10-K/A 1 tenk_a.txt 10-K/A =============================================================================== 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)
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)
Registrant's telephone number: (610) 995-9400 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock -- $.50 par value and related Rights -------------------- Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes |X| No |_| Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. |X|. As of December 14, 2001, there were 6,632,884 shares of the registrant's Common Stock ($.50 par value) outstanding. The aggregate market value of voting stock held by non-affiliates of the registrant as of such date was $29,637,835 (5,049,035 shares at $5.87 per share). DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Proxy Statement for the 2002 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12 and 13. =============================================================================== CASTLE ENERGY CORPORATION 2001 FORM 10-K TABLE OF CONTENTS
Item Page ---- ---- PART I ------ 1. and 2. Business and Properties ............................................................................. 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
2 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 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 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:
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 ==========
--------------- (1) Thousand cubic feet Oil and Gas Production The following table summarizes the net quantities of oil and gas production of the Company for each of the three fiscal years in the period ended September 30, 2001, including production from acquired properties since the date of acquisition.
Fiscal Year Ended September 30, ---------------------------------- 2001 2000 1999 ---- ---- ---- Oil - Bbls (barrels) .................. 262,000 279,000 124,000 Gas - MCF ............................. 3,083,000 3,547,000 1,971,000
Average Sales Price and Production Cost Per Unit The following table sets forth the average sales price per barrel of oil and MCF of gas produced by the Company, including hedging adjustments, and the average production cost (lifting cost) per equivalent unit of production for the periods indicated. Production costs include applicable operating costs and maintenance costs of support equipment and facilities, labor, repairs, severance taxes, property taxes, insurance, materials, supplies and fuel consumed in operating the wells and related equipment and facilities. 5
Fiscal Year Ended September 30, ------------------------- 2001 2000 1999 ---- ---- ---- Average Sales Price per Barrel of Oil ............ $27.39 $27.94 $18.36 Average Sales Price per MCF of Gas ............... $ 4.53 $ 2.87 $ 2.25 Average Production Cost per Equivalent MCF(1) .... $ 1.59 $ 1.19 $ .70
--------------- (1) For purposes of equivalency of units, a barrel of oil is assumed equal to six MCF of gas, based upon relative energy content. No production was hedged in fiscal 2001. The average sales price per barrel of crude oil decreased $4.64 per barrel for the year ending September 30, 2000 and increased $.11 per barrel for the year ended September 30, 1999 as a result of hedging. The average sales price per mcf (thousand cubic feet) of natural gas decreased $.07 for each of the years ended September 30, 2000 and 1999 as a result of hedging. Oil and gas sales were not hedged after July 2000. Productive Wells and Acreage The following table presents the oil and gas properties in which the Company held an interest as of September 30, 2001. The wells and acreage owned by the Company and its subsidiaries are located primarily in Alabama, California, Illinois, Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Pennsylvania, Texas and Wyoming.
As of September 30, 2001 ------------------ Gross(2) Net(3) -------- ------- Productive Wells:(1) Gas Wells ............................................. 521 203 Oil Wells ............................................. 103 49 Acreage: Developed Acreage ..................................... 129,517 31,351 Undeveloped Acreage ................................... 85,686 29,678
In addition, one of the Company's subsidiaries has a fifty percent interest in approximately 3,100,000 gross undeveloped acres in Romania (approximately 1,550,000 net acres). --------------- (1) A "productive well" is a producing well or a well capable of production. Fifty-nine wells are dual wells producing oil and gas. Such wells are classified according to the dominant mineral being produced. (2) A gross well or acre is a well or acre in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. (3) A net well or acre is deemed to exist when the sum of fractional working interests owned in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres. Drilling Activity The table below sets forth for each of the three fiscal years in the period ended September 30, 2001 the number of gross and net productive and dry developmental wells drilled, including wells drilled on acquired properties since the dates of acquisition. 6
Fiscal Year Ended September 30, -------------------------------------------------------------------------------------------------- 2001 2000 1999 ------------------------------------- ------------------------------------- ---------------- United States Romania United States Romania United States ---------------- ----------------- ----------------- ---------------- ---------------- Productive Dry Productive Dry Productive Dry Productive Dry Productive Dry ---------- --- ---------- --- ---------- --- ---------- --- ---------- --- Developmental: Gross ....................... 17 4 -- -- 9 -- -- 5 3 Net ......................... 4 1.3 -- -- 4.5 -- -- 2.3 1.2 Exploratory: Gross ....................... -- 3* 1 8 -- 2 -- -- Net ......................... -- 1.5* .5 3.75 -- 1 -- --
All wells drilled by the Company in fiscal 1999 were drilled in the United States. --------------- * One well, in which the Company has a fifty percent (50%) interest, produced some volumes of natural gas when tested but the Company has not been able to obtain a price for its production that makes future operations economical. REGULATIONS Since the Company's subsidiaries have disposed of their refineries and third parties have assumed environmental liabilities associated with the refineries, the Company's current activities are not subject to environmental regulations that generally pertain to refineries, e.g., the generation, treatment, storage, transportation and disposal of hazardous wastes, the discharge of pollutants into the air and water and other environmental laws. Nevertheless, the Company has some contingent environmental exposures. See Items 3 and 7 and Note 12 to the consolidated financial statements included in Item 8 of this Form 10-K. The oil and gas exploration and production operations of the Company are subject to a number of local, state and federal environmental laws and regulations. To date, compliance with such regulations by the Company's natural gas marketing and transmission and exploration and production subsidiaries has not resulted in material expenditures. Most states in which the Company conducts oil and gas exploration and production activities have laws regulating the production and sale of oil and gas. Such laws and regulations generally are intended to prevent waste of oil and gas and to protect correlative rights and opportunities to produce oil and gas as between owners of interests in a common reservoir. Most states also have regulations requiring permits for the drilling of wells and regulations governing the method of drilling, casing and operating wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. In recent years there has been a significant increase in the amount of state regulation, including increased bonding, plugging and operational requirements. Such increased state regulation has resulted in, and is anticipated to continue to result in, increased legal and compliance costs being incurred by the Company. Based on past costs and even considering recent increases, management of the Company does not believe such legal and compliance costs will have a material adverse effect on the financial condition or results of operations of the Company although compliance requirements continue to absorb an increasing percentage of management's time. The Company plans to participate in the drilling of a wildcat well in the Black Sea in the spring or early summer of 2002. Participation in the drilling of this well will expose the Company to several risks not commonly associated with the Company's domestic onshore operations including drilling offshore, using foreign contractors to drill, political and governmental regulatory risks and possible delays in obtaining permits, parts and supplies. In addition, if the well is successful, a pipeline may have to be installed to transport the crude oil or natural gas discovered to onshore collection facilities. The Company is also subject to various state and Federal laws regarding environmental and ecological matters because it acquires, drills and operates oil and gas properties. To alleviate the environmental risk, the Company carries $25,000,000 of liability insurance and $3,000,000 of special operator's extra expense (blowout) insurance for wells it drills, including the well planned to be drilled in the Black Sea. 7 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 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 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 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 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Principal Market The Company's Common Stock is quoted on the Nasdaq National Market ("NNM") under the trading symbol "CECX." Stock Price and Dividend Information Stock Price: On December 29, 1999, the Company's Board of Directors declared a stock split in the form of a 200% stock dividend applicable to all stockholders of record on January 12, 2000. The additional shares were paid on January 31, 2000 and the Company's shares first traded at post split prices on February 1, 2000. The stock split applied only to the Company's outstanding shares on January 12, 2000 (2,337,629 shares) and did not apply to treasury shares (4,491,017 shares) on that date. As a result of the stock split 4,675,258 additional shares were issued. All share changes have been recorded retroactively in these data and elsewhere in this Form 10-K. The table below presents the high and low sales prices of the Company's Common Stock as reported by the NNM for each of the quarters during the three fiscal years ended September 30, 2001.
2001 2000 1999 ------------- -------------- ------------- High Low High Low High Low ---- --- ---- --- ---- --- First Quarter (December 31)............................................... $7.73 $5.92 $ 9.67 $5.50 $6.46 $5.63 Second Quarter (March 31)................................................. $6.94 $5.60 $10.56 $4.81 $5.96 $5.25 Third Quarter (June 30)................................................... $6.92 $5.67 $ 6.50 $4.63 $6.42 $5.00 Fourth Quarter (September 30)............................................. $6.47 $4.21 $ 7.75 $6.25 $6.08 $5.50
The final sale of the Company's Common Stock as reported by the NNM on November 30, 2001 was at $5.87. Dividends: On June 30, 1997, the Company's Board of Directors adopted a policy of paying regular quarterly cash dividends of $.05 per share on the Company's common stock. Commencing July 15, 1997, dividends have been paid quarterly. As with any company, the declaration and payment of future dividends are subject to the discretion of the Company's Board of Directors and will depend on various factors - including a covenant in the Company's letter of credit facility that limits dividends to 50% of the Company's net income. Approximate Number of Holders of Common Stock As of November 30, 2001, the Company's Common Stock was held by approximately 3,000 stockholders. ITEM 6. SELECTED FINANCIAL DATA During the five fiscal years ended September 30, 2001, the Company consummated a number of transactions affecting the comparability of the financial information set forth below. In May 1997, the Company sold its Rusk County, Texas oil and gas properties and pipeline to UPRC and one of its subsidiaries. In June 1999, CECI acquired all of the oil and gas assets of AmBrit. See Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 4 to the Company's Consolidated Financial Statements included in Item 8 of this Form 10-K. 12 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.
For the Fiscal Year Ended September 30, ------------------------------------------------- (in Thousands, except per share amounts) 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- 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
September 30, ------------------------------------------------ 2001 2000 1999 1998 1997 ---- ---- ---- ---- ---- 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
Share data have been retroactively restated to reflect the 200% stock dividend that was effective January 31, 2000. 13 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ("$000's" Omitted Except Per Unit Amounts) ------------------------------------------------------------------------------- RESULTS OF OPERATIONS GENERAL From August 1989 to September 30, 1995, two of the Company's subsidiaries conducted refining operations. By December 12, 1995, the Company's refining subsidiaries had sold all of their refining assets. In addition, Powerine merged into a subsidiary of EMC and was no longer a subsidiary of the Company. The Company's other refining subsidiary, IRLP, owns no refining assets and is in the process of liquidation. As a result, the Company has accounted for its refining operations as discontinued operations in the Company's financial statements as of September 30, 1995 and retroactively. Accordingly, discussion of results of operations has been confined to the results of continuing operations and the anticipated impact, if any, of liquidation of the Company's remaining inactive refining subsidiary and contingent environmental liabilities of the Company or its refining subsidiaries. Also, as noted above, CECI acquired the oil and gas properties of AmBrit on June 1, 1999. The oil and gas reserves associated with the acquisition were estimated at approximately 12.5 billion cubic feet of natural gas and 2,000,000 barrels of crude oil, roughly 150% of the reserves owned by the Company before the acquisition. Furthermore, as a result of the acquisition, the Company's production of oil and gas increased by approximately 425%. This acquisition impacted consolidated operations for the last four months of fiscal 1999 only. Gas marketing sales and purchases ceased effective May 31, 1999 by virtue of the scheduled termination of its subsidiaries' gas sales and gas purchase contracts with Lone Star and MGNG. The Company has not replaced these contracts although it continues to seek similar gas marketing acquisitions. As a result, natural gas marketing operations impacted consolidated operations for all of fiscal 1999 and none of fiscal 2000 or fiscal 2001. Fiscal 2001 vs Fiscal 2000 OIL AND GAS SALES Oil and gas sales increased $3,185 or 17.7% from fiscal 2000 to fiscal 2001. An analysis of the increase is as follows:
Fiscal Year Ended September 30, ------------- Increase 2001 2000 (Decrease) ---- ---- ---------- Production (Net): Barrels of crude oil................................................................ 262,000 279,000 (17,000) Mcf of natural gas.................................................................. 3,083,000 3,547,000 (464,000) Equivalent net of natural gas....................................................... 4,655,000 5,221,000 (566,000) Oil and Gas Sales: Before hedging...................................................................... $ 21,144 $ 19,487 $ 1,657 Effect of hedging................................................................... (1,528) 1,528 ---------- ---------- --------- Net of hedging...................................................................... $ 21,144 $ 17,959 $ 3,185 ========== ========== ========= Average Price/MCFE: Before hedging...................................................................... $ 4.54 $ 3.73 $ .81 Effect of hedging................................................................... (0.29) 0.29 ---------- ---------- --------- Net................................................................................. $ 4.54 $ 3.44 $ 1.10 ========== ========== ========= Analysis of Increase: Price (5,221,000 mcfe x $.81/mcfe).................................................. $ 4,229 Volume (566,000 mcfe x $4.54/mcfe).................................................. (2,570) Decrease in hedging losses.......................................................... 1,528 Rounding............................................................................ (2) --------- $ 3,185 =========
14 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:
Year Ended September 30, ----------------------------- Increase 2001 2000 (Decrease) ---- ---- ---------- Depreciation and amortization of furniture and fixtures and equipment........................ $ 122 $ 219 ($ 97) Depreciation, depletion and amortization of oil and gas properties........................... 3,348 2,990 358 ------ ------ ----- $3,470 $3,209 $ 261 ====== ====== =====
Depreciation and amortization of furniture and fixtures and equipment decreased $97 from fiscal 2000 to fiscal 2001 primarily because certain furniture and fixture assets and vehicles were fully depreciated in fiscal 2000. 15 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:
Year Ended September 30, ------------- 2001 2000 ---- ---- Litigation recovery (costs) ............................... ($45) Miscellaneous ............................................. $42 70 --- ---- $42 $ 25 === ====
PROVISION FOR INCOME TAXES The tax provisions (benefit) for the years ended September 30, 2001 and 2000 consist of the following components:
Year Ended September 30, --------------- 2001 2000 ---- ---- 1. Decrease in net deferred tax asset using 36% Federal and state blended tax rate ............. $ 808 $ 948 2. Change in valuation allowance .................... (431) (3,204) 4. Other (primarily revisions of previous estimates) ..................................... 4 (35) ----- ------- $ 381 ($2,291) ===== =======
The tax provision for the year ended September 30, 2001 consists primarily of deferred taxes of $808 related to timing differences originating in fiscal 2001 and a decrease of $431 in the valuation allowance from fiscal 2000. The decrease in the valuation allowance resulted because the Company determined that a 16 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:
Year Ended September 30, ------------------------------------- 2000 1999 Increase ---- ---- -------- Production (Net): Barrels of crude oil.................. 279,000 124,000 155,000 Mcf of natural gas.................... 3,547,000 1,971,000 1,576,000 Equivalent net of natural gas......... 5,221,000 2,715,000 2,506,000 Oil and Gas Sales: Before hedging........................ $ 19,487 $ 6,862 $ 12,625 Effect of hedging..................... (1,528) (150) (1,378) ---------- ---------- ---------- Net of hedging........................ $ 17,959 $ 6,712 $ 11,247 ========== ========== ========== Average Price/MCFE: Before hedging........................ $ 3.73 $ 2.53 $ 1.20 Effect of hedging..................... (0.29) (0.06) (0.23) ---------- ---------- ---------- Net................................... $ 3.44 $ 2.47 $ .97 ========== ========== ========== An analysis of the increase in oil and gas sales is as follows: Analysis of Increase Before Hedging: Price (2,715,000 mcfe x $1.20/mcfe)... $ 3,258 Volume (2,506,000 mcfe x $3.73/mcfe).. 9,347 Rounding.............................. 20 ---------- $ 12,625 ========== Analysis of Increase After Hedging: Price (2,715,000 mcfe x $.97/mcfe).... $ 2,634 Volume (2,506,000 mcfe x $3.44/mcfe).. 8,621 Rounding.............................. (8) ---------- $ 11,247 ==========
The increase in production volumes is primarily attributable to the acquisition of the AmBrit properties on June 1, 1999. As a result of this acquisition, the production volumes attributable to the AmBrit properties contributed twelve months of oil and gas sales for the year ended September 30, 2000 versus only four months of oil and gas sales for the year ended September 30, 1999. 17 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:
Year Ended September 30, ------------------------ 2000 1999 Increase ---- ---- -------- Depreciation and amortization of furniture and fixtures and equipment ......................... $ 219 $ 109 $ 110 Depreciation, depletion and amortization of oil and gas properties ............................. 2,990 1,937 1,053 ------ ------ ------ $3,209 $2,046 $1,163 ====== ====== ======
Depreciation and amortization of furniture and fixtures and equipment increased $110 from fiscal 1999 to fiscal 2000 primarily because of depreciation related to new vehicles purchased in late fiscal 1999 and early fiscal 2000 and because of amortization of computer software commencing in the first quarter of fiscal 2000. For the year ended September 30, 2000, the depletion rate per equivalent mcf was $.57 in fiscal 2000 versus $.71 in fiscal 1999. The net decrease is the result of offsetting factors. The depletion rate indirectly decreased because of substantially higher energy prices at September 30, 2000 versus those at September 30, 1999. As a result of such higher prices, the Company's net economic oil and gas reserves increased substantially from 1999 to 2000 and related depreciation, depletion and amortization decreased substantially because more equivalent mcfs of gas were allocated to essentially the same depletable costs. This decrease was offset by the Company's expenditure of approximately $7,600 in the acquisition of drilling acreage and drilling of eight dry holes in the United States and two unproductive wells in Romania. These expenditures increased the depletion rate because the related costs of these drilling ventures were added to the Company's amortization base without a concomitant increase in oil and gas reserves to be depleted. 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 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:
Year Ended September 30, ------------- 2000 1999 ---- ---- Litigation recovery (costs) .................................... ($45) $ 355 Write-down of investment in Penn Octane Corporation preferred stock ......................................................... (423) Market price adjustment of investment in Penn Octane Corporation common stock ...................................... 431 Miscellaneous .................................................. 70 (11) --- ----- $25 $ 352 === =====
PROVISION FOR INCOME TAXES The tax provision (benefit) for the years ended September 30, 2000 and 1999 consist of the following components:
Year Ended September 30, ------------- 2000 1999 ---- ---- 1. Increase in net deferred tax asset using 36% Federal and state blended tax rate ............................. ($2,256) 2. Utilization of deferred tax asset, net of related valuation reserves, using 36% blended Federal and state tax rate ............................................... $2,765 3. A tax provision of 2% on all net income in excess of that required to realize the net deferred tax asset. (This 2% rate represents alternative minimum Federal corporate taxes the Company must pay despite having tax carryforwards and credits available to offset regular Federal corporate tax) ................................. 71 4. Other (primarily revisions of previous estimates) ...... (35) 120 ------- ------ $ 2,291 $2,956 ======= ======
The tax provision for the year ended September 30, 2000, consists primarily of deferred taxes of $948 related to timing differences originating in fiscal 2000 and the reversal of a $3,204 valuation reserve from fiscal 1999. The reversal of the valuation reserve resulted because of positive evidence that the Company will be able to generate sufficient taxable income in the future to utilize its deferred tax asset. Such positive evidence consists primarily of the increased value of the Company's oil and gas reserves as a result of substantially higher oil and gas prices. 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 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:
Expected Uses of Funds ---------------------- Funds to support bond for appeal of verdict in Long Trusts Lawsuit............................................................ $3,000 Reduction of trade payables......................................... 1,025 Estimated drilling costs for wildcat in Black Sea (excludes completion costs if well successful)............................... 1,000 Dividends to shareholders........................................... 990 Recompletions and reworks on existing wells......................... 600 ------ $6,615 ======
If sufficient funds are available, the Company may also consider an additional investment in Networked. The Company does not expect to undertake any significant developmental drilling since it has entered into a letter of intent to sell its oil and gas properties to Delta for a fixed price (see Items 1 and 2 above) effective October 1, 2001. The Company may also continue to repurchase its shares if funds are available. 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.
Expected Sources of Funds ------------------------- Proceeds of sale of oil/gas properties to Delta at closing....... $15,500 Unrestricted cash - September 30, 2001........................... 5,844 Letter of credit portion of credit facility...................... 3,000 ------- $24,344 =======
The Company expects only marginally positive cash flow from operations during the period from October 1, 2001 to April 30, 2002 given current low oil and gas prices. If such prices increase, the Company may be able to fund some of its expected expenditures from cash flow from oil and gas operations. Conversely, the Company could experience negative cash flow from oil and gas operations if oil and gas prices decrease from present levels. 20 In addition, the Company owns marketable securities which had a market value (also book value) of $6,722 at September 30, 2001 and the Company could liquidate these and use the proceeds to fund planned expenditures if needed. Most of the marketable securities owned by the Company, however, are the common stocks of Delta (382,289 shares) and Penn Octane Corporation ("Penn Octane"), a small public company involved in the sale of liquid propane gas in Mexico (1,343,600 shares). Both of these companies are thinly traded and volatile and the Company may, therefore, not be able to liquidate its shares in Delta and Penn Octane at recorded values - especially if such shares must be liquidated quickly in the market. If the sale to Delta is consummated as planned, the Company will also receive 9,566,000 shares of Delta common stock. The closing of the sale of the Company's domestic oil and gas properties to Delta is subject to numerous conditions, including execution of a definitive agreement by December 31, 2001, approval of the sale by the Company's and Delta's boards of directors and approval by Delta's shareholders. Accordingly, there can be no assurance that the contemplated sale will close or that it will close when anticipated. In addition, economic conditions could change between the present time and closing and either Delta or the Company may not conclude the transaction, although the party failing to close could be subject to significant penalties pursuant to the terms of the letter of intent. If the Delta transaction does not close, the Company's expected uses and sources of funds for the period October 1, 2001 to September 30, 2002 are approximately as follows:
Expected Uses of Funds ---------------------- Developmental drilling.......................................... $ 5,286 Funds to support bond for appeal of verdict in Long Trusts lawsuit........................................................ 3,000 Reduction of trade payables..................................... 1,025 Estimated drilling costs for wildcat well in the Black Sea...... 1,000 Recompletions and reworks on existing wells..................... 600 Dividends to shareholders....................................... 1,320 ------- $12,231 =======
As noted above, the Company may also consider additional investments in Networked and further repurchase of its shares if sufficient cash is available. In addition, the Company may consider acquisitions of other properties or exploration and production companies, as it has in the past. 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.
Expected Sources of Funds ------------------------- Unrestricted cash - September 30, 2001........................... $ 5,844 Letter of credit portion of credit facility...................... 3,000 Expected minimum cash available for drilling under credit facility ($12,500-$3,000 letter of credit).................... 9,500 ------- $18,344 =======
The amount that can be borrowed under the Company's line of credit will be determined by the energy bank making the loan based upon its parameters and will probably change based upon past production, changes in oil and gas prices and other factors. 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 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 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 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 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 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 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page ---- CONSOLIDATED FINANCIAL STATEMENTS: Consolidated Statements of Operations for the Years Ended September 30, 2001, 2000 and 1999.................................................... 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
All other schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto. 27 CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF OPERATIONS ("$000's" Omitted Except Share and Per Share Amounts)
Year Ended September 30, ------------------------------------- 2001 2000 1999 ---- ---- ---- Revenues: Natural gas marketing and transmission: Gas sales........................... $ 50,067 Exploration and production: Oil and gas sales................... $ 21,144 $ 17,959 6,712 ---------- ---------- ---------- 21,144 17,959 56,779 ---------- ---------- ---------- Expenses: Natural gas marketing and transmission: Gas purchases....................... 31,062 General and administrative.......... 35 Transportation...................... 1,123 Depreciation and amortization....... 6,284 ---------- 38,504 ---------- Exploration and production: Oil and gas production.............. 7,399 6,194 1,910 General and administrative.......... 1,828 2,038 1,038 Depreciation, depletion and amortization......................... 3,470 3,209 2,046 Impairment of foreign unproved properties........................... 2,765 832 ---------- ---------- ---------- 15,462 12,273 4,994 ---------- ---------- ---------- Corporate general and administrative.. 4,169 3,717 4,112 ---------- ---------- ---------- 19,631 15,990 47,610 ---------- ---------- ---------- Operating income....................... 1,513 1,969 9,169 ---------- ---------- ---------- Other income (expense): Interest income....................... 641 784 1,701 Other income.......................... 42 25 352 Equity in loss of Networked Energy LLC (99) ---------- ---------- ---------- 584 809 2,053 ---------- ---------- ---------- Income before provision for (benefit of) income taxes..................... 2,097 2,778 11,222 ---------- ---------- ---------- Provision for (benefit of) income taxes: State................................. 11 (64) 79 Federal............................... 370 (2,227) 2,877 ---------- ---------- ---------- 381 (2,291) 2,956 ---------- ---------- ---------- Net income............................. $ 1,716 $ 5,069 $ 8,266 ========== ========== ========== Net income per share: Basic................................. $ .26 $ .73 $ 1.01 ========== ========== ========== Diluted............................... $ .25 $ .71 $ .99 ========== ========== ========== Weighted average number of common and potential dilutive shares outstanding: Basic................................. 6,643,724 6,939,350 8,205,501 ========== ========== ========== Diluted............................... 6,818,855 7,102,803 8,347,932 ========== ========== ==========
The accompanying notes are an integral part of these consolidated financial statements 28 CASTLE ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS ("$000's" Omitted Except Share and Per Share Amounts)
September 30, ------------------- 2001 2000 ---- ---- ASSETS Current assets: Cash and cash equivalents .............................. $ 5,844 $ 11,525 Restricted cash ........................................ 370 1,742 Accounts receivable .................................... 2,787 3,758 Marketable securities .................................. 6,722 10,985 Prepaid expenses and other current assets .............. 277 251 Estimated realizable value of discontinued net refining assets................................................. 612 800 Deferred income taxes .................................. 1,879 2,256 -------- -------- Total current assets.................................. 18,491 31,317 Property, plant and equipment, net: Natural gas transmission ............................... 51 55 Furniture, fixtures and equipment ...................... 222 258 Oil and gas properties, net (full cost method): Proved properties..................................... 39,843 29,218 Unproved properties not being amortized............... 110 1,447 Investment in 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 ======== ========
The accompanying notes are an integral part of these consolidated financial statements 29 CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS ("$000's" Omitted Except Share and Per Share Amounts)
Year Ended September 30, -------------------------------- 2001 2000 1999 ---- ---- ---- Cash flows from operating activities: Net income................................. $ 1,716 $ 5,069 $ 8,266 -------- -------- --------- Adjustments to reconcile net income to cash provided by operating activities: Depreciation, depletion and amortization. 3,470 3,209 8,330 Impairment of foreign unproved properties 2,765 832 Deferred income taxes (benefit).......... 377 (2,256) 2,765 Unrealized gain on marketable securities. (481) Impairment of Penn Octane preferred stock 423 Equity in loss of Networked Energy LLC... 99 Changes in assets and liabilities: (Increase) decrease in restricted cash.. 1,372 (972) (157) Decrease in accounts receivable......... 971 1,414 3,209 Decrease in prepaid transportation...... 1,123 (Increase) decrease in prepaid expenses and other current assets................ (26) 343 (301) Decrease in other assets................ 29 Decrease in prepaid gas purchases....... 852 Increase (decrease) in accounts payable. 1,110 (436) (5,740) Increase (decrease) in accrued expenses. 27 (537) (861) Increase in other long-term liabilities. 3 6 -------- -------- --------- Total adjustments...................... 10,168 1,632 9,162 -------- -------- --------- Net cash flow provided by operating activities................................ 11,884 6,701 17,428 -------- -------- --------- Cash flows from investment activities: Investment in note receivable - Penn Octane Corporation............................... (500) Investment in marketable securities........ (34) (269) Proceeds from sale of oil and gas assets... 48 1,427 Realization from (liquidation of) discontinued net refining assets.......... 900 Acquisition of AmBrit oil and gas properties................................ (20,170) Investment in other oil and gas properties. (15,449) (11,226) (3,794) Investment in Networked Energy LLC......... (150) (350) Purchase of furniture, fixtures and equipment................................. (82) (173) (98) Other...................................... (35) -------- -------- --------- Net cash used in investing activities.. (15,667) (10,857) (23,431) -------- -------- ---------
(continued on next page) The accompanying notes are an integral part of these consolidated financial statements 30 CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS ("$000's" Omitted) (continued from previous page)
Year Ended September 30, ------------------------------- 2001 2000 1999 ---- ---- ---- Cash flows from financing activities: Acquisition of treasury stock.................................................................. (572) (5,208) (6,919) Dividends paid to stockholders................................................................. (1,326) (1,363) (1,681) Proceeds from exercise of stock options........................................................ 255 -------- -------- -------- Net cash (used in) financing activities.................................................... (1,898) (6,571) (8,345) -------- -------- -------- Net (decrease) in cash and cash equivalents..................................................... (5,681) (10,727) (14,348) Cash and cash equivalents - beginning of period................................................. 11,525 22,252 36,600 -------- -------- -------- Cash and cash equivalents - end of period....................................................... $ 5,844 $ 11,525 $ 22,252 ======== ======== ======== Supplemental disclosures of cash flow information are as follows: Cash paid during the period: Income taxes................................................................................. $ 11 $ 188 $ 108 ======== ======== ======== Accrued dividends............................................................................ $ 331 $ 333 $ 368 ======== ======== ======== Conversion of Penn Octane Corporation note and accrued interest receivable to marketable securities.................................................................................... $ 521 $ 1,000 ======== ======== Unrealized gain (loss) on investment in available-for-sale marketable securities............... ($ 3,071) $ 2,275 $ 2,396 ======== ======== ======== Exchange of oil/gas properties for Delta Petroleum Company common stock........................ $ 1,937 ========
The accompanying notes are an integral part of these consolidated financial statements 31 CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND OTHER COMPREHENSIVE INCOME ("$000's" Omitted Except Per Share Amounts)
Years Ended September 30, 2001, 2000 and 1999 ---------------------------------------------------------------------------------------------------------------- Accumulated Common Stock Additional Other Treasury Stock ----------------- Paid-In Comprehensive Comprehensive Retained ------------------ Shares Amount Capital Income Income (Loss) Earnings Shares Amount Total ------ ------ ------- ------ ------------- -------- ------ ------ ----- 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 ========== ====== ======= ======= ======= ========= ======== =======
The accompanying notes are an integral part of these consolidated financial statements 32 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 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 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 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 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 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 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:
Estimated Realizable Value Net Refining of Discontinued Liabilities Net Refining Assets Retained ------------------- --------------- Balance - October 1, 1998 ........ $ 3,623 $ 5,129 Reduction in estimated MG SWAP litigation recovery ............. (129) (129) Collection of MG SWAP litigation proceeds ........................ (575) (575) Additional recovery in connection with the Powerine Arbitration ... 900 Reduction in estimated recoverable value of note receivable from American Western (2,119) Adjustment of vendor liabilities . (2,119) Other ............................ (1) ------- ------- Balance - September 30, 1999 ..... 800 3,205 Cash transactions ................ (153) Adjustment of vendor liabilities . 152 ------- ------- Balance - September 30, 2000 ..... 800 3,204 Cash transactions ................ (80) Adjustment of vendor liabilities . 80 Adjustments resulting from American Western's Plan of Liquidation ..................... (188) (188) ------- ------- Balance - September 30, 2001 ..... $ 612 $ 3,016 ======= =======
As of September 30, 2001, the estimated realizable value of discontinued net refining assets consists of $612 of estimated recoverable proceeds from the American Western note. The estimated value of net refining liabilities retained 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 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:
Year Ended September 30, 1999 ----------------------------- (Unaudited) Revenues.................................. $ 62,719 Net income................................ $ 7,958 Net income per share...................... $ .95 Shares outstanding (diluted).............. 8,347,932
These proforma results are presented for comparative purposes only and are not necessarily indicative of the results which would have been obtained had the acquisition been consummated as presented. Operations related to the AmBrit oil and gas properties have been included in the Company's Consolidated Statements of Operations since June 1, 1999, the closing date of the AmBrit acquisition. Investment in Drilling Joint Ventures In fiscal 1999, the Company entered into two drilling ventures to participate in the drilling of up to sixteen exploratory wells in south Texas. During fiscal 2000, the Company participated in the drilling of nine exploratory wells pursuant to the related joint venture operating agreements. Eight wells drilled resulted in dry holes and one well was completed as a producer. The Company has no further drilling obligations under these joint ventures and has terminated participation in each drilling venture. The total cost incurred to participate in the drilling of the exploratory wells was $6,003. Offshore Louisiana Property Acquisition In December 1999, a subsidiary of the Company purchased majority interests in twenty-six offshore Louisiana wells from Whiting Petroleum Company ("Whiting"), a public company engaged in oil and gas exploration and development. The adjusted purchase price was $890. 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 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:
September 30, ------------- 2001 2000 ---- ---- Funds supporting letters of credit for offshore Louisiana wells ......................................... $1,519 Drilling deposits in escrow - Romania .................... $ 7 4 Funds supporting letters of credit issued for operating bonds ......................................... 209 219 Funds escrowed for litigation settlement ................. 154 ---- ------ $370 $1,742 ==== ======
The drilling deposits in escrow in Romania are to be used only to conduct exploratory drilling activities in Romania and cannot be withdrawn or used for other purposes by the Company. The funds escrowed for litigation settlement pertain to Larry Long Litigation (see Note 13). 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 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:
Common Stock -------------------- Penn Octane Delta Chevron/Texaco Total ----------- ----- -------------- ----- September 30, 2001: Cost..................................................................... $2,271 $1,937 $14 $ 4,222 Unrealized gain (loss)................................................... 3,308 (808) 2,500 ------ ------ --- ------- Book value (market value)................................................ $5,579 $1,129 $14 $ 6,722 ====== ====== === ======= September 30, 2000: Cost..................................................................... $1,750 $1,937 $ 3,687 Unrealized gain.......................................................... 7,298 7,298 ------ ------ --- ------- Book value (market value)................................................ $9,048 $1,937 $10,985 ====== ====== === =======
The fair market values of Penn Octane, Delta and Chevron/Texaco shares were based on one hundred percent (100%) of the closing price on September 28, 2001, the last trading day in the Company's fiscal year ending September 30, 2001. At September 30, 2001 and 2000, the fair market values of the Penn Octane shares include $164 and $1,641, respectively, related to options to acquire Penn Octane common stock held by the Company. The value of such options was computed using the Black-Scholes method (see Note #16). The Company owned 1,343,600 shares of Penn Octane, 382,289 shares of Delta and 177 shares of Chevron/Texaco at September 30, 2001. Of these 501,000 shares of Penn Octane and all 177 shares of Chevron/Texaco were registered. The remaining shares are either in the process of being registered or the Company has registration rights with respect to such shares. At September 30, 2001, the Company also owned options to purchase 74,067 common shares of Penn Octane common stock at $2.50 per share. At September 30, 2000, the Company owned 1,067,667 shares of Penn Octane and 382,289 shares of Delta, as well as options to purchase 454,167 common shares of Penn Octane at exercise prices of $1.75 to $6.00 per share. NOTE 9 - FURNITURE, FIXTURES AND EQUIPMENT Furniture, fixtures and equipment are as follows:
September 30, ------------- 2001 2000 ---- ---- Cost: Furniture and fixtures .................................. $ 693 $ 660 Automobile and trucks ................................... 269 222 ----- ----- 962 882 Accumulated depreciation ................................. (740) (624) ----- ----- $ 222 $ 258 ===== =====
42 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:
September 30, 2001 ----------------------------------- United States Romania Total ------------- ------- ----- Proved properties................................................................... $ 56,100 $ 56,100 Less: Accumulated depreciation, depletion and amortization ......................... (16,257) (16,257) -------- -------- Proved properties................................................................... 39,843 39,843 Unproved properties not being amortized............................................. $ 3,707 3,707 Impairment of unproved properties................................................... (3,597) (3,597) -------- ------- -------- $ 39,843 $ 110 $ 39,953 ======== ======= ========
September 30, 2000 ----------------------------------- United States Romania Total ------------- ------- ----- Proved properties................................................................... $ 42,127 $ 42,127 Less: Accumulated depreciation, depletion and amortization ......................... (12,909) (12,909) -------- -------- Proved properties................................................................... 29,218 29,218 Unproved properties not being amortized............................................. $2,279 2,279 Impairment of unproved properties................................................... (832) (832) -------- ------ -------- $ 29,218 $1,447 $ 30,665 ======== ====== ========
Capital costs incurred by the Company in oil and gas activities are as follows:
Year Ended September 30, ---------------------------------------------------------- 2001 2000 ---------------------------- --------------------------- United United States Romania Total States Romania Total ------ ------- ----- ------ ------- ----- Acquisition of properties: Proved properties ............................................. $10,002 $10,002 $3,642 $ 3,642 Unproved properties ........................................... 346 346 678 $ 999 1,677 Exploration..................................................... 1,560 $1,428 2,988 2,966 346 3,312 Development..................................................... 2,113 2,113 2,595 2,595 ------- ------ ------- ------ ------ ------- $14,021 $1,428 $15,449 $9,881 $1,345 $11,226 ======= ====== ======= ====== ====== =======
Year Ended September 30, ---------------------------- 1999 ---------------------------- United States Romania Total ------ ------- ----- 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 ======= ==== =======
43 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:
Year Ended September 30, --------------------------- 2001 2000 1999 ---- ---- ---- Revenues: Crude oil, condensate, natural gas liquids and natural gas sales ............. $21,144 $17,959 $6,712 ------- ------- ------ Costs and expenses: Production costs............................ $ 7,399 $ 6,194 1,910 Depreciation, depletion and amortization............................... 3,348 2,990 1,937 Impairment of foreign unproved properties................................. 2,765 832 ------- ------- ------ Total costs and expenses.................... 13,512 10,016 3,847 ------- ------- ------ Income tax provision (benefit)............... 1,387 (6,553) 753 ------- ------- ------ Income from oil and gas producing activities................................. $ 6,245 $16,569 $2,112 ======= ======= ======
The income tax provision is computed at the effective tax rate for the related fiscal year. Assuming conversion of oil and gas production into common equivalent units of measure on the basis of energy content, depletion rates per equivalent MCF (thousand cubic feet) of natural gas were as follows:
Year Ended September 30, ------------------------ 2001 2000 1999 ---- ---- ---- Depletion rate per equivalent MCF of natural gas.................................. $0.72 $0.57 $0.71 ===== ===== =====
The increase in the depletion rate in fiscal 2001 resulted primarily because the Company's reserves qualitites decreased significantly as a result of lower oil and gas prices at September 30, 2001. The decrease in reserve quantities without a similar decrease in related costs resulted in a higher depletion rate. In addition, in fiscal 2001, the Company acquired significant East Texas reserves at a higher cost per mcfe than the cost for the Company's existing reserves at the time of the acquisition (see Note 4). The decrease in the depletion rate in fiscal 2000 resulted primarily because the Company's reserve quantities increased significantly as a result of higher oil and gas prices at September 30, 2000. The increase in reserve quantities without a similar increase in costs resulted in the lower depletion rate. 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 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:
("000's" Omitted) ------------------------- Natural Gas Oil (BBLS) (MCF) ---------- ------------ Proved developed and undeveloped reserves: As of October 1, 1998 .................... 255 15,324 Acquisitions ......................... 2,021 12,529 Revisions of previous estimates ...... (122) 2,520 Production ........................... (124) (1,971) ------ ------- As of September 30, 1999 ................. 2,030 28,402 Acquisitions ......................... 1,063 6,639 Divestitures ......................... (974) (236) Discoveries .......................... 1 317 Revisions of previous estimates ...... 2,894 12,728 Production ........................... (279) (3,547) ------ ------- As of September 30, 2000 ................. 4,735 44,303 Acquisitions ......................... 266 10,183 Revisions of previous estimates ...... (1,730) (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 ====== =======
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 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.
September 30, ------------------------------- 2001 2000 1999 ---- ---- ---- 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 ======== ======== ========
The future cash flows were computed using the applicable year-end prices and costs that related to then existing proved oil and gas reserves in which the Company has interests. The estimates of future income tax expense are computed at the blended rate (Federal and state combined) of 36%. The following were the sources of changes in the standardized measure of discounted future net cash flows:
September 30, ------------------------------ 2001 2000 1999 ---- ---- ---- Standardized measure, beginning of year....... $ 91,119 $ 41,244 $ 9,946 Sale of oil and gas, net of production costs.. (13,745) (11,083) (4,324) Net changes in prices......................... (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 ======== ======== =======
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 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 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:
Lease Sublease Year Ending September 30, Commitments Rentals ------------------------- ----------- -------- 2002............................................ $ 473 $ 65 2003............................................ 470 66 2004............................................ 240 2005............................................ 76 ------ -------- 2006............................................ $1,259 $ 131 ====== ========
Rent expense for the years ended September 30, 2001, 2000 and 1999 was $456, $412 and $386, respectively. Severance/Retention Obligations The Company has severance agreements with substantially all of its employees, including five of its officers, that provide for severance compensation in the event substantially all of the Company's or its subsidiaries' assets are sold and the employees are terminated as a result of such sale. Such termination severance commitments aggregated $1,101 at September 30, 2001. No severance obligations were owed to employees at September 30, 2001. 48 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 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 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 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):
Incentive Plan Other Options Options Total ------- ------- ----- Outstanding at October 1, 1998...... 195,000 20,000 215,000 Issued.............................. 15,000 15,000 Exercised........................... (25,000) (25,000) Repurchased......................... (10,000) (10,000) ---------- ---------- --------- Outstanding at September 30, 1999... 175,000 20,000 195,000 Effect of 200% stock dividend (see Note 15) ..................... 350,000 40,000 390,000 Issued.............................. 105,000 105,000 ---------- ---------- --------- Outstanding at September 30, 2000... 630,000 60,000 690,000 Issued.............................. 60,000 60,000 ---------- ---------- --------- Outstanding at September 30, 2001... 690,000 60,000 750,000 ========== ========== ========= Exercisable at September 30, 2001... 690,000 60,000 750,000 ========== ========== ========= Reserved at September 30, 2001...... 1,687,500 60,000 1,747,500 ========== ========== ========= Reserved at September 30, 2000...... 1,687,500 60,000 1,747,500 ========== ========== ========= Reserved at September 30, 1999...... 1,687,500 60,000 1,747,500 ========== ========== ========= Exercise prices at: September 30, 2001................. $ 3.42- $ 3.79 $ 8.58 September 30, 2000................. $ 3.42- $ 3.79 $ 8.58 September 30, 1999................. $ 3.42- $ 3.79 $ 5.75 Exercise Termination Dates......... 5/17/2003- 4/23/2007 5/17/2003- 1/02/2011 1/02/2011
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 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:
Weighted Average Options Price ------- ----- Outstanding - October 1, 1998 ....................... 215,000 $12.96 Issued .............................................. 15,000 17.25 Exercised ........................................... (25,000) 10.25 Repurchased ......................................... (10,000) 10.75 ------- ------- Balance - September 30, 1999 ........................ 195,000 13.75 Effect of 200% stock dividend (see Note 15) ......... 390,000 (9.17) Issued .............................................. 105,000 7.89 ------- ------- Outstanding - September 30, 2000 .................... 690,000 5.09 Issued .............................................. 60,000 7.00 ------- ------- Outstanding - September 30, 2001 .................... 750,000 $ 5.24 ======= =======
At September 30, 2001, exercise prices for outstanding options ranged from $3.42 to $8.58. The weighted average remaining contractual life of such options was 5.6 years. The per share weighted average fair values of stock options issued during fiscal 2001, 2000 and fiscal 1999 were $2.41, $3.29 and $4.56, respectively, on the dates of issuance using the Black-Scholes option pricing model with the following weighted average assumptions: average expected dividend yield - 3.0% in 2001, 3.0% in 2000 and 3.5% in 1999; risk free interest rate - 3.50% in 2001, 5.54% in 2000 and 6.32% in 1999; expected life of 10 years in 2001, 2000 and 1999 and volatility factor of .38 in 2001, .44 in 2000, and .22 in 1999. The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options which have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including the expected stock price volatility. Because the Company's employee stock options have characteristics significantly different from those of traded options, and because changes in the subjective input assumptions can materially affect the fair value estimate, in management's opinion, the existing models do not necessarily provide a reliable single measure of the fair value of its employee stock options. 53 CASTLE ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ("$000's" Omitted Except Per Share Amounts) Proforma net income and earnings per share had the Company accounted for its options under the fair value method of SFAS 123 is as follows:
Year Ending September 30, ------------------------- 2001 2000 1999 ---- ---- ---- Net income as reported........................ $1,716 $5,069 $8,266 Adjustment required by SFAS 123............... (145) (346) (152) ------ ------ ------ Pro-forma net income.......................... $1,571 $4,723 $8,114 ====== ====== ====== Pro-forma net income per share: Basic........................................ $ 0.24 $ .68 $ .99 ====== ====== ====== Diluted...................................... $ 0.23 $ .66 $ .97 ====== ====== ======
NOTE 17 - INCOME TAXES Provisions for (benefit of) income taxes consist of:
September 30, -------------------------- 2001 2000 1999 ---- ---- ---- Provision for (benefit of) income taxes: Current: Federal.................................. $ 4 ($ 35) $ 193 State.................................... (2) Deferred: Federal.................................. 786 922 2,209 State.................................... 22 26 68 Adjustment to the valuation allowance for deferred taxes: Federal..................................... (419) (3,115) 475 State....................................... (12) (89) 13 ----- -------- ------ $ 381 ($ 2,291) $2,956 ===== ======== ======
Deferred tax assets (liabilities) are comprised of the following at September 30, 2001 and 2000:
September 30, ----------------- 2001 2000 ---- ---- Operating losses and tax credit carryforwards ....... $ 4,715 $ 4,993 Statutory depletion carryovers ...................... 3,903 3,689 Depletion accounting ................................ (5,341) (3,602) Discontinued net refining operations ................ 866 866 Losses in foreign subsidiaries ...................... 1,295 300 ------- ------- 5,438 6,246 Valuation allowance ................................. (3,559) (3,990) ------- ------- $ 1,879 $ 2,256 ======= ======= Deferred tax assets - current ....................... $ 1,879 $ 2,256 ------- ------- $ 1,879 $ 2,256 ======= =======
At September 30, 2001, the Company determined that a portion of the deferred tax asset would more likely than not be realized based upon estimates of future taxable income and upon the projected taxable income 54 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:
Year Ended September 30, -------------------------- 2001 2000 1999 ---- ---- ---- Tax at statutory rate....................... $ 734 $ 972 $ 3,928 State taxes, net of federal benefit......... 7 (42) 51 Revision of tax estimates and contingencies.............................. 50 (151) Statutory depletion......................... (1,330) Increase (decrease) in valuation allowance.................................. (431) (3,204) 489 Other....................................... 21 (17) (31) ----- ------- ------- $ 381 ($2,291) $ 2,956 ===== ======= =======
At September 30, 2001, the Company had the following tax carryforwards available:
Federal Tax --------------------- Alternative Minimum Regular Tax ------- ----------- Net operating loss .............................. $ 2,674 $24,021 Alternative minimum tax credits ................. $ 3,752 N/A Statutory depletion ............................. $10,841 $ 440
The net operating loss carryforwards expire from 2001 through 2010. On September 9, 1994, the Company experienced a change of ownership for tax purposes. As a result of such change of ownership, the Company's net operating loss carryforward became subject to an annual limitation of $7,845. At September 30, 2001 all net operating loss carryforwards of the Company were no longer subject to the annual limitation. The Company also has approximately $58,688 in individual state tax loss carryforwards available at September 30, 2001. Approximately $47,287 of such carryforwards are primarily available to offset taxable income apportioned to certain states in which the Company has no operations and currently has no plans for future operations. As a result, it is probable most of such state tax carryforwards will expire unused. 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 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.
Year Ended September 30, 2001 --------------------------------------------------------------------------- Natural Gas Oil & Gas Eliminations Marketing Exploration and and and Refining Corporate Transmission Production (Discontinued) Items Consolidated ------------ ----------- -------------- ------------ ------------ Revenues....................................... $ 21,144 $21,144 Operating income (loss)........................ $ 5,682 ($ 4,169) $ 1,513 Identifiable assets............................ $67,702* $105,238 ($113,822) $59,118 Capital expenditures........................... $ 15,531 $15,531 Depreciation, depletion and amortization....... $ 3,468 $ 2 $ 3,470
Year Ended September 30, 2000 --------------------------------------------------------------------------- Natural Gas Oil & Gas Eliminations Marketing Exploration and and and Refining Corporate Transmission Production (Discontinued) Items Consolidated ------------ ----------- -------------- ------------ ------------ Revenues....................................... $17,959 $17,959 Operating income (loss)........................ $ 5,686 ($ 3,717) $ 1,969 Identifiable assets............................ $67,727* $92,229 ($96,661) $63,295 Capital expenditures........................... $11,399 $11,399 Depreciation, depletion and amortization....... $ 3,207 $ 2 $ 3,209
56 CASTLE ENERGY CORPORATION NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ("$000's" Omitted Except Per Share Amounts)
Year Ended September 30, 1999 --------------------------------------------------------------------------- Natural Gas Oil & Gas Eliminations Marketing Exploration and and and Refining Corporate Transmission Production (Discontinued) Items Consolidated ------------ ----------- -------------- ------------ ------------ Revenues....................................... $50,067 $ 7,190 $57,257 Operating income (loss)........................ $11,563 $ 1,718 ($ 4,112) $ 9,169 Identifiable assets............................ $79,026* $67,720 ($87,208) $59,538 Capital expenditures........................... $24,065 $24,065 Depreciation, depletion and amortization....... $ 6,284 $ 2,046 $ 8,330
--------------- * Consists primarily of intracompany receivables. For the year ended September 30, 1999, sales by the Company's natural gas marketing subsidiary to Lone Star Gas Company under the Lone Star Contract aggregated $46,802. These amounts constituted approximately 82% of consolidated revenues for the year ended September 30, 1999. The Lone Star contract terminated in May 1999. At the present time, the Company's consolidated revenues consist entirely of oil and gas sales. Three purchasers of the Company's oil and gas production currently account for approximately 43% of consolidated production. 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 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)
First Second Third Fourth Quarter Quarter Quarter Quarter (December 31) (March 31) (June 30) (September 30) ------------- ---------- --------- -------------- Year Ended September 30, 2001: Revenues......................................................... $5,394 $ 6,316 $5,347 $4,087 Operating income (loss).......................................... $1,533 $ 2,174 $ 511 ($2,705) Net income (loss)................................................ $1,110 $ 1,531 $ 397 ($1,322) Net income per share (diluted)................................... $ .16 $ .22 $ .06 ($ .20) Year Ended September 30, 2000: Revenues......................................................... $4,085 $3,318 $4,945 $ 5,611 Operating income (loss).......................................... $ 32 ($ 387) $ 835 $ 1,489 Net income (loss)................................................ $ 259 ($ 277) $1,024 $ 4,063 Net income (loss) per share (diluted)............................ $ .04 ($ .04) $ .15 $ .58
For the year ended September 30, 2000 revenues from well operations have been retroactively reclassified as reductions of oil and gas production costs. The sums of the quarterly per share amounts differ from the annual per share amounts primarily because the stock purchases made by the Company were not made in equal amounts and at corresponding times each quarter. 58 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 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None 60 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 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. and 2. Financial Statements and Financial Statement Schedules Financial statements and schedules filed as part of this Report on Form 10-K are listed in Item 8 of this Form 10-K. 3. Exhibits The Exhibits required by Item 601 of Regulation S-K and filed herewith or incorporated by reference herein are listed in the Exhibit Index below.
Exhibit Number Description of Document -------------- ----------------------- 3.1 Restated Certificate of Incorporation(15) 3.2 Bylaws(10) 4.1 Specimen Stock Certificate representing Common Stock(8) 4.2 Rights Agreement between Castle Energy Corporation and American Stock Transfer and Trust Company as Rights Agent, dated as of April 21, 1994(10) 10.33 Castle Energy Corporation 1992 Executive Equity Incentive Plan(8) 10.34 First Amendment to Castle Energy Corporation 1992 Executive Equity Incentive Plan, effective May 11, 1993(8) 10.124 Asset Purchase Agreement dated February 27, 1998 by and between Castle Energy Corporation and Alexander Allen, Inc.(21) 10.125 Rollover and Assignment Agreement, dated December 1, 1998 between Penn Octane Corporation and Certain Lenders, including Castle Energy Corporation(22) 10.126 Purchase and Sale Agreement by and between AmBrit Energy Corp. and Castle Exploration Company, Inc., effective January 1, 1999(23) 10.127 Agreement to Exchange $.9 Million Secured Notes Into Senior Preferred Stock of Penn Octane Corporation dated March 3, 1999(23) 10.128 Credit Agreement by and among Castle Exploration Company, Inc. and Comerica Bank-Texas, effective May 28, 1999(24) 10.129 Purchase and Sale Agreement by and between Costilla Redeco Energy LLC and Castle Exploration Company, Inc., effective May 31, 1999(24) 10.130 Letter dated July 22, 1999 between Penn Octane Corporation and Castle Energy Corporation(26) 10.131 Letter dated July 29, 1999 between Penn Octane Corporation and Castle Energy Corporation(26) 10.132 Castle Energy Corporation Severance Benefit Plan(26) 10.133 Asset Acquisition Agreement between Castle Exploration Company, Inc., Deerlick Creek Partners, I., L.P. and Deven Resources, Inc, effective September 1, 1999(27) 10.134 Purchase and Sale Agreement, dated December 15, 1999, between Whiting Park Production, Ltd. and Castle Exploration Company, Inc.(27) 10.135 Asset Acquisition Agreement between Castle Exploration Company, Inc, and American Refining and Exploration Company, Deven Resources, Inc., CMS/Castle Development Fund I L.P., effective as of October 1, 1999(27) 10.136 Promissary Note between CEC, Inc. and Penn Octane Corporation(28) 10.137 Purchase Agreement between CEC, Inc. and Penn Octane Corporation Effective January 5, 2000(28)
62
Exhibit Number Description of Document -------------- ----------------------- 10.138 Purchase and Sale Agreement, dated August 6, 2000 between and among Castle Exploration Company, Inc., Parks and Luttrell Energy Partners L.P. and Parks and Luttrell Energy, Inc.(31) 10.139 Purchase and Sale Agreement dated August 4, 2000 between Castle Offshore LLC, BWAB Limited Liability Company and Delta Petroleum Company(31) 10.140 Agreement to Transfer a Membership Interest In Networked Energy LLC to CEC, Inc., dated August 31, 2000(31) 10.141 Second Amendment - Promissary Note of Penn Octane Corporation(29) 10.142 Purchase and Sale Agreement, dated April 1, 2001, between Strand Energy LC and Castle Exploration Company, Inc.(30) 10.143 Credit Agreement as of November 26, 2001 among Castle Exploration Company, Inc. and Castle Energy Corporation and Bank of Texas National Association 11.1 Statement re: Computation of Earnings Per Share 21 List of subsidiaries of Registrant 23.2 Consent of Ralph E. Davis Associates, Inc. 23.3 Consent of Huntley & Huntley, Inc.
(b) Reports on Form 8-K The Company filed no reports on Form 8-K during the last quarter of the Company's fiscal year ended September 30, 2001. --------------- (8) Incorporated by reference to the Registrant's Form S-1 (Registration Statement), dated September 29, 1993 (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 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. CASTLE ENERGY CORPORATION
Date: April 23, 2002 By: /s/JOSEPH L. CASTLE II -------------------------------- Joseph L. Castle II Chairman of the Board and Chief Executive Officer
64 DIRECTORS, OFFICERS, BOARD OF DIRECTORS AND PROFESSIONALS (December 19, 2001)
JOSEPH L. CASTLE II RICHARD E. STAEDTLER Chairman & Chief Executive Officer Chief Financial Officer and Chief Accounting Officer MARTIN R. HOFFMANN SIDNEY F. WENTZ Former Secretary of the Army Former Chairman of The Robert Wood Johnson Foundation JOHN P. KELLER RUSSELL S. LEWIS President, Keller Group, Inc. President, Lewis Capital Group OPERATING OFFICERS JOSEPH L. CASTLE II RICHARD E. STAEDTLER Chief Executive Officer Chief Financial Officer Chief Accounting Officer MARY A. CADE TIMOTHY M. MURIN Company Controller and Treasurer President - Exploration and Production WILLIAM C. LIEDTKE III Company Counsel PRINCIPAL OFFICES One Radnor Corporate Center 512 Township Line Road Suite 250 Three Valley Square, Suite 100 100 Matsonford Road Blue Bell, PA 19422 Radnor, PA 19087 12731 Power Plant Road 61 McMurray Road, Suite 204 Tuscaloosa, Alabama 35406 Pittsburgh, PA 15241-1633 P.O. Box 425 5623 North Western Avenue, Suite A Acme, PA 15610-0425 Oklahoma City, OK 73118 PROFESSIONALS Counsel Independent Reservoir Engineers Duane, Morris & Heckscher LLP Huntley & Huntley, Inc. One Liberty Place, 42nd Floor Corporate One II, Suite 100 Philadelphia, PA 19103-7396 4075 Monroeville Blvd. Monroeville, PA 15146 Independent Accountants Ralph E. Davis Associates, Inc. 1717 St. James Place, Suite 460 KPMG LLP Houston, Texas 77056 700 Louisiana Houston, Texas 77002 Registrar and Transfer Agent American Stock Transfer & Trust Company 40 Wall Street, 46th Floor New York, New York 10005