (431)   (3,204)       489
     Other.......................................       21       (17)       (31)
                                                     -----   -------    -------
                                                     $ 381   ($2,291)   $ 2,956
                                                     =====   =======    =======
</TABLE>


    At September 30, 2001, the Company had the following tax carryforwards
available:
<TABLE>
<CAPTION>

                                                              Federal Tax
                                                          ---------------------
                                                                    Alternative
                                                                      Minimum
                                                         Regular        Tax
                                                         -------    -----------
     <S>                                                 <C>        <C>
     Net operating loss ..............................   $ 2,674      $24,021
     Alternative minimum tax credits .................   $ 3,752          N/A
     Statutory depletion .............................   $10,841      $   440
</TABLE>


    The net operating loss carryforwards expire from 2001 through 2010.

    On September 9, 1994, the Company experienced a change of ownership for
tax purposes. As a result of such change of ownership, the Company's net
operating loss carryforward became subject to an annual limitation of $7,845.
At September 30, 2001 all net operating loss carryforwards of the Company were
no longer subject to the annual limitation.

    The Company also has approximately $58,688 in individual state tax loss
carryforwards available at September 30, 2001. Approximately $47,287 of such
carryforwards are primarily available to offset taxable income apportioned to
certain states in which the Company has no operations and currently has no
plans for future operations. As a result, it is probable most of such state
tax carryforwards will expire unused.

NOTE 18 - RELATED PARTIES

    In June 1999, the Company repurchased 24,700 (74,100 after stock split)
shares of the Company's common stock from an officer of the Company. Such
shares were repurchased at the closing stock price on the date of sale less
$.125, resulting in a payment of $434 to the officer. The shares were
repurchased pursuant to the Company's share repurchase program.


                                       55
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

    Another officer of the Company is a 10% shareholder in an unaffiliated
company that is entitled to receive 12.5% of the Company's share of net cash
flow from its Romanian joint venture after the Company has recovered its
investment in Romania.

NOTE 19 - BUSINESS SEGMENTS

    As of September 30, 1995, the Company had disposed of its refining segment
of the energy business (see Note 3) and operated in only two business segments
- natural gas marketing and transmission and exploration and production. In
May 1997, the Company sold its pipeline (natural gas transmission) to a
subsidiary of UPRC (see Note 4). As a result, the Company was no longer in the
natural gas transmission segment but continued to operate in the natural gas
marketing and exploration and production segments. On May 31, 1999, the
Company's long-term gas sales and gas supply contracts expired by their own
terms and the Company exited the natural gas marketing business.

    The Company does not allocate interest income, interest expense or income
tax expense to these segments.
<TABLE>
<CAPTION>

                                                                               Year Ended September 30, 2001
                                                        ---------------------------------------------------------------------------
                                                        Natural Gas     Oil & Gas                       Eliminations
                                                         Marketing     Exploration                          and
                                                            and            and           Refining        Corporate
                                                        Transmission    Production    (Discontinued)       Items       Consolidated
                                                        ------------   -----------    --------------    ------------   ------------
     <S>                                                <C>            <C>            <C>               <C>            <C>
     Revenues.......................................                     $ 21,144                                         $21,144
     Operating income (loss)........................                     $  5,682                        ($  4,169)       $ 1,513
     Identifiable assets............................      $67,702*       $105,238                        ($113,822)       $59,118
     Capital expenditures...........................                     $ 15,531                                         $15,531
     Depreciation, depletion and amortization.......                     $  3,468                        $       2        $ 3,470
</TABLE>

<TABLE>
<CAPTION>

                                                                               Year Ended September 30, 2000
                                                        ---------------------------------------------------------------------------
                                                        Natural Gas     Oil & Gas                       Eliminations
                                                         Marketing     Exploration                          and
                                                            and            and           Refining        Corporate
                                                        Transmission    Production    (Discontinued)       Items       Consolidated
                                                        ------------   -----------    --------------    ------------   ------------
     <S>                                                <C>            <C>            <C>               <C>            <C>
     Revenues.......................................                     $17,959                                          $17,959
     Operating income (loss)........................                     $ 5,686                          ($ 3,717)       $ 1,969
     Identifiable assets............................      $67,727*       $92,229                          ($96,661)       $63,295
     Capital expenditures...........................                     $11,399                                          $11,399
     Depreciation, depletion and amortization.......                     $ 3,207                          $      2        $ 3,209
</TABLE>



                                       56
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

<TABLE>
<CAPTION>

                                                                               Year Ended September 30, 1999
                                                        ---------------------------------------------------------------------------
                                                        Natural Gas     Oil & Gas                       Eliminations
                                                         Marketing     Exploration                          and
                                                            and            and           Refining        Corporate
                                                        Transmission    Production    (Discontinued)       Items       Consolidated
                                                        ------------   -----------    --------------    ------------   ------------
     <S>                                                <C>            <C>            <C>               <C>            <C>
     Revenues.......................................      $50,067        $ 7,190                                          $57,257
     Operating income (loss)........................      $11,563        $ 1,718                          ($ 4,112)       $ 9,169
     Identifiable assets............................      $79,026*       $67,720                          ($87,208)       $59,538
     Capital expenditures...........................                     $24,065                                          $24,065
     Depreciation, depletion and amortization.......      $ 6,284        $ 2,046                                          $ 8,330
</TABLE>

---------------

        *   Consists primarily of intracompany receivables.

    For the year ended September 30, 1999, sales by the Company's natural gas
marketing subsidiary to Lone Star Gas Company under the Lone Star Contract
aggregated $46,802. These amounts constituted approximately 82% of
consolidated revenues for the year ended September 30, 1999. The Lone Star
contract terminated in May 1999.

    At the present time, the Company's consolidated revenues consist entirely
of oil and gas sales. Three purchasers of the Company's oil and gas production
currently account for approximately 43% of consolidated production. Sales
derived from these three purchasers for the year end September 30, 2001
aggregated $2,871, $2,611 and $2,603.

NOTE 20 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS

    Cash and Cash Equivalents - the carrying amount is a reasonable estimate
of fair value.

    Marketable securities are related solely to the Company's investment in
Penn Octane, Delta and Chevron/Texaco common stock and options to buy Penn
Octane stock and are recorded at fair market value. Market value for common
stock is computed to equal the closing share price at year end times the
number of shares held by the Company. Fair market value for options is
computed using the Black - Scholes option valuation model.

    Other Current Assets and Current Liabilities - the Company believes that
the book values of other current assets and current liabilities approximate
the market values.

NOTE 21 - SUBSEQUENT EVENTS

    Subsequent to September 30, 2001, the Company disbursed the remaining $153
from the Larry Long Litigation settlement account (see Note 13).

    Subsequent to September 30, 2001, the Company paid MGNG $400 in settlement
of the MGNG Litigation (see Note 13).

    In November 2001, the Company entered into an agreement for a line of
credit of up to $40,000 with an energy bank. Pursuant to the related agreement
the energy bank agreed to make available to the Company loans and letters of
credit not to exceed a borrowing base determined by the value of the Company's
oil and gas reserves using parameters set by the bank. Such borrowing based
will be determined no less than semi-annually. The loans and letters of credit
will be secured by the Company's oil and gas properties to the extent the
amount outstanding under the facility exceeds $10,000. Interest under the
facility will accrue at the bank's prime rate or at a LIBOR rate - the choice
of rates being determined by the Company. Letters of credit issued under the
facility will accrue interest at 2.25% annually. Loans outstanding under the
facility will be repaid pursuant to a schedule set by the bank but
redetermined at each borrowing base determination date. In addition, the
Company is subject to typical financial covenants including minimum tangible
net worth, debt service coverage, interest coverage and current ratio
limitations, limitations on annual and quarterly dividends the Company may pay
to shareholders and

                                       57
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

other limitations governing capital expenditures. The facility is scheduled to
terminate November 30, 2003. The facility also includes a provision to provide
letters of credit of up to $3,000 as may be required for the Long Trusts
Lawsuit litigation (see Note 13).

    On December 11, 2001, the Company entered into a letter of intent to sell
all of its domestic oil and gas assets to Delta for $20,000 and 9,566,000
shares of commons stock of Delta. The effective date of the proposed sale is
October 1, 2001 and the expected closing date is April 30, 2002 or later. The
sale is subject to execution of a definitive purchase and sale agreement by
both parties, approval of the transaction by both Delta's and the Company's
directors and approval of the issuance of the shares to Castle by Delta's
shareholders.

    If the sale to Delta is not consummated, the Company could continue to
operate as it does currently or pursue other alternative strategies.

NOTE 22 - QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>

                                                                              First          Second        Third         Fourth
                                                                             Quarter         Quarter      Quarter        Quarter
                                                                          (December 31)    (March 31)    (June 30)   (September 30)
                                                                          -------------    ----------    ---------   --------------
     <S>                                                                  <C>              <C>           <C>         <C>
     Year Ended September 30, 2001:
      Revenues.........................................................       $5,394         $ 6,316      $5,347          $4,087
      Operating income (loss)..........................................       $1,533         $ 2,174      $  511         ($2,705)
      Net income (loss)................................................       $1,110         $ 1,531      $  397         ($1,322)
      Net income per share (diluted)...................................       $  .16         $   .22      $  .06         ($ .20)
     Year Ended September 30, 2000:
      Revenues.........................................................       $4,085          $3,318      $4,945         $ 5,611
      Operating income (loss)..........................................       $   32         ($  387)     $  835         $ 1,489
      Net income (loss)................................................       $  259         ($  277)     $1,024         $ 4,063
      Net income (loss) per share (diluted)............................       $  .04         ($ .04)      $  .15         $   .58
</TABLE>


    For the year ended September 30, 2000 revenues from well operations have
been retroactively reclassified as reductions of oil and gas production costs.

    The sums of the quarterly per share amounts differ from the annual per
share amounts primarily because the stock purchases made by the Company were
not made in equal amounts and at corresponding times each quarter.


                                       58
<PAGE>


                           CASTLE ENERGY CORPORATION
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
                  ("$000's" Omitted Except Per Share Amounts)

                          Independent Auditors' Report


The Board of Directors
Castle Energy Corporation:

We have audited the accompanying consolidated balance sheets of Castle Energy
Corporation and subsidiaries as of September 30, 2001 and 2000, and the
related consolidated statements of operations, stockholders' equity and other
comprehensive income, and cash flows for each of the years in the three year
period ended September 30, 2001. These consolidated financial statements are
the responsibility of the Company's management. Our responsibility is to
express an opinion on these consolidated financial statements based on our
audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United State of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Castle
Energy Corporation and subsidiaries as of September 30, 2001 and 2000, and the
results of their operations and their cash flows for each of the years in the
three year period ended September 30, 2001 in conformity with accounting
principles generally accepted in the United States of America.

                                    KPMG LLP

Houston, Texas
December 18, 2001


                                       59

<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE

    None


                                       60

<PAGE>
                                    PART III

    None

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT**

ITEM 11. EXECUTIVE COMPENSATION**

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT**

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS - NOT APPLICABLE
---------------

**  The information required by Items 10, 11, 12 and 13 is incorporated by
    reference to the Registrant's Proxy Statement for its 2002 Annual Meeting
    of Stockholders.


                                       61

<PAGE>
                                    PART IV


ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)     1. and 2. Financial Statements and Financial Statement Schedules

    Financial statements and schedules filed as part of this Report on Form
10-K are listed in Item 8 of this Form 10-K.

3.  Exhibits

    The Exhibits required by Item 601 of Regulation S-K and filed herewith or
incorporated by reference herein are listed in the Exhibit Index below.

<TABLE>
<CAPTION>
Exhibit Number        Description of Document
  --------------      -----------------------

<S>                   <C>
    3.1               Restated Certificate of Incorporation(15)

    3.2               Bylaws(10)

    4.1               Specimen Stock Certificate representing Common Stock(8)

    4.2               Rights Agreement between Castle Energy Corporation and American Stock Transfer and Trust Company as Rights
                      Agent, dated as of April 21, 1994(10)

    10.33             Castle Energy Corporation 1992 Executive Equity Incentive Plan(8)

    10.34             First Amendment to Castle Energy Corporation 1992 Executive Equity Incentive Plan, effective May 11, 1993(8)

    10.124            Asset Purchase Agreement dated February 27, 1998 by and between Castle Energy Corporation and Alexander
                      Allen, Inc.(21)

    10.125            Rollover and Assignment Agreement, dated December 1, 1998 between Penn Octane Corporation and Certain
                      Lenders, including Castle Energy Corporation(22)

    10.126            Purchase and Sale Agreement by and between AmBrit Energy Corp. and Castle Exploration Company, Inc.,
                      effective January 1, 1999(23)

    10.127            Agreement to Exchange $.9 Million Secured Notes Into Senior Preferred Stock of Penn Octane Corporation dated
                      March 3, 1999(23)

    10.128            Credit Agreement by and among Castle Exploration Company, Inc. and Comerica Bank-Texas, effective May 28,
                      1999(24)

    10.129            Purchase and Sale Agreement by and between Costilla Redeco Energy LLC and Castle Exploration Company, Inc.,
                      effective May 31, 1999(24)

    10.130            Letter dated July 22, 1999 between Penn Octane Corporation and Castle Energy Corporation(26)

    10.131            Letter dated July 29, 1999 between Penn Octane Corporation and Castle Energy Corporation(26)

    10.132            Castle Energy Corporation Severance Benefit Plan(26)

    10.133            Asset Acquisition Agreement between Castle Exploration Company, Inc., Deerlick Creek Partners, I., L.P. and
                      Deven Resources, Inc, effective September 1, 1999(27)

    10.134            Purchase and Sale Agreement, dated December 15, 1999, between Whiting Park Production, Ltd. and Castle
                      Exploration Company, Inc.(27)

    10.135            Asset Acquisition Agreement between Castle Exploration Company, Inc, and American Refining and Exploration
                      Company, Deven Resources, Inc., CMS/Castle Development Fund I L.P., effective as of October 1, 1999(27)

    10.136            Promissary Note between CEC, Inc. and Penn Octane Corporation(28)

    10.137            Purchase Agreement between CEC, Inc. and Penn Octane Corporation Effective January 5, 2000(28)
</TABLE>



                                       62

<PAGE>

<TABLE>
<CAPTION>
Exhibit Number        Description of Document
  --------------      -----------------------

<S>                   <C>
    10.138            Purchase and Sale Agreement, dated August 6, 2000 between and among Castle Exploration Company, Inc., Parks
                      and Luttrell Energy Partners L.P. and Parks and Luttrell Energy, Inc.(31)

    10.139            Purchase and Sale Agreement dated August 4, 2000 between Castle Offshore LLC, BWAB Limited Liability Company
                      and Delta Petroleum Company(31)

    10.140            Agreement to Transfer a Membership Interest In Networked Energy LLC to CEC, Inc., dated August 31, 2000(31)

    10.141            Second Amendment - Promissary Note of Penn Octane Corporation(29)

    10.142            Purchase and Sale Agreement, dated April 1, 2001, between Strand Energy LC and Castle Exploration Company,
                      Inc.(30)

    10.143            Credit Agreement as of November 26, 2001 among Castle Exploration Company, Inc. and Castle Energy
                      Corporation and Bank of Texas National Association

    11.1              Statement re: Computation of Earnings Per Share

    21                List of subsidiaries of Registrant

    23.2              Consent of Ralph E. Davis Associates, Inc.

    23.3              Consent of Huntley & Huntley, Inc.
</TABLE>


(b)     Reports on Form 8-K

    The Company filed no reports on Form 8-K during the last quarter of the
Company's fiscal year ended September 30, 2001.
---------------

(8)  Incorporated by reference to the Registrant's Form S-1 (Registration
     Statement), dated September 29, 1993 (File 33-69626)

(10) Incorporated by reference to the Registrant's Form 10-Q for the second
     quarter ended March 31, 1994 (File 0-10990)

(15) Incorporated by reference to the Registrant's Form 10-K for the fiscal
     year ended September 30, 1994 (File 0-10990)

(23) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
     March 31, 1999 (File 0-10990)

(24) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
     June 30, 1999 (File 0-10990)

(26) Incorporated by reference to the Registrant's Form 10-K for the fiscal
     year ended September 30, 1999 (File 0-10990)

(27) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
     December 31, 1999 (File 0-10990)

(28) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
     March 31, 2000 (File 0-10990)

(29) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
     December 31, 2000 (File 0-10990)

(30) Incorporated by reference to the Registrant's Form 10-Q for quarter ended
     March 31, 2001 (File 0-10990)

(31) Incorporated by reference to the Registrant's Form 10-K for year ended
     September 30, 2000 (File 0-10990)


                                       63

<PAGE>
                                   SIGNATURES


    Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.

                           CASTLE ENERGY CORPORATION

<TABLE>
<CAPTION>
<S>                                         <C>
Date: April 23, 2002                        By: /s/JOSEPH L. CASTLE II
                                                --------------------------------
                                                   Joseph L. Castle II
                                                   Chairman of the Board
                                                   and Chief Executive Officer
</TABLE>





                                       64

<PAGE>
           DIRECTORS, OFFICERS, BOARD OF DIRECTORS AND PROFESSIONALS

                              (December 19, 2001)

<TABLE>
<CAPTION>
<S>                                                     <C>
JOSEPH L. CASTLE II                                     RICHARD E. STAEDTLER
Chairman & Chief Executive Officer                      Chief Financial Officer and
                                                           Chief Accounting Officer

MARTIN R. HOFFMANN                                      SIDNEY F. WENTZ
Former Secretary of the Army                            Former Chairman of The Robert Wood
                                                           Johnson Foundation

JOHN P. KELLER                                          RUSSELL S. LEWIS
President, Keller Group, Inc.                           President, Lewis Capital Group

                               OPERATING OFFICERS

JOSEPH L. CASTLE II                                     RICHARD E. STAEDTLER
Chief Executive Officer                                 Chief Financial Officer
                                                        Chief Accounting Officer

MARY A. CADE                                            TIMOTHY M. MURIN
Company Controller and Treasurer                        President - Exploration and Production

WILLIAM C. LIEDTKE III
Company Counsel

                                PRINCIPAL OFFICES

One Radnor Corporate Center                             512 Township Line Road
Suite 250                                               Three Valley Square, Suite 100
100 Matsonford Road                                     Blue Bell, PA 19422
Radnor, PA 19087

12731 Power Plant Road                                  61 McMurray Road, Suite 204
Tuscaloosa, Alabama 35406                               Pittsburgh, PA 15241-1633

P.O. Box 425                                            5623 North Western Avenue, Suite A
Acme, PA 15610-0425                                     Oklahoma City, OK 73118


                                  PROFESSIONALS

Counsel                                                  Independent Reservoir Engineers

Duane, Morris & Heckscher LLP                            Huntley & Huntley, Inc.
One Liberty Place, 42nd Floor                            Corporate One II, Suite 100
Philadelphia, PA 19103-7396                              4075 Monroeville Blvd.
                                                         Monroeville, PA 15146

Independent Accountants                                  Ralph E. Davis Associates, Inc.
                                                         1717 St. James Place, Suite 460
KPMG LLP                                                 Houston, Texas 77056
700 Louisiana
Houston, Texas 77002                                     Registrar and Transfer Agent
                                                         American Stock Transfer & Trust Company
                                                         40 Wall Street, 46th Floor
                                                         New York, New York 10005

</TABLE>