-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, Q38lIznIkwFlTUkojJdnl8pr+EsgwHL4sXPOmIwR7kz6LSJsY6HFk3dFtWv0yBzO jPIWEYZ+jNNKXrqlPpS3Yg== 0000950116-99-002302.txt : 19991222 0000950116-99-002302.hdr.sgml : 19991222 ACCESSION NUMBER: 0000950116-99-002302 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 10 CONFORMED PERIOD OF REPORT: 19990930 FILED AS OF DATE: 19991221 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CASTLE ENERGY CORP CENTRAL INDEX KEY: 0000709355 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 760035225 STATE OF INCORPORATION: DE FISCAL YEAR END: 0930 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 000-10990 FILM NUMBER: 99777924 BUSINESS ADDRESS: STREET 1: ONE RADNOR CORPORATE CTR STE 250 STREET 2: 100 MATSONFORD RD CITY: RADNOR STATE: PA ZIP: 19087 BUSINESS PHONE: 6109959400 MAIL ADDRESS: STREET 1: ONE RADNOR CORPORATE CENTER SUITE 250 STREET 2: 100 MATSONFORD CITY: RADNOR STATE: PA ZIP: 19087 FORMER COMPANY: FORMER CONFORMED NAME: MINDEN OIL & GAS INC/NEW DATE OF NAME CHANGE: 19861117 FORMER COMPANY: FORMER CONFORMED NAME: MINDEN HOLDING CO DATE OF NAME CHANGE: 19830310 10-K 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ================================================================================ FORM 10-K |X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended September 30, 1999 OR |_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _______________ to _________________ Commission file number: 0-10990 CASTLE ENERGY CORPORATION ------------------------------------------------------ (Exact name of registrant as specified in its charter) Delaware 76-0035225 ------------------------------- ---------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) One Radnor Corporate Center Suite 250, 100 Matsonford Road Radnor, Pennsylvania 19087 ---------------------------------------- ---------- (Address of principal executive offices) (Zip Code) Registrant's telephone number: (610) 995-9400 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock-- $.50 par value and related Rights Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes __X__ No ____ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]. As of November 22, 1999, there were 2,342,629 shares of the registrant's Common Stock ($.50 par value) outstanding. The aggregate market value of voting stock held by non-affiliates of the registrant as of such date was $30,605,477 (1,820,346 shares at $16.813 per share). DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Proxy Statement for the 2000 Annual Meeting of Stockholders are incorporated by reference in Items 10, 11, 12 and 13 CASTLE ENERGY CORPORATION 1999 FORM 10-K TABLE OF CONTENTS Item Page - ---- ---- PART I ------ 1. and 2. Business and Properties..................................... 1 3. Legal Proceedings........................................... 5 4. Submission of Matters to a Vote of Security Holders......... 8 PART II ------- 5. Market for the Registrant's Common Equity and Related Stockholder Matters......................................... 9 6. Selected Financial Data..................................... 9 7. Management's Discussion and Analysis of Financial Condition and Results of Operations......................... 11 8. Financial Statements and Supplementary Data.................. 27 PART III -------- 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure........................... 59 10. Directors and Executive Officers of the Registrant............ 59 11. Executive Compensation........................................ 59 12. Security Ownership of Certain Beneficial Owners and Management.................................................... 59 13. Certain Relationships and Related Transactions................ 59 PART IV ------- 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K..................................................... 60 PART I ITEMS 1. AND 2. BUSINESS AND PROPERTIES INTRODUCTION All statements other than statements of historical fact contained in this report are forward-looking statements. Forward-looking statements in this report generally are accompanied by words such as "anticipate," "believe," "estimate," or "expect" or similar statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove correct. Factors that could cause the Company's results to differ materially from the results discussed in such forward-looking statements are disclosed in this report, including without limitation in conjunction with the expected cash sources and expected cash obligations discussed below. All forward-looking statements in this Form 10-K are expressly qualified in their entirety by the cautionary statements in this paragraph. Furthermore, this statement constitutes a Year 2000 Readiness Disclosure Statement and the statements contained herein are subject to the Year 2000 Information and Readiness Disclosure Act ("Act"). In case of a dispute, this document and information contained herein are entitled to protection of the Act. Castle Energy Corporation (the "Company") is currently engaged in oil and gas exploration and production in the United States and Romania. References to the Company mean Castle Energy Corporation, the parent, and/or its subsidiaries. Such references are for convenience only and are not intended to describe legal relationships. During the period from August of 1989 through September 30, 1995, the Company, through certain subsidiaries, was primarily engaged in petroleum refining. Indian Refining I Limited Partnership (formerly Indian Refining Limited Partnership) ("IRLP"), an indirect wholly-owned subsidiary of the Company, owned the Indian Refinery, an 86,000 barrel per day (B/D) refinery located in Lawrenceville, Illinois ("Indian Refinery"). Powerine Oil Company ("Powerine"), a former indirect wholly-owned subsidiary of the Company, owned and operated a 49,500 B/D refinery located in Santa Fe Springs, California ("Powerine Refinery"). By September 30, 1995, the Company's refining subsidiaries had terminated and discontinued all of their refining operations. For accounting purposes, refining operations were classified as discontinued operations in the Company's Consolidated Financial Statements as of September 30, 1995 (see Note 3 to the consolidated financial statements included in Item 8 of this Form 10-K). During the period from December 31, 1992 to May 31, 1999, the Company, through three 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 UPRC in May 1997 and because it is unlikely that similar profitable long-term contracts can be negotiated since most gas purchasers buy gas on the spot market. Although the Company is currently seeking additional natural gas marketing operations, it is currently operating exclusively in the exploration and production segment of the energy industry. Since inception to the present the Company continues to operate in the exploration and production business. During the fiscal year ended September 30, 1999, the Company invested $23,964,000 in oil and gas property acquisition, exploration and development including $934,000 in Romania. In addition, the Company entered into two drilling joint ventures to drill up to 16 new wells in South Texas over the next two years. The Company also expects to drill 2-3 new wells in Romania over the next 18 months. The Company is currently evaluating several other possible acquisitions of oil and gas assets and oil and gas companies. As of September 30, 1999, the Company's exploration and production subsidiaries owned interests in 507 producing oil and gas wells located in ten states. The subsidiaries operate approximately half of the wells. At September 30, 1999, the Company's exploration and production assets included proved reserves of approximately 28.4 billion cubic feet of natural gas and approximately 2,030,000 barrels of oil. In October 1996, the Company commenced a program to repurchase shares of its common stock at stock prices beneficial to the Company. At November 22, 1999, 4,486,017 shares representing approximately 66% of previously outstanding shares had been repurchased and the Company's Board of Directors has authorized the purchase of up to 263,983 additional shares. -1- OIL AND GAS EXPLORATION AND PRODUCTION General The Company's oil and gas exploration and production business is currently conducted through Castle Exploration Company, Inc. ("CECI"), a wholly-owned subsidiary, and Petroleum Reserve Corporation ("PRC"), a division of the Company. From December 3, 1992 to May 30, 1997 Castle Texas Production Limited Partnership ("Production"), one of the Company's exploration and production subsidiaries, owned and operated approximately 115 oil and gas wells in Rusk County, Texas. On May 30, 1997, Production sold these wells and related undrilled acreage to Union Pacific Resources Company ("UPRC"). On June 1, 1999, CECI consummated the purchase of the oil and gas properties of AmBrit Energy Corp. ("AmBrit"). The oil and gas properties purchased included interests in approximately 180 oil and gas properties in Alabama, Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Texas and Wyoming, as well as undrilled acreage in several of these states. The production from the oil and gas properties acquired from AmBrit increased the Company's consolidated production by approximately 425%. The oil and gas reserves acquired approximated 150% of the Company's oil and gas reserves before the acquisition. Subsequent to September 30, 1999, CECI acquired additional outside interests in several Alabama wells which it operates for $372,000. In addition, CECI entered into three agreements to acquire additional oil and gas interests in operated wells in Alabama and in non-operated wells in Pennsylvania and to acquire a majority interest in twenty-six (26) offshore Louisiana wells. The adjusted purchase price for these acquisitions, assuming closings as planned, is expected to approximate $3,075,000. The interests in the Louisiana offshore wells, assuming the anticipated purchase is consummated, will be the Company's first investment in offshore wells. As of September 30, 1999, all of the wells in which the Company has an interest were onshore. Properties Proved Oil and Gas Reserves The following is a summary of the Company's oil and gas reserves as of September 30, 1999. 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, 1999 were as follows: Net MCF(1) of gas: Proved developed....................................... 23,547,000 Proved undeveloped..................................... 4,855,000 ---------- Total.................................................. 28,402,000 ========== Net barrels of oil: Proved developed....................................... 1,788,000 Proved undeveloped..................................... 242,000 ----------- Total.................................................. 2,030,000 =========== - ----------------- (1) Thousand cubic feet -2- 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, 1999, including production from acquired properties since the date of acquisition.
Fiscal Year Ended September 30, ----------------------------------------- 1999 1998 1997 ---- ---- ---- Oil -- Bbls (barrels).............................................. 124,000 20,000 36,000 Gas -- MCF......................................................... 1,971,000 869,000 2,454,000
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 and the average production cost (lifting cost) per equivalent unit of production for the periods indicated. Production costs include applicable operating costs and maintenance costs of support equipment and facilities, labor, repairs, severance taxes, property taxes, insurance, materials, supplies and fuel consumed in operating the wells and related equipment and facilities.
Fiscal Year Ended September 30, ---------------------------------- 1999 1998 1997 ---- ---- ---- Average Sales Price per Barrel of Oil................................... $18.36 $15.46 $19.94 Average Sales Price per MCF of Gas...................................... $ 2.25 $ 2.38 $ 2.46 Average Production Cost per Equivalent MCF(1)........................... $ .88 $ 0.78 $ .73
- ---------------- (1) For purposes of equivalency of units, a barrel of oil is assumed equal to six MCF of gas, based upon relative energy content. The average sales price per barrel of crude oil 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 the year ended September 30, 1999. Oil and gas sales were not hedged in fiscal 1998 and 1997. Productive Wells and Acreage The following table presents the oil and gas properties in which the Company held an interest as of September 30, 1999. The wells and acreage owned by the Company and its subsidiaries are located primarily in Alabama, California, Illinois, Louisiana, Mississippi, New Mexico, Montana, Oklahoma, Pennsylvania and Wyoming. As of September 30, 1999 -------------------------- Gross(2) Net (3) --------- --------- Productive Wells:(1) Gas Wells.................................. 411 128 Oil Wells.................................. 96 46 Acreage: Developed Acreage.......................... 124,491 24,637 Undeveloped Acreage........................ 86,564 31,077 In addition, one of the Company's subsidiaries has a fifty percent interest in approximately 3,100,000 gross undeveloped acres in Romania (1,550,000 net acres). - ---------------- (1) A "productive well" is a producing well or a well capable of production. Sixty-four 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- (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, 1999 the number of gross and net productive and dry developmental wells drilled including wells drilled on acquired properties since the dates of acquisition. No exploratory wells were drilled during the periods presented.
Fiscal Year Ended September 30, --------------------------------------------------------------------------- 1999 1998 1997 --------------------- --------------------- ---------------------- Productive Dry Productive Dry Productive Dry ---------- --- ---------- --- ---------- --- Developmental: Gross.................................. 5 3 23.0 -- 3.0 -- Net.................................... 2.3 1.2 15.2 -- 1.4 --
The Company is currently participating in a twelve well exploratory drilling venture in South Texas, another four well exploratory drilling program also in South Texas, an Appalachian drilling program in Western Pennsylvania and a wildcat drilling program in Romania, where a subsidiary of the Company owns fifty percent (50%) of a drilling concession granted by the Romanian government. Subsequent to September 30, 1999, CECI also acquired additional outside interests in several Alabama wells it operates for $372,000. In addition, CECI has entered into agreements to acquire additional oil and gas interests in operated wells in Alabama and Pennsylvania and to acquire majority interests in twenty-six wells in offshore Louisiana, including 18 non-producing wells. See Note 22 to the consolidated financial statements included in Item 8 to this Form 10-K. REGULATIONS Since the Company's subsidiaries have disposed of their refineries and third parties have assumed environmental liabilities associated with the refineries, the Company's current activities are not subject to environmental regulations that generally pertain to refineries, e.g., the generation, treatment, storage, transportation and disposal of hazardous wastes, the discharge of pollutants into the air and water and other environmental laws. Nevertheless, the Company has some contingent environmental exposures. See Items 3 and 7 and Note 12 to the consolidated financial statements included in Item 8. of this Form 10-K. The oil and gas exploration and production operations of the Company are subject to a number of local, state and federal environmental laws and regulations. To date, compliance with such regulations by the Company's natural gas marketing and transmission and exploration and production subsidiaries has not resulted in material expenditures. Most states in which the Company conducts oil and gas exploration and production activities have laws regulating the production and sale of oil and gas. Such laws and regulations generally are intended to prevent waste of oil and gas and to protect correlative rights and opportunities to produce oil and gas as between owners of interests in a common reservoir. Some state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or unit. Most states also have regulations requiring permits for the drilling of wells and regulations governing the method of drilling, casing and operating wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. In recent years there has been a significant increase in the amount of state regulation, including increased bonding, plugging and operational requirements. Such increased state regulation has resulted in, and is anticipated to continue to result in, increased legal and compliance costs being incurred by the Company. Based on past costs and even considering recent increases, management of the Company does not believe such legal and compliance costs will have a material adverse effect on the financial condition or results of operations of the Company although compliance issues continue to absorb an increasing percentage of management's time. If the Company consummates its acquisition of twenty-six (26) offshore Louisiana wells, as planned, it anticipates its environmental and plugging and abandonment costs may increase significantly. Seventeen of the wells to be acquired are temporarily abandoned or shut in and will eventually have to be returned to production or plugged and abandoned. 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 -4- of liability insurance and $3,000,000 of special operator's extra expense (blowout) insurance for wells it drills. Such insurance covers sudden and accidental pollution. Although management believes that its current insurance coverage is adequate, management is obtaining additional property and operator's extra expense insurance coverage for the twenty-six offshore Louisiana wells it expects to acquire because the property and environmental exposure for such offshore wells is considerably greater than that for similar onshore wells. At the present time, all of the Company's wells are onshore. EMPLOYEES AND OFFICE FACILITIES As of November 22, 1999, the Company, through its subsidiaries, employed 27 personnel. Until June 30, 1998, the Company outsourced all of its administrative, land and accounting functions. Effective July 1, 1998, the Company exercised its option to acquire the computer equipment and software of the company providing the outsourcing services and also hired most of that company's employees. As a result the Company now performs all administrative, land and accounting functions in-house. The Company also recently established an Oklahoma City office and entered into a service agreement providing for legal and land services. The Company leases certain offices as follows: Office Location Function - --------------- -------- Radnor, PA Corporate Headquarters Plymouth Meeting, PA Accounting Office Mt. Pleasant, PA Oil and Gas Production Office Pittsburgh, PA Drilling and Exploration Office Tuscaloosa, Alabama Gas Production Office Oklahoma City, Oklahoma Land and Legal ITEM 3. LEGAL PROCEEDINGS Contingent Environmental Liabilities In December 1995, IRLP sold the Indian Refinery to American Western Refining Limited Partnership ("American Western"), an unaffiliated party. As part of the related purchase and sale agreement, American Western assumed all environmental liabilities and indemnified IRLP with respect thereto. Subsequently American Western filed for bankruptcy and sold the Indian Refinery to an outside party pursuant to a bankruptcy proceeding. The new owner is currently dismantling the Indian Refinery. During fiscal 1998, the Company was also informed that the United States Environmental Protection Agency ("EPA") has investigated offsite acid sludge waste found near the Indian Refinery and was also investigating and remediating surface contamination in the Indian Refinery property. Neither the Company nor IRLP was initially named with respect to these two actions. In October 1998, the EPA named the Company and two of its refining subsidiaries as potentially responsible parties for the expected clean-up of the Indian Refinery. In addition, eighteen other parties were named including Texaco Refining and Marketing, Inc., 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 expects that it will respond to the EPA information request during the second quarter of fiscal 2000. In September 1995, Powerine sold the Powerine Refinery to Kenyen Resources ("Kenyen"), an unaffiliated party. In January 1996, Powerine merged into a subsidiary of Energy Merchant Corp. ("EMC"), an unaffiliated party, and EMC assumed all environmental liabilities. In August 1998, EMC sold the Powerine Refinery to a third party which is seeking financing to 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 -5- 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 relevant information from the Company. Estimated gross undiscounted clean up costs for this refinery are $80,000,000 - $150,000,000 according to third parties. If the Company were found liable for the remediation of the Indian Refinery, it could be required to pay a percentage of the clean-up costs. Since the Company's subsidiary only operated the Indian Refinery five years, whereas Texaco and others operated it over fifty years, the Company would expect that its share of remediation liability would be proportional to its years of operation, although such may not be the case. An opinion issued by the U.S. Supreme Court in June 1998 in a comparable matter supports the Company's position. Nevertheless, if funds for environmental clean-up are not provided by these former and/or present owners, it is possible that the Company and/or one of its former refining subsidiaries could be named a party in additional legal actions to recover remediation costs. In recent years, government and other plaintiffs have often sought redress for environmental liabilities from the party most capable of payment without regard to responsibility or fault. Whether or not the Company is ultimately held liable in such a circumstance, should litigation involving the Company and/or IRLP occur, the Company would probably incur substantial legal fees and experience a diversion of management resources from other operations. Although the Company does not believe it is liable for any of its subsidiaries' clean-up costs and intends to vigorously defend itself in such regard, the Company cannot predict the ultimate outcome of these matters due to inherent uncertainties. General Powerine Arbitration In June 1997, an arbitrator ruled in the Company's favor in an arbitration hearing concerning a contract dispute between MGNG and Powerine which had been assigned to the Company. In October 1997, the Company recovered $8,700,000 from the arbitration and sought an additional $2,142,000 plus interest. In January 1999, the Company recovered $900,000 in connection with the $2,142,000 sought. Rex Nichols et al Lawsuit In March of 1998, the Company, one of its subsidiaries and one of its officers were sued by two outside interest owners owning interests in several wells formerly operated by one of the Company's exploration and production subsidiaries. The lawsuit was filed in the Fourth Judicial District of Rusk County, Texas. The lawsuit, as initially filed, sought unspecified net production revenues resulting from reversionary interests on several wells formerly operated by the Company's subsidiary. Management believes the Company's exposure on the matter, if any, is less than $50,000. Subsequently, the plaintiffs expanded their petition claiming amounts due in excess of $250,000 based upon their interpretation of other provisions of the underlying oil and gas leases. The case is currently in discovery and no date has been set for a trial. Management believes that the plaintiffs additional claims are without merit and intends to vigorously defend its position. SWAP Agreement - MGNG In January 1998, IRLP filed suit against MG Refining and Marketing, Inc. ("MGR&M"), a subsidiary of MG, to collect $704,000 plus interest. The dispute concerned funds owed to IRLP but not paid by MGR&M. In February 1998, MG contended that the $704,000 was not owed to IRLP and that it had liquidated MGR&M. In April 1999, IRLP recovered $575,000 of the $704,000 sought. The difference between the book value, $704,000 and the actual recovery, $575,000 was recorded as a reduction in the value of discontinued net refining assets since the recovery relates to IRLP's discontinued refining operations (See Note 3 to the consolidated financial statements included in Item 8 of this Form 10-K.) Powerine/EMC/Litigation In July 1998, the Company sued Powerine and EMC to recover $330,000 plus interest. The amount sought represented amounts that Powerine or EMC were required to pay to the Company under the January 1996 purchase and sale agreement whereby Powerine merged into a subsidiary of EMC. In April 1999, the Company recovered $355,000 from EMC. The recovery was recorded as other income. -6- 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 have apparently now 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. No hearing has been held on the plaintiffs' request for class certification. After a lengthy period of inactivity the plaintiff's counsel has recently sought to continue or settle the case. At present no class has been certified and no trial date set. Based upon the revised pleadings, management of the Company initially determined that the worst possible exposure for the Company and its subsidiary limited partnerships for all gas sold to Lone Star, were they to lose the case on all points, was less than $3,000,000. However, the Company sold all of its Rusk County oil and gas properties to UPRC in May of 1997. The sale to UPRC effectively removed any possibility of exposure by the Company or its subsidiary limited partnerships to claims for additional royalties with respect to production after May 1997, thus reducing the exposure to the Company and its subsidiaries to less than $2,000,000 in actual damages if they were to lose the case on all points. Although the Company believes that the plaintiff's claims are without merit and intends to continue to vigorously defend itself in this matter, the Company cannot predict the ultimate outcome. MGNG Litigation On May 4, 1998, Production filed a lawsuit against MGNG and MG Gathering Company ("MGC"), two subsidiaries of MG, in the district court of Harris County, Texas. Production seeks to recover gas measurement and transportation expenses charged by the defendants in breach of a certain gas purchase contract. Improper charges exceed $750,000 before interest. In October of 1998, MGNG and MGC filed a suit in Harris County, Texas. This suit seeks indemnification from two of the Company's subsidiaries in the event Production wins its lawsuit against MGNG and MGC. The MG entities have 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 Company is pursuing this case using all legal remedies. The parties participated in mediation but were not able to resolve the issue. The case is expected to be scheduled for trial in May 2000. UPRC, to whom the Company sold its Rusk County, Texas oil and gas properties, has also informed the Company that it intends to sue MGNG on the same transportation expense issue. On October 6, 1999, MGNG filed a second lawsuit against the Company and three of its subsidiaries claiming $772,000 was owed to MGNG under a gas supply contract between one of the Company's subsidiaries and MGNG. The suit was filed in the district court of Harris County, Texas. The Company and its subsidiaries believe that they do not owe $772,000 and that they are entitled to offset some or all of the $772,000 claimed against amounts owed to Production by MGNG for improper gas measurement and transportation deductions. The Castle entities have answered this suit denying MGNG claims based partially on the legal right of offset. Pilgreen Litigation As part of the AmBrit purchase, CECI acquired a 10.65% overriding royalty interest ("ORRI") in the Pilgreen #2ST gas well in Texas. Because of title disputes, AmBrit and other interest owners had previously filed claims against the operator of the Pilgreen well, and CECI acquired post January 1, 1999 rights in that litigation. Although revenue attributed to the ORRI has been suspended by the operator since first production, because of recent related appellate decisions and settlement -7- negotiations, the Company believes that revenue attributable to the ORRI should be released to CECI in the second quarter of fiscal 2000. As of September 30, 1999, approximately $124,000 attributable to CECI's share of the ORRI revenue was suspended. 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 1999. -8- 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: The table below presents the high and low sales prices of the Company's Common Stock as reported by the NNM for each of the quarters during the two fiscal years ended September 30, 1999.
1999 1998 --------------------- ----------------------- High Low High Low --------- ------ ---------- -------- First Quarter (December 31).................................. $19.38 $16.88 $15.06 $12.75 Second Quarter (March 31).................................... $17.88 $15.75 $18.00 $13.50 Third Quarter (June 30)...................................... $19.25 $15.00 $20.63 $17.50 Fourth Quarter (September 30)................................ $18.25 $16.50 $19.69 $16.50
The final sale of the Company's Common Stock as reported by the NNM on November 22, 1999 was at $16.81. Dividends: On June 30, 1997, the Company's Board of Directors adopted a policy of paying regular quarterly cash dividends of $.15 per share on the Company's common stock. Commencing July 15, 1997, dividends have been paid quarterly. As with any company the declaration and payment of future dividends are subject to the discretion of the Company's Board of Directors and will depend on various factors. Approximate Number of Holders of Common Stock As of November 22, 1999, 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, 1999, the Company consummated a number of transactions affecting the comparability of the financial information set forth below. In August 1989, IRLP acquired the Indian Refinery. From April 1990 until September 30, 1995, IRLP, operated the Indian Refinery. In December 1992, three of the Company's subsidiaries acquired certain oil and gas and pipeline assets from ARCO. In October 1993, one of the Company's subsidiaries acquired Powerine, which owned the Powerine Refinery. During fiscal 1995, both refineries ceased operations and the Company's refining subsidiaries reached a settlement with MG and its affiliates and terminated most of their transactions and relationships with MG. By September 1995, the Company's refining subsidiaries had discontinued all their refining operations. In May 1997, the Company sold its Rusk County, Texas oil and gas properties and pipeline to UPRC and one of its subsidiaries. In June 1999, CECI acquired all of the oil and gas assets of AmBrit. See Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 4 to the Company's consolidated financial statements included in Item 8 of this Form 10-K. The following selected financial data have been derived from the Consolidated Financial Statements of the Company for each of the five years ended September 30, 1999. Certain information in the Consolidated Statements of Operations has been reclassified to give effect to the discontinuance of refining operations. The information should be read in conjunction with the consolidated financial statements and notes thereto included in Items 8 of this Form 10-K. -9- Earnings per share have been retroactively restated in accordance with SFAS 128.
For the Fiscal Years Ended September 30, ---------------------------------------------------------------- (in Thousands, except per share amounts) 1999 1998 1997 1996 1995 ---- ---- ---- ---- ---- Revenues: Natural gas marketing and transmission............. $50,067 $70,001 $ 64,606 $ 59,471 $ 70,402 Exploration and production......................... 7,190 2,603 7,113 9,224 9,197 Gross Margin: Natural gas marketing and transmission............. 19,005 26,747 24,640 25,238 30,242 Exploration and production......................... 4,802 1,828 5,173 7,179 6,831 Earnings before interest, taxes, depreciation, and amortization: Natural gas marketing and transmission............. 17,847 25,162 23,054 23,162 28,252 Exploration and production......................... 3,764 836 4,036 5,944 5,761 Corporate general and administrative expenses.......... (4,112) (3,081) (3,370) (3,499) (4,995) Depreciation, depletion and amortization............... (8,330) (9,885) (12,250) (13,717) (14,155) Interest expense....................................... (2) (1,038) (1,959) (4,046) Interest income and other income....................... 2,053 2,230 21,097(1) 3,884 966 ------- ------- -------- -------- --------- Income from continuing operations before income taxes.............................................. 11,222 15,260 31,529 13,815 11,783 Provision for (benefit of) income taxes related to continuing operations.............................. 2,956 1,204 4,663 (11,259) 37,823 ------- ------- -------- -------- --------- Income (loss) from continuing operations .............. 8,266 14,056 26,866 25,074 (26,040) Income from discontinued refining operations net of applicable income taxes............................ 40,937 ------- ------- -------- -------- --------- Net income............................................. $ 8,266 $14,056 $ 26,866 $ 25,074 $ 14,897 ======= ======= ======== ======== ========= Dividends.............................................. $ 2,048 $ 1,688 $ 1,446 ======= ======= ======== Net income (loss) per share (diluted): Continuing operations.............................. $ 2.97 $ 3.66 $ 4.64 $ 3.73 ($ 3.84) Discontinued operations............................ 6.04 ------- ------- -------- -------- --------- $ 2.97 $ 3.66 $ 4.64 $ 3.73 $ 2.20 ======= ======= ======== ======== ========= Dividends per share.................................... $ .75 $ .45 $ .30 ======= ======= ======== Balance Sheet Data: Working capital (deficit)........................... $26,489 $40,271 $ 46,384 ($ 4,452) ($ 12,474) Property, plant and equipment, net, including oil and gas properties............................... 26,985 4,969 2,998 36,223 40,406 Total assets........................................ 60,363 67,004 82,717 101,230 116,904 Long-term debt, including current maturities........ 14,006 35,946 Stockholders' equity................................ 53,503 51,553 67,765 66,711 41,637
- ------------- (1) Includes a $19,667 non-recurring gain on sale of assets. -10- ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ("000's" Omitted Except Share 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. As noted above, the Company sold its Rusk County, Texas oil and gas properties and pipeline to UPRC and its subsidiary, respectively, in May 1997. The oil and gas reserves sold approximated 84% of the Company's proved oil and gas reserves at the date of sale. As a result operations applicable to the assets sold impacted consolidated operations for eight months in fiscal 1997 and not at all thereafter. Also, as noted above, CECI acquired the oil and gas properties of AmBrit on June 1, 1999. The oil and gas reserves associated with the acquisition were estimated at approximately 12.5 billion cubic feet of natural gas and 2,000 barrels of crude oil or 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 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 because it sold its pipeline assets to a subsidiary of UPRC in May 1997 and because it is unlikely that similar profitable long-term contracts can be negotiated since most gas purchasers buy gas on the spot market. Although the Company is currently seeking additional natural gas marketing operations, it is currently operating exclusively in the exploration and production segment of the energy industry. As a result natural gas marketing operations impacted consolidated operations for all of fiscal 1997 and fiscal 1998 but only the first eight months of fiscal 1999. Fiscal 1999 vs Fiscal 1998 NATURAL GAS MARKETING Gas sales from natural gas marketing decreased $19,934 or 28.5% from fiscal 1998 to 1999. Gas sales in each fiscal year consist of the following: September 30, ---------------------- 1999 1998 ---- ---- Gas sales to Lone Star.......................... $46,802 $64,619 Gas sales to MGNG............................... 3,265 4,904 Gas sales to third parties...................... 478 ------- ------- $50,067 $70,001 ======= ======= -11- Gas sales to Lone Star and MGNG decreased from fiscal 1999 to fiscal 1998 because both of the relevant gas sales contracts terminated May 31, 1999 by their own terms. The natural gas volumes sold during the period October 1, 1998 to May 31, 1999 were the remaining contractual volumes required under the related long-term gas sales contracts with Lone Star and MGNG. The gas prices received by the Company's natural gas marketing subsidiary were essentially fixed both years so that the decreases in sales under both the Lone Star Contract and the contract with MGNG were caused by decreased volumes delivered. Gas Purchases Gas purchases decreased $12,192 or 28.2% from fiscal 1998 to fiscal 1999. Gas purchases in each of the fiscal years consist of the following: September 30 -------------------- 1999 1998 ---- ---- Gas purchases - Lone Star Contract............. $27,277 $36,898 Gas purchases - MGNG Contract.................. 3,785 5,897 Gas purchases - sales to third parties......... 459 ------- ------- $31,062 $43,254 ======= ======= Gas purchases decreased because the related long-term gas supply contracts with MGNG terminated and the Company ceased buying gas supplies on the spot market on May 31, 1999, the same day that the Lone Star Contract terminated. The gas price paid by the Company under such long-term gas supply agreement with MGNG was essentially fixed for approximately ninety percent (90%) of volumes purchased . The gas price paid for the remaining ten percent (10%) of gas supplies was based upon a market index price. The gross margin percentage (natural gas purchases as a percentage of natural gas sales) was essentially the same both years - 61.9% in fiscal 1999 and 61.8% in fiscal 1998. General and Administrative General and administrative costs decreased $27 from $62 for the year ended September 30, 1998 to $35 for the year ended September 30, 1999. The decrease was attributable to the termination of a natural gas hedging consulting arrangement on May 31, 1999, the date the Company's long-term gas contracts terminated. Transportation Transportation expense decreased $416 or 27% from $1,539 for the year ended September 30, 1998 to $1,123 for the year ended September 30, 1999. Transportation expense is based upon and thus proportional to deliveries made to Lone Star and represents the amortization of a $3,000 prepaid transportation asset received by one of the Company's subsidiaries in the sale of the Castle Pipeline to a subsidiary of UPRC in May 1997. Deliveries to Lone Star were approximately 37% greater during the year ended September 30, 1998 than during the year ended September 30, 1999 because deliveries to Lone Star ceased on May 31, 1999. By May 31, 1999, the $3,000 allocated to prepaid transportation had been completely amortized. Amortization Amortization of gas contracts decreased $3,178 or 33.6% from fiscal 1998 to fiscal 1999. The decrease is entirely attributable to the termination of the Lone Star Contract on May 31, 1999. For fiscal 1998 twelve months' of amortization are included in operations versus only eight months of amortization in fiscal 1999. Both the Lone Star Contract and the MGNG Contract expired May 31, 1999. During the year ended September 30, 1999, the operating income from these contracts was $11,563 or 126.1% of consolidated operating income. For the year ended September 30, 1998, the operating income from these contracts was $15,700 or approximately 120.5% of consolidated operating income for the period. The Company has not replaced these contracts because it sold its pipeline assets to a subsidiary of UPRC in May 1997 and because it is unlikely that similar profitable long-term contracts can be negotiated since most gas purchasers buy gas on the spot market. Although the Company is currently seeking additional natural gas marketing operations, it is currently operating exclusively in the exploration and production segment of the energy industry. -12- The Company is currently seeking to replace some or all of the operating income contribution of its former natural gas marketing operations with operating income from additional exploration and production properties and other energy assets. In that respect, the Company acquired the oil and gas assets of AmBrit, has entered into two drilling ventures in South Texas and has acquired a 50% interest in a drilling concession in Romania. In addition, subsequent to September 30, 1999, the Company acquired outside interests in wells it operates for $372 and entered into agreements to acquire other oil and gas properties (see above and Note 22 included in the consolidated financial statements included in Item 8 of this Form 10-K.) The Company is also currently reviewing several other possible exploration and production, pipeline and natural gas marketing acquisitions. There can, however, be no assurance the Company will succeed in these efforts. EXPLORATION AND PRODUCTION On June 1, 1999, the Company purchased all of AmBrit's oil and gas properties for $20,170 net of purchase price adjustments. AmBrit's oil and gas properties consist primarily of proved developed producing reserves. The current production from the AmBrit properties is approximately 425% that of the Company's other properties. In addition, the oil and gas reserves associated with the acquisition are estimated to be approximately 150% of the Company's other reserves. Therefore, as a result of this acquisition, the Company's exploration and production operations have increased significantly since June 1, 1999. In order to facilitate comparisons of financial data we have separately disclosed changes applicable to the acquisition of the AmBrit properties and those applicable to the Company's other exploration and production operations. The results are as follows:
Less Amounts Applicable Effect Of To Acquisition Non AmBrit Properties Change of AmBrit ----------------------------------- On Consolidated Properties Year Ended Operating Year Ended June 1, 1999- September 30, Year Ended Income: September 30, September 30, 1999 as September 30, Increase 1999 1999 Adjusted 1998 (Decrease) ------------------- -------------------- ------------------- --------------- ---------- Revenues - -------- Oil and gas sales.............. $6,712 $3,943 $2,769 $2,373 $396 Well operations................ 478 126 352 230 122 -------- -------- -------- ------- ----- 7,190 4,069 3,121 2,603 518 Expenses - -------- Oil and gas.................... (2,388) (1,438) (950) (775) (175) General and administrative..... (1,038) (22) (1,016) (992) (24) Depreciation, depletion and amortization................ (2,046) (1,214) (832) (423) (409) ------- ------ ------- -------- ---- Operating Income (loss).......... $1,718 $1,395 $ 323 $ 413 ($ 90) - ----------------------- ====== ====== ======= ======= ====
Although the Company has also invested in two exploration ventures in South Texas and a drilling concession in Romania, production from such ventures, if any, has not yet commenced. No proved reserves have been associated with any of these ventures. Revenues Oil and Gas Sales Oil and gas sales on non-AmBrit properties increased $396 or 16.7% from fiscal 1998 to fiscal 1999. Most of the increase is attributable to a 13% increase in production. Although oil and gas prices have recently increased significantly, they were lower during much of the year ended September 30, 1999. At September 30, 1999, the Company had hedged 54% of its anticipated oil production and 39% of its anticipated gas production for the year ended September 30, 2000. The crude oil was hedged at an average New York Mercantile Exchange ("NYMEX") price of $19.85 per barrel and the natural gas was hedged at an average price of $2.66 per mcf. The price the -13- Company receives for its production differs from the NYMEX pricing due to its location basis differentials. However, management believes the NYMEX pricing is highly correlated to its production field prices and expects to be able to apply hedge accounting to these derivative transactions. To the extent that futures NYMEX oil and gas prices average less than the prices at which the Company has hedged production, the Company's future oil and gas sales will increase above that which results from the sale of production at market prices. Conversely, to the extent that futures NYMEX prices exceed the average prices at which the Company has hedged its production, the Company's future oil and gas sales will decrease below that which results from the sale of production at market prices. At September 30, 1999, the Company had not hedged 46% and 61% of its anticipated crude oil and natural gas production, respectively. As a result, the Company remains exposed to oil and gas price risk on this unhedged production. As a result of the acquisition of the AmBrit oil and gas properties, the Company expects that its revenues from oil and gas sales will increase significantly in the future. Well Operations Revenue from non-AmBrit well operations increased $122 or 53% from fiscal 1998 to fiscal 1999. The increase was primarily caused by the non-recurring recovery of operating fees in 1999 that had been written off in prior years. Expenses Oil and Gas Production Oil and gas production expenses increased $175 or 22.6% from fiscal 1998 to fiscal 1999. The increase in oil and gas production expenses results from operating expenses related to eight new wells drilled in fiscal 1999 in which the Company has an interest and the general maturing of the Company's oil and gas properties and the tendency for older, depleting properties to carry a higher production expense burden than recently drilled properties. In fiscal 1999 oil and gas production expense comprised 34.3% of oil and gas sales versus 32.7% of oil and gas sales in fiscal 1998. For the period July 1, 1999 to September 30, 1999, oil and gas production expenses related to the AmBrit properties comprised 36.5% of related oil and gas sales from AmBrit properties. Since oil and gas production expenses generally increase as wells deplete, the Company expects that the oil and gas production expense percentage (oil and gas production expense as a percentage of oil and gas sales) will increase in the future given fixed oil and gas prices. Such increase may, however, be offset by a lower percentage of oil and gas production expenses to oil and gas sales for the Company's interests in new wells which the Company expects to be drilled. Depreciation, Depletion and Amortization Depreciation, depletion and amortization from non-AmBrit properties increased $409 or 96.7% from fiscal 1998 to fiscal 1999. Approximately 80% of the increase is attributable to a higher depletion rate per equivalent mcf produced. The higher depletion rate results from the acquisition of the AmBrit properties and the accounting requirement under full cost accounting that depreciation, depletion and amortization be computed on a consolidated basis by country - not on a separate property or field basis. Prior to the acquisition of the AmBrit properties, the Company's amortization rate per equivalent mcf produced was $.37 whereas after the acquisition the Company's rate was approximately $.71 per equivalent mcf produced. The remaining 20% of the increase in depreciation, depletion and amortization was caused by a 13% increase in production. CORPORATE GENERAL AND ADMINISTRATIVE EXPENSE Corporate general and administrative expenses increased $1,031 or 33.5% from fiscal 1998 to fiscal 1999. Most of the increase was caused by increased consulting fees applicable to due diligence for possible acquisitions. Increased employee bonuses and increased legal costs also contributed to the increase. -14- OTHER INCOME (EXPENSE) Interest Income Interest income decreased $570 or 25.1% from fiscal 1998 to fiscal 1999. The decrease is primarily attributable to a decrease in the average balance of unrestricted cash outstanding during the periods being compared. In June 1999, the Company paid $20,170 (net of purchase price) for AmBrit's oil and gas properties. In addition, during the year ended September 30, 1999, the Company spent $6,919 to acquire shares of its common stock. Other Income (Expense) The composition of other income (expense) is as follows:
Year Ended September 30, ----------------------------------- 1999 1998 --------------------- ------------ Write down of investment in Penn Octane Corporation preferred stock............................................................ ($423) Market price adjustment of investment in Penn Octane Corporation common stock..................................................... 431 Litigation recovery - EMC............................................. 355 Miscellaneous......................................................... (11) ($41) ----- ---- $352 ($41) ==== ====
The $423 write down of the Company's investment in the preferred stock of Penn Octane Corporation ("Penn Octane"), a public company selling liquid propane gas to northern Mexico, was based upon the Company's calculation of the loss that would be incurred if the Company converted its shares of Penn Octane preferred stock and sold the resulting common shares (unregistered) at a discount to the market price given the thin capitalization of Penn Octane and low trading volumes in its stock. Subsequently, the Company converted all of its Penn Octane preferred stock to Penn Octane common stock. The market price adjustment relates to the Company's investment in Penn Octane common stock. Until June 30, 1999, the Company classified Penn Octane securities as trading securities because all except 50,000 of the 551,000 common shares owned by the Company were registered and the Company did not expect to hold its Penn Octane investment for the long term. According to current generally accepted accounting principles, such securities were valued at fair market value with unrealized gains or losses included in earnings. The $431 favorable market adjustment resulted from the increase in the market price of Penn Octane common stock as of June 30, 1999. Effective June 30, 1999, the Company reclassified its investment in Penn Octane common stock as available-for-sale securities because the Company was not actively buying and selling Penn Octane securities. At September 30, 1999, the market value of the Company's investment in Penn Octane stock exceeded the Company's cost by $2,444. This unrealized gain, less $40 of estimated income taxes, has been recorded as other comprehensive income pursuant to SFAS 130. At September 30, 1999, the Company owned 1,067,667 shares of Penn Octane common stock representing approximately 8.5% of outstanding stock at September 30, 1999. The $355 litigation recovery was a non-recurring gain related to the Powerine/EMC Litigation occurring in the second fiscal quarter of 1999 for which there was no counterpart during the year ended September 30, 1998. -15- PROVISION FOR INCOME TAXES The tax provisions for the year ended September 30, 1999 and 1998 consist of the following components:
Year Ended September 30, ------------------------------ 1999 1998 ------------------ ---------- 1. Increase in net deferred tax asset using 36% Federal and state blended tax rate.................................................................... ($3,788) 2. Utilization of deferred tax asset, net of related valuation reserves, using 36% blended Federal and state tax rate.................................. $2,765 4,992 3. A tax provision of 2% on all net income in excess of that required to realize the net deferred tax asset. (This 2% rate represents alternative minimum Federal corporate taxes the Company must pay despite having tax carryforwards and credits available to offset regular Federal corporate tax).................................................................... 71 4. Other (primarily revisions of previous estimates)....................... 120 ------ $2,956 $1,204 ====== ======
The tax provision for the year ended September 30, 1998, consists primarily of a tax provision of $4,992 (utilization of deferred tax asset) and an offsetting reversal of tax estimates and contingencies of $3,788. The Company evaluated its need for a deferred tax valuation allowance at September 30, 1998 based upon positive evidence confirming the Company's ability to generate sufficient taxable income to utilize the deferred tax asset available and recorded a deferred tax asset, net of valuation reserves, of $3,788. The tax provision for the year ended September 30, 1999, consists of utilization of the $2,765 of remaining net deferred tax assets at September 30, 1998, $71 of Federal alternative minimum taxes on net income in excess of that required to fully utilize the $2,765 net deferred tax asset using a 36% blended tax rate and $120 of other taxes related to revisions to the prior year's taxable income. The fiscal 1999 blended Federal and state income tax rate was 26%, which is lower than the statutory rate due to the utilization of statutory depletion and tax credits. The Company did not record a net deferred tax asset at September 30, 1999 because it determined that future taxable income was less certain given the Company's large exploratory and wildcat drilling programs, the expiration of the Lone Star Contract, contingent environmental liabilities and other factors. EARNINGS PER SHARE Since November 1996, the Company has repurchased 4,486,017 or 66% of its common shares. As a result of these share acquisitions, earnings per share are higher than they would be if no shares had been repurchased. Fiscal 1998 vs Fiscal 1997 NATURAL GAS MARKETING AND TRANSMISSION Gas sales from natural gas marketing increased $5,402 or 8.4% from fiscal 1997 to 1998. Gas sales in each fiscal year consist of the following: September 30, -------------------------- 1998 1997 ---- ---- Gas sales to Lone Star................... $64,619 $59,695 Gas sales to MGNG........................ 4,904 4,904 Gas sales to third parties............... 478 ------- ------- $70,001 $64,599 ======= ======= -16- Lone Star Contract Natural gas sales under the Lone Star Contract increased $4,924 or 8.2% from fiscal 1997 to fiscal 1998. Under the Company's long-term gas sales contract with Lone Star, the price received for gas is essentially fixed through May 31, 1999. The variance in gas sales, therefore, is almost entirely attributable to the volumes of gas delivered. Although the volumes sold to Lone Star annually are essentially fixed (the Lone Star Contract has a take-or-pay provision), the Lone Star Contract year is from February 1 to January 31 whereas the Company's fiscal year is from October 1 to September 30. Furthermore, although the volumes to be taken by Lone Star in a given contract year are fixed, there is no provision requiring equal monthly or daily volumes and deliveries accordingly vary with Lone Star's seasonal and peak demands. Such variances have been significant. As a result, Lone Star deliveries, although fixed for a contract year, may be skewed and not proportional for the Company's fiscal periods. For fiscal 1998, sales to Lone Star were approximately $735 more than those which would have resulted if daily deliveries had been fixed and equal. At September 30, 1998, the remaining volumes to be delivered under the Lone Star Contract were approximately 8.4% greater than those that would be delivered if daily deliveries were fixed and equal. MGNG Contract Gas sales to MGNG remained the same in fiscal 1998 as in fiscal 1997 because the gas sales contract with MGNG requires a fixed daily volume of gas at a fixed price and the MGNG contract was in force for all of the periods being compared. Gas Purchases Gas purchases increased $3,288 or 8.2% from fiscal 1997 to fiscal 1998. Gas purchases in each of the fiscal years consist of the following:
September 30 --------------------- 1998 1997 ---- ---- Gas purchases - Lone Star Contract...................................................... $36,898 $34,686 Gas purchases - MGNG Contract........................................................... 5,897 5,280 Gas purchases - sales to third parties.................................................. 459 ------- ------- $43,254 $39,966 ======= =======
Gas purchases for the Lone Star Contract increased $2,212 or 6.4% from fiscal 1997 to fiscal 1998. For fiscal 1997 gas purchases comprised 58.1% of gas sales versus 57.1% of gas sales for fiscal 1998. From 1997 to 1998 the gross margin increased $2,712 or 10.8%. During the same periods the gross margin percentage ((gas sales - gas purchases) as a percentage of gas sales) increased 1.0% from 41.9% for fiscal 1997 to 42.9% for fiscal 1998. The decrease in gas purchases as a percentage of gas sales and the concomitant increase in gross margin percentage for the Lone Star Contract resulted primarily from non-recurring favorable adjustments of gas purchase costs in fiscal 1998 and the replacement of high price gas contracts expiring in April 1997 with lower market price contracts. Gas purchases for the contract with MGNG increased $617 or 11.7% from fiscal 1997 to fiscal 1998. The gas sales volumes sold to MGNG for each of the two years being compared were equal; hence the increase is entirely attributable to increased market prices for gas, net of hedging effects. Gas purchased for third parties increased from zero in fiscal 1997 to $459 in fiscal 1998. The gas sales to third parties in fiscal 1998 resulted because Lone Star limited its daily gas purchases to 103% of volumes nominated and the Company had to sell the excess gas elsewhere. The restriction of daily sales to 103% of volumes nominated did not, however, affect annual volumes that Lone Star was required to take under the Lone Star Contract. In August 1998, the Company hedged all of its remaining unhedged gas requirements. As a result of such hedging, the Company had fixed its price exposure on its gas sales contract with MGNG through May 31, 1999, the termination date for the contract. -17- Operating Costs Operating costs decreased to a recovery of $16 for the year ended September 30, 1998 from $472 for the year ended September 30, 1997 because the Texas pipeline was sold to UPRC in May 1997 and as of June 1, 1997 the Company no longer incurred operating costs to operate the Texas pipeline. General and Administrative General and administrative expenses decreased $714 from $776 for the year ended September 30, 1997 to $62 for the year ended September 30, 1998. Most general and administrative expenses incurred during the year ended September 30, 1997 related to the Texas pipeline, which was sold in May 1997. The remaining administrative expenses consist primarily of consulting fees for on-going gas marketing operations. Transportation Transportation expense increased $1,201 from $338 for the year ended September 30, 1997 to $1,539 for the year ended September 30, 1998. During the period October 1, 1996 to May 31, 1997, one of the Company's subsidiaries owned and operated the Texas pipeline and all transportation revenues were for intercompany transportation and were accordingly eliminated in consolidation of the Company's financial statements. On May 30, 1997, the Company sold the Texas pipeline to a subsidiary of UPRC. In both 1997 and 1998, transportation expense consisted entirely of the amortization of a $3,000 prepaid transportation asset. Amortization is based upon and thus proportional to deliveries made to Lone Star. In fiscal 1997, four months' transportation expense was recorded versus twelve months' transportation expense in fiscal 1998. Depreciation and Amortization Depreciation and amortization decreased $1,177 or 11.1% from fiscal 1997 fiscal 1998. The decrease is attributable to the sale of the Texas pipeline to a subsidiary of UPRC in May 1997. As a result of the sale, the Company no longer owned or depreciated the Texas pipeline. EXPLORATION AND PRODUCTION As noted above, the Company sold its Texas oil and gas properties to UPRC in May 1997. The reserves sold represented approximately 84% of the Company's proved oil and gas reserves and 60%-65% of the Company's oil and gas production at the time of sale. Comparison of fiscal 1998 oil and gas sales, production expenses, general and administrative expenses and depletion, depreciation and amortization to those in fiscal 1997 is thus not meaningful. Accordingly, exploration and production operations comparisons and analysis have been limited to operations from those oil and gas properties which were not sold to UPRC. The related operating results for such properties are as follows:
Year Ended September 30, ----------------------------- 1998 1997 ---- ---- Revenues: Oil and gas sales................................................ $2,373 $3,111 Well operations.................................................. 230 287 -------- ------ 2,603 3,398 ------- ------ Expenses: Oil and gas production........................................... 775 528 General and administrative....................................... 992 745 Depreciation, depletion and amortization......................... 423 653 -------- ------ 2,190 1,926 ------- ------ Operating income.................................................... $ 413 $1,472 ======= ======
-18- Revenues Oil and Gas Sales Oil and gas sales decreased $738 or 23.7% from fiscal 1997 to fiscal 1998. The decrease is attributable to decreased oil and gas prices and decreased production. Many of the Company's oil and gas reserves are mature reserves and such decreased production is expected. Although the Company has participated in drilling twenty-three new wells and several reworks on existing wells from July 1997 through September 30, 1998, production from such new drilling activities has only recently begun impacting operations. The Company is also reviewing possible investments in other oil and gas drilling programs and oil and gas property acquisitions, including several requiring substantial investment. As a result, the Company expects that, if it is successful in making acquisitions, its oil and gas sales will eventually increase given stable oil and gas sales prices. However, there can be no assurance that wells expected to be drilled will actually be drilled, that such drilling will be successful or that the Company will be successful in making acquisitions or that oil and gas sales will increase. Well Operations Revenue from well operations decreased $57 or 19.9% from fiscal 1997 to fiscal 1998. The decrease is attributable to the Company's resignation as operator on certain Appalachian wells in fiscal 1997 where a non-operator offered to operate the wells at a cost significantly less than that being incurred by the Company in performing such operations. The related well operations revenues were not replaced. Expenses Oil and Gas Production Oil and gas production expenses increased $247 or 46.8% from fiscal 1997 to fiscal 1998. The increase in oil and gas production expenses results from the general maturing of the Company's oil and gas properties and the tendency for older, depleting properties to carry a higher production expense burden than recently drilled properties. Furthermore, oil and gas production expenses, especially non-capitalized repairs, do not generally occur evenly each year and are best compared on a cumulative rather than on an annual basis. There can be no assurance, however, that such will be the case. General and Administrative General and administrative costs increased $247 or 33.2% from fiscal 1997 to the fiscal 1998. The net increase was primarily attributable to higher employee costs and bonuses, higher consulting fees and increased legal costs. The increase was offset to a minor extent by tax refunds and vendor settlements in fiscal 1998 for which there was no counterpart in fiscal 1997. Depreciation, Depletion and Amortization Depreciation, depletion and amortization decreased $230 or 35.2% from fiscal 1997 to the fiscal 1998. The decrease is attributable to slightly decreased production and significantly lower depletion rate per unit of production. The lower depletion rate results primarily from the Company's sale of 84% of its proved oil and gas reserves to UPRC. OTHER INCOME (EXPENSE) Gain on Sale of Assets In May 1997, the Company's subsidiaries sold their Texas oil and gas assets and pipeline to UPRC, resulting in a $19,667 gain. There was no counterpart in fiscal 1998. Interest Income Interest income increased $786 or 52.9% from fiscal 1997 to fiscal 1998. The increase is primarily attributable to an increase in the average balance of invested unrestricted cash. For the year ended September 30, 1997, $800 of interest income was attributable to a note receivable from MG related to the Powerine Arbitration and $685 resulted from the investment of excess cash. For the year ended September 30, 1998, $31 was attributable to interest on the MG note, $94 was attributable -19- to interest on a note from Penn Octane Corporation ("Penn Octane"), a public company involved in liquid petroleum and compressed natural gas business, and the remaining $2,146 was attributable to the investment of excess cash. Interest on the MG note ceased on October 14, 1997. Interest Expense Interest expense decreased $1,036 from $1,038 for the year ended September 30, 1997 to $2 for the year ended September 30, 1998 because the Company repaid all of its long-term debt in May 1997 with a portion of the proceeds from the sale of its Texas oil and gas properties and pipeline to UPRC. Penn Octane Note In October 1997, the Company invested $1,000 in a promissary note of Penn Octane. The note bears interest at 10% payable quarterly and was due on June 30, 1998. At June 30, 1998, Penn Octane did not repay the note. In May of 1998, Penn Octane was awarded a judgement against a bank and such judgement is in excess of the $1,000 owed to the Company by Penn Octane. In December 1998, Penn Octane assigned its interest in the bank judgement to the extent of the Company's note to the Company in return for an extension of the note until June 30, 1999. The Company also received 225,000 warrants to purchase the common stock of Penn Octane for one dollar and seventy-five cents per share as consideration for the extension. The bank owing the judgement has appealed it and such appeal may not be resolved for a year or more. As a result, there can be no assurance that the judgement will be upheld upon appeal or that the bank will ultimately pay the judgement won by Penn Octane to the Company. If the note is not repaid by its extended due date, the Company intends to reduce the Penn Octane note to its estimated realizable value, if any. GAMXX On February 27, 1998, the Company entered into an agreement with Alexander Allen, Inc. ("AA") concerning amounts owed to the Company by AA and its subsidiary, GAMXX Energy, Inc. ("GAMXX"). The Company had made loans to GAMXX through 1991 in the aggregate amount of approximately $8,000. When GAMXX was unable to obtain financing, the Company recorded a one hundred percent loss provision on its loans to GAMXX in 1991 and 1992 while still retaining its lender's lien against GAMXX. Pursuant to the terms of the GAMXX Agreement, the Company is to receive $1,000 cash in settlement for its loans when GAMXX closes on its financing. GAMXX expected such closing not later than May 31, 1998 but such closing has not yet occurred. The Company has carried its loans to GAMXX at zero the last six years. The Company will record the $1,000 proceeds as "other income" if and when it collects such amount. There can be no assurance that GAMXX will close on its financing. PROVISION FOR INCOME TAXES As a result of the tax benefit recorded in fiscal 1996, the Company expected to provide for income taxes at a 36% blended statutory rate for the remainder of the Lone Star Contract for book purposes. During this period the Company expected to pay income taxes, however, at a 2% effective rate, consisting of Federal alternative minimum tax. The Company's tax provision for fiscal 1997 consists of two components: a. The tax provision on pre-tax accounting income, exclusive of the $19,667 gain on the sale of assets, aggregates $4,270 and essentially represents the partial utilization of the $7,716 deferred tax asset recorded at September 30, 1996 at an effective rate of 36% of earnings. If future events change the Company's estimate concerning the probability of utilizing its tax assets, appropriate adjustments will be made when such a conclusion is reached. b. The tax provision on the $19,667 gain equals the Company's expected tax liability for the income related to the sale and aggregates $393. The tax rate used in such calculation was 2%, the Federal alternative minimum tax rate. The Company is not yet subject to a higher tax rate due to its tax carryforwards. A tax provision of 36% was not provided for the gain because a related deferred tax asset was not previously provided since the Company did not anticipate selling the properties and had previously taken the properties off the market. -20- The tax provision for the year ended September 30, 1998 consists primarily of a tax provision of $4,992 (utilization of deferred tax asset) and an offsetting reversal of tax estimates and contingencies of $3,463. The Company evaluated its need for a deferred tax valuation allowance at September 30, 1998 based upon recent positive evidence confirming the Company's ability to utilize its tax carryforwards. EARNINGS PER SHARE Since November 1996, the Company has reacquired 3,486,017 shares of its common stock. As a result of these share acquisitions, earnings per outstanding share have been higher than would be the case if no shares had been repurchased LIQUIDITY AND CAPITAL RESOURCES All statements other than statements of historical fact contained in this report are forward-looking statements. Forward- looking statements in this report generally are accompanied by words such as "anticipate," "believe," "estimate," or "expect" or similar statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, no assurance can be given that such expectations will prove correct. Factors that could cause the Company's results to differ materially from the results discussed in such forward-looking statements are disclosed in this report, including without limitation in conjunction with the expected cash sources and expected cash obligations discussed below. All forward-looking statements in this Form 10-K are expressly qualified in their entirety by the cautionary statements in this paragraph. Furthermore, this statement constitutes a Year 2000 Readiness Disclosure Statement and the statements contained herein are subject to the Year 2000 Information and Readiness Disclosure Act ("Act"). In case of a dispute, this document and information contained herein are entitled to protection of the Act. During the year ended September 30, 1999, the Company generated $17,567 from operating activities. During the same period the Company invested $23,964 in oil and gas properties and $6,919 to reacquire shares of its common stock. In addition, it paid $1,681 in stockholder dividends. At September 30, 1999, the Company had $22,252 of unrestricted cash, $26,489 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 financial statements included in Item 8 of this Form 10-K). Expected Sources and Uses of Funds As of November 22, 1999, the estimated future cash expenditures of the Company for the next two fiscal years consist of the following: a. Investments in Oil and Gas Properties and Other Energy Sector Ventures Subsequent to September 30, 1999, the Company spent $372 to acquire outside interests in gas wells it operated in Alabama. During this period the Company also entered into agreements to purchase additional outside interests in the Alabama wells, to purchase majority interests in several Pennsylvania wells and to purchase majority interests in 26 Louisiana offshore wells. The total cost to the Company, after purchase price adjustments, and assuming all three transactions are consummated, is approximately $3,075. In addition, the Company anticipates the following exploration and drilling expenditures over the next two fiscal years: 1. Development drilling on existing acreage............ $ 4,000 2. South Texas exploratory drilling ventures........... 6,500 3. Romanian concession ................................ 2,000 ------- $12,500 ======= If the initial drilling results in the South Texas drilling ventures are less favorable than anticipated, the Company expects to be able to reduce this drilling commitment by approximately $3,000. Conversely, if the initial results are better than expected the Company may participate in the drilling of more wells than budgeted above. If the initial wildcat Romanian wells are successful, the Company may also increase its investment in that country significantly and could conceivably spend $10,000-$15,000 if new oil and gas fields are discovered. -21- In addition, the Company is currently pursuing several other possible material investments in the energy sector. These possible investments include drilling ventures, the acquisition of oil and gas properties and oil and gas companies, as well as the acquisition of pipelines and gas marketing operations. Although most of these possible investments involve domestic properties, some involve investments overseas. Although the Company has concluded several transactions and believes it can conclude an additional transaction or several transactions on terms favorable to the Company, there can be no assurance that such will be the case. Oil and gas prices have recently increased significantly and many potential sellers have decided not to sell or have not been forced to sell by their lenders. In addition, several sellers have raised the price for the oil/gas properties they are selling given currently high oil and gas prices and acquisition of such properties at such high prices would not be in the Company's best interest. In addition, several large oil and gas companies have significantly more resources than the Company and other parties may be willing to pay more than the Company for a given acquisition. b. Repurchase of Company Shares - as of November 22, 1999, the Company had repurchased 4,486,017 of its shares of common stock at a cost of $64,192. The Company's Board of Directors previously authorized the repurchase of up to 4,750,000 shares to provide an exit vehicle for investors who want to liquidate their investment in the Company. The decision whether to repurchase additional shares and/or to increase the repurchase authorization above 4,750,000 shares will depend upon the market price of the Company's stock, tax considerations, the number of stockholders seeking to sell their shares and other factors. c. Recurring Dividends - the Company's Board of Directors adopted a policy of paying a $.60 per share annual dividend ($.15 per share quarterly) in June of 1997. The Company expects to continue to pay such dividend until the Board of Directors, in its sole discretion, changes such policy. At September 30, 1999, the Company had available the following sources of funds: Unrestricted cash - September 30, 1999............................. $22,252 Line of credit - energy bank....................................... 30,000 Marketable securities.............................................. 3,761 ------- $56,013 ======= In addition, the Company anticipates significant future cash flow from exploration and production operations. The estimated sources of funds are subject to most of the risks enumerated below. The realization from the sale of the Company's investment in Penn Octane is dependent on the market value of such stock and the Company's ability to liquidate its Penn Octane stock investment at or near market values. Since Penn Octane is thinly capitalized and traded, liquidation of a large volume of Penn Octane stock without significantly lowering the market price may be impossible. The Company thus expects that it can fund all of its present drilling commitments from its own unrestricted cash. The Company can also use its unrestricted cash and future cash flow, as well as up to $30,000 from it line of credit, to acquire additional oil and gas properties and to conduct additional drilling. As a result, the Company believes it has available the financing to make additional future acquisitions of up to approximately $40,000-$57,000 while still funding its existing drilling commitments. The Company has also negotiated with several potential industry partners who may provide financing if the Company decides to make an acquisition for prices in excess of these amounts. The Company's future operations are subject to the following risks: 1. Contingent Environmental Liabilities Although the Company has never itself conducted refining operations and its refining subsidiaries have exited the refining business and the Company does not anticipate any required expenditures related to discontinued refining operations, interested parties could seek redress from the Company for environmental liabilities. In the past, government and other plaintiffs have often named the most financially capable parties in such cases regardless of the existence or extent of actual liability. As a result there exists the possibility that the Company could be named for any environmental claims related to discontinued refining operations of its present and former refining subsidiaries. -22- The Company was informed that the EPA has investigated offsite acid sludge waste found near the Indian Refinery and was also remediating surface contamination in the Indian Refinery property. Neither the Company nor IRLP has been named with respect to these two actions. In October 1998, the EPA named the Company and two of its subsidiaries as potentially responsible parties for the expected clean-up of the Indian Refinery. In addition, eighteen other parties were named including Texaco Refining and Marketing, Inc., 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 expects to respond to the EPA information request in the second quarter of fiscal 2000. Estimated undiscounted clean-up costs for the Indian Refinery are $80,000 to $150,000 according to third parties. If the Company were found liable for the remediation of the Indian Refinery, it could be required to pay a percentage of the clean-up costs. Since the Company's subsidiary only operated the Indian Refinery five years whereas Texaco and others operated it over 50 years, the Company would expect that its share of any remediation liability would be proportional to its years of operation although such may not be the case. Although the Company does not believe it has any liabilities with respect to the environmental liabilities of the refineries, a court of competent jurisdiction may find otherwise. A decision by the U.S. Supreme Court in June 1998 in a comparable case supports the Company's position. The above estimate of expected cash resources and cash obligations assumes no expenditure for 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 resources will be decreased and such decrease could be significant. 2. IRLP Vendor Liabilities: IRLP owes its vendors approximately $5,000. Its only major asset was a $5,388 note due from the purchaser of the Indian Refinery, American Western. We have recently been informed that IRLP has agreed to settle its $5,388 note for approximately $800 in exchange for a covenant of the EPA not to sue IRLP. Assuming such a settlement is consummated, IRLP will be able to pay its creditors only a small portion of the amounts owed to them. 3. Larry Long Litigation: The above cash flow assumes the Company will not have to pay any claim related to the Larry Long litigation. Although the sale of the Company's Texas oil and gas properties and pipeline to UPRC have significantly reduced the Company's exposure, there can be no assurance that the plaintiffs will not file new lawsuits, having already amended their original complaint three times. In such case, the Company would be exposed to the continuing legal costs of defending the amended petitions, and, if it is determined that settlement is in the Company's best interest, the cost to settle the lawsuit. 4. 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 4,486,017 or 66% of its outstanding common stock since November of 1996 and has effectively become the major market maker in the Company's stock. If the Company ceases repurchasing shares the market value of the Company's stock may be adversely affected. 5. Year 2000 The Company has completed a study of the Year 2000 issue and related risks. As a result of the study, the Company has replaced its oil and gas and general ledger software with new software which is Year 2000 compliant. Total costs to purchase and install the new system were $122. The Company commenced using the new software in the first quarter of fiscal 1999 and has encountered no significant problems to date. The -23- Company has also made inquiries to outside parties who process transactions of the Company, e.g., payroll, commercial banks, transfer agent, reserve engineers, etc. While most outside parties have confirmed they are Year 2000 compliant, a few have not done so to the Company's satisfaction. The Company is continuing to pursue the vendors whose responses appear to provide insufficient assurance. The most important systems operated by the Company are its revenue distribution, joint interest billing and general ledger systems. The Company installed new systems because the new systems are Year 2000 compliant. If a Year 2000 problem nevertheless occurred, the Company could process transactions for several months manually or using small computers but only with increased administrative costs. Nevertheless, in many cases, the Company is not the operator of a given well or purchaser of oil and gas production. In those cases the Company is dependent upon the operator and/or gas/oil purchaser for accurate volumetric, cost and sales information and for payments. Although the Company has made Year 2000 inquiries of such operators and purchasers and generally received satisfactory responses, there can be no assurance that such operators and purchasers will actually be Year 2000 compliant. If such is the case, the Company could find a portion of its production revenue held in escrow until Year 2000 compliance was achieved or resulting litigation settled. The related legal cost and resulting administrative confusion could be substantial. The Company has made contingency plans in the event of non-compliance of its systems, but can do little in the case of non-compliance by outside operators and oil/gas purchasers. If outside operators and/or purchasers experience major Year 2000 disruptions, the Company's cash flow would be negatively impacted. If such outside operators and/or purchasers were unable to record production and disburse payments, the Company's share of production proceeds could be tied up for several months until the disruptions are fixed and retroactive processing is completed. Since three oil and gas purchasers buy in excess of 60% of the Company's current production, the impact on the Company of any one or more of the three experiencing Year 2000 problems could be substantial. Although most operators and purchasers have provided some written assurance that they are or will be Year 2000 compliant, such may not be the case. The Company and its subsidiaries are not aware of any material Year 2000 operational risks with respect to wells it operates. 6. Foreign Operating Risks Since the Company anticipates spending a minimum of approximately $3,000 drilling a Romanian concession of which $934 was incurred by September 30, 1999, the Company's interests are subject to certain foreign country risks over which the Company has no control - including political risk, currency risk, the risk of additional taxation and the possibility that foreign operating requirements and procedures may reduce or eliminate estimated profitability. 7. Exploration and Production Reserve Risk The Company is currently participating in several drilling ventures. Most of these ventures involve exploratory drilling where the probability of discovering commercial oil and gas reserves is less than fifty percent (50%). The drilling investment is essentially a sunk cost. Reserve risk is the possibility that the reserves discovered, if any, will not approximate those the Company has estimated before drilling. If commercial reserves are not found the Company's future operations and cash flow will be adversely affected. 8. Exploration and Production Price Risk The Company has hedged approximately 54% of its anticipated crude oil production and 39% of its anticipated natural gas production for the year ended September 30, 2000 at prices which are expected to provide profitable margins. The Company has not hedged any of its anticipated oil and gas production beyond December 2000 because the cost to do so appears excessive when compared to the risk involved. As a result of the Company remains exposed to future oil and gas price changes with respect to approximately 46% of its estimated crude oil production and 61% of its anticipated natural gas production through September 2000 and virtually all of its anticipated oil and gas production thereafter. Such exposure could be considerable given the volatility of oil and gas prices. For example, from February 1999 to October 1999, crude oil prices essentially doubled. In the past crude oil prices and gas prices have shown general volatility over short periods of time. -24- 9. Exploration and Production Operating Risk All of the Company's current oil and gas properties are onshore properties with relatively low operating risk. As noted above, the Company acquired a fifty percent (50%) interest in a Romanian oil and gas concession in fiscal 1999 and is currently involved in seismic and other pre-drilling activities in that country. In addition, in May 1999, the Company entered into an agreement to acquire majority interests in twenty-six (26) offshore Louisiana wells for which the Company will be the operator. The operating risks associated with the Romanian drilling concession and the Louisiana offshore wells expected to be acquired are significantly greater than those associated with the operation of onshore wells. Operations in Romania may, for example, be impacted by the lack of rig availability or access to operating supplies, equipment, skilled operating personnel or by excessive governmental regulations. Although the Company will not operate any Romanian wells it is affected by and bears fifty percent (50%) of the costs related to the such operating activities. In Louisiana, where the Company expects to become operator, operations will be impacted by the inherent difficulties of producing crude oil in offshore waters including but not limited to the necessity of transporting crude oil by barge and operating the producing wells from a drilling platform rather than from dry land. 10. 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 appears to affect most corporations. 11. Future of the Company The oil and gas industry is a dynamic constantly changing industry. In the last five years the rate of mergers and acquisitions within the industry has accelerated significantly as companies seek to consolidate operations, shed unprofitable operations and reduce administrative costs. Although the Company has recently acquired the oil and gas assets of AmBrit and invested in other oil and gas acquisitions, there can be no assurance that the Company will not become the acquisition target of another larger oil and gas company. As a result , the Company's Board of Directors may decide to pursue other courses of action, including but not limited to liquidation, sale of assets, merger or other reorganization. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK The Company has hedged approximately 54% percent of its estimated consolidated crude oil production (approximately 30,000 barrels per month) and 39% of its estimated natural gas production (approximately 350,000 mcf per month) through September 30, 2000 using futures contracts. The Company has also hedged approximately 14% of its anticipated natural gas production for the year ended September 30, 2001. The average hedged prices (based on NYMEX prices) are $19.85 per barrel for crude oil and $2.66 per mcf for natural gas. The price the Company receives for production differs from the NYMEX pricing due to its location basis differentials. However, management believes that NYMEX pricing is highly correlated to its production field prices and expects to be able to apply hedge accounting to these derivative transactions. The Company therefore remains at risk primarily with respect to its unhedged production. If oil and gas market prices increase, oil and gas revenues applicable to the unhedged production will increase. If oil and gas market prices decrease, oil and gas revenues related to such unhedged production will decrease. Based upon the volumes hedged at September 30, 1999, future oil and gas sales would increase approximately $555 if NYMEX prices decreased 10%. Conversely, future oil and gas sales would decrease approximately $448 if NYMEX prices increased 10%. The Company also remains at risk with respect to differences between the exchange prices on the New York Mercantile Exchange and the field or spot prices it receives with respect to its production. 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. -25- NEW ACCOUNTING PRONOUNCEMENTS In June 1997, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards No. 130 ("SFAS 130") regarding reporting comprehensive income, which establishes standards for reporting and display of comprehensive income and its components. The components of comprehensive income refer to revenues, expenses, gains and losses that are excluded from net income under current accounting standards, including foreign currency translation items, minimum pension liability adjustments and unrealized gains and losses on certain investments in debt and equity securities. SFAS 130 requires that all items recognized under accounting standards as components of comprehensive income be reported in a financial statement displayed in equal prominence with the other financial statements; the total of other comprehensive income for a period is required to be transferred to a component of equity that is separately displayed in a statement of financial condition at the end of an accounting period. SFAS 130 was effective for both interim and annual periods for companies having fiscal years beginning after December 15, 1997. Reclassification of financial statements for earlier periods provided for comparative purposes was required. The Company adopted SFAS 130, effective October 1, 1998. In June 1997, FASB issued Financial Accounting Standards Board No. 131 ("SFAS 131") regarding disclosures about segments of an enterprise and related information. SFAS 131 established standards for reporting information about operating segments in annual financial statements and required the reporting of selected information about operating segments in interim financial reports issued to stockholders. It also established standards for related disclosures about products and services, geographic areas and major customers. SFAS 131 was effective for companies having fiscal years beginning after December 15, 1997. The Company adopted SFAS No. 131 as of October 1, 1998. The provisions of SFAS 131 have not materially changed the Company's disclosures and reported financial information to the present because the Company has presented the required segment information in its consolidated statements of operations for several years before SFAS 131 was effective and continue to do so. Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"), was issued by the Financial Accounting Standards Board in June 1998. SFAS 133 standardizes the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. Under the standard, entities are required to carry all derivative instruments in the statement of financial position at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, 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. SFAS 133 is effective for all fiscal quarters of fiscal years beginning after June 15, 2000. The Company anticipates that it will adopt SFAS 133 effective October 1, 2000. As noted above, the Company has hedged much of its anticipated oil and gas production for the fiscal year ended September 30, 2000. The Company currently accounts for its crude oil and natural gas hedges pursuant to Statement of Financial Accounting Standards No. 80, Accounting for Futures Contracts ("SFAS 80") and expects to do so until adoption of SFAS 133 is required. Under SFAS 80 gains and losses from hedging activities are credited or debited to the item being hedged. For natural gas marketing hedging activities, the item being hedged was gas purchases. For exploration and production hedges, the item being hedged is oil and gas sales. The Company has not yet determined the impact of SFAS 133 on its financial condition or results of operations. RISK FACTORS See above. -26- ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page ---- CONSOLIDATED FINANCIAL STATEMENTS: Consolidated Statements of Operations for the Years Ended September 30, 1999, 1998 and 1997................. 28 Consolidated Balance Sheets as of September 30, 1999 and 1998............................................... 29 Consolidated Statements of Cash Flows for the Years Ended September 30, 1999, 1998 and 1997................. 30 Consolidated Statements of Stockholders' Equity and Other Comprehensive Income for the Years Ended September 30, 1999, 1998 and 1997............................................................. 32 Notes to the Consolidated Financial Statements.............................................................. 33 INDEPENDENT AUDITORS' REPORT................................................................................ 57
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 Per Share Amounts)
Year Ended September 30, -------------------------------------------- 1999 1998 1997 ---- ---- ---- Revenues: Natural gas marketing and transmission: Gas sales.............................................. $ 50,067 $ 70,001 $ 64,599 Transportation......................................... 7 ----------- ------------ ----------- 50,067 70,001 64,606 ------------ ------------- ----------- Exploration and production: Oil and gas sales...................................... 6,712 2,373 6,740 Well operations........................................ 478 230 373 ----------- ------------ ----------- 7,190 2,603 7,113 ----------- ------------ ----------- 57,257 72,604 71,719 ----------- ------------ ----------- Expenses: Natural gas marketing and transmission: Gas purchases.......................................... 31,062 43,254 39,966 Operating costs........................................ (16) 472 General and administrative............................. 35 62 776 Transportation......................................... 1,123 1,539 338 Depreciation and amortization.......................... 6,284 9,462 10,639 ----------- ------------ ----------- 38,504 54,301 52,191 ----------- ------------ ----------- Exploration and production: Oil and gas production................................. 2,388 775 1,940 General and administrative............................. 1,038 992 1,137 Depreciation, depletion and amortization............... 2,046 423 1,611 ----------- ------------ ----------- 5,472 2,190 4,688 ----------- ------------ ----------- Corporate general and administrative..................... 4,112 3,081 3,370 ----------- ------------ ----------- 48,088 59,572 60,249 ----------- ------------ ----------- Operating income............................................. 9,169 13,032 11,470 ----------- ------------ ----------- Other income (expense): Gain on sale of assets................................... 19,667 Interest income.......................................... 1,701 2,271 1,485 Other income (expense)................................... 352 (41) (55) Interest expense......................................... (2) (1,038) ----------- ------------ ----------- 2,053 2,228 20,059 ----------- ------------ ----------- Income before provision for income taxes.................... 11,222 15,260 31,529 ----------- ------------ ----------- Provision for income taxes: State.................................................... 79 40 119 Federal.................................................. 2,877 1,164 4,544 ----------- ------------ ----------- 2,956 1,204 4,663 ----------- ------------ ----------- Net income................................................... $ 8,266 $ 14,056 $ 26,866 =========== ============ ============ Net income per share: Basic.................................................... $ 3.02 $ 3.71 $ 4.66 =========== ============ ============== Diluted.................................................. $ 2.97 $ 3.66 $ 4.64 =========== ============ ============== Weighted average number of common and potential dilutive shares outstanding: Basic................................................ 2,735,167 3,790,100 5,764,045 ========== =========== =========== Diluted.............................................. 2,782,644 3,837,903 5,795,341 ========== =========== ===========
The accompanying notes are an integral part of these financial statements -28- CASTLE ENERGY CORPORATION CONSOLIDATED BALANCE SHEETS ("000's" Omitted Except Share Amounts)
September 30, --------------------- 1999 1998 ---- ---- ASSETS Current assets: Cash and cash equivalents......................................................... $ 22,252 $ 36,600 Restricted cash................................................................... 770 613 Accounts receivable............................................................... 5,172 8,381 Marketable securities............................................................. 4,194 471 Prepaid transportation, net....................................................... 1,123 Prepaid expenses and other current assets......................................... 594 293 Prepaid gas purchases............................................................. 852 Deferred income taxes............................................................. 2,765 Note receivable - Penn Octane Corporation......................................... 1,000 Estimated realizable value of discontinued net refining assets.................... 800 3,623 -------- -------- Total current assets............................................................ 33,782 55,721 Property, plant and equipment, net: Natural gas transmission.......................................................... 60 62 Furniture, fixtures and equipment................................................. 298 307 Oil and gas properties, net (full cost method).................................... Proved properties............................................................... 24,765 4,385 Unproved properties not being amortized......................................... 1,862 215 Gas contracts, net.................................................................... 6,285 Other assets.......................................................................... 29 29 -------- -------- Total assets.................................................................... $ 60,796 $ 67,004 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Dividend payable.................................................................. $ 368 Accounts payable.................................................................. 2,918 $ 8,658 Accrued expenses.................................................................. 802 1,663 Net refining liabilities retained................................................. 3,205 5,129 -------- -------- Total current liabilities....................................................... 7,293 15,450 Long-term liabilities................................................................. - 1 -------- -------- Total liabilities............................................................... 7,293 15,451 -------- -------- 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; 6,828,646 shares and 6,803,646 shares at September 30, 1999 and 1998, respectively.......................................................... 3,414 3,402 Additional paid-in capital........................................................ 67,365 67,122 Accumulated other comprehensive income - unrealized gains on marketable securities, net of taxes.......................................... 2,396 Retained earnings................................................................. 41,054 34,836 --------- -------- 114,229 105,360 Treasury stock at cost - 4,282,217 shares at September 30, 1999 and 3,862,917 shares at September 30, 1998...................................... (60,726) (53,807) --------- -------- Total stockholders' equity...................................................... 53,503 51,553 --------- -------- Total liabilities and stockholders' equity...................................... $ 60,796 $ 67,004 ======== ========
The accompanying notes are an integral part of these financial statements -29- CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS ("000's" Omitted Except Share Amounts)
Year Ended September 30, --------------------------------------- 1999 1998 1997 ---- ---- ---- Cash flows from operating activities: Net income ............................................................... $ 8,266 $14,056 $ 26,866 -------- ------- -------- Adjustments to reconcile net income to cash provided by operating activities: Depreciation, depletion and amortization............................... 8,330 9,885 12,250 Amortization of deferred debt issue costs.............................. 343 Deferred income taxes.................................................. 2,765 968 3,983 Gain on sale of assets................................................. (19,667) Unrealized gain on marketable securities............................... (481) Impairment of Penn Octane preferred stock.............................. 423 Changes in assets and liabilities: (Increase) decrease in restricted cash.............................. (157) (116) 1,246 (Increase) in marketable securities................................. (471) (Increase) decrease in accounts receivable.......................... 3,209 (2,513) 4,349 Decrease in notes receivable........................................ 10,000 Decrease in prepaid transportation.................................. 1,123 1,539 338 (Increase) decrease in prepaid expenses and other current assets.... (301) 159 (379) (Increase) decrease in other assets................................. (29) 371 (Increase) decrease in prepaid gas purchases........................ 852 (852) Increase (decrease) in accounts payable............................. (5,740) 3,043 1,798 Increase (decrease) in accrued expenses............................. (861) 406 (3,351) (Decrease) in other current liabilities............................. (2,037) (Decrease) in other long-term liabilities........................... (62) -------- ------- -------- Total adjustments............................................... 9,162 22,019 (818) -------- ------- -------- Net cash flow provided by operating activities.................. 17,428 36,075 26,048 -------- ------- -------- Cash flows from investment activities: Investment in marketable securities....................................... (269) (1,000) Proceeds from sale of oil and gas assets and pipeline..................... 50,184 Realization from (liquidation of) discontinued net refining assets........ 900 (1,425) (1,860) Acquisition of AmBrit oil and gas properties.............................. (20,170) Investment in other oil and gas properties................................ (3,794) (2,212) (1,540) Investment in pipelines................................................... (63) (59) Purchase of furniture, fixtures and equipment............................. (98) (182) (4) Other..................................................................... 42 (359) -------- ------- -------- Net cash provided by (used in) investing activities............. (23,431) (4,840) 46,362 -------- ------- --------
(continued on next page) The accompanying notes are an integral part of these financial statements -30- CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS ("000's" Omitted Except Share Amounts) (continued from previous page)
Year Ended September 30, --------------------------------------- 1999 1998 1997 ---- ---- ---- Cash flows from financing activities: Acquisition of treasury stock ............................................... (6,919) (28,644) (25,163) Dividends paid to shareholders .............................................. (1,681) (2,393) (739) Proceeds of long-term debt................................................... 17,658 Proceeds from exercise of stock options...................................... 255 64 797 Repayment of long-term debt.................................................. (31,664) Payment of debt issuance costs............................................... (418) ------- ------- -------- Net cash (used in) financing activities................................ (8,345) (30,973) (39,529) ------- ------- -------- Net increase (decrease) in cash and cash equivalents............................ (14,348) 262 32,881 Cash and cash equivalents - beginning of period................................. 36,600 36,338 3,457 ------- ------- -------- Cash and cash equivalents - end of period....................................... $22,252 $36,600 $ 36,338 ======= ======= ======== Supplemental disclosures of cash flow information are as follows: Cash paid during the period: Interest.................................................................. $ 2 $ 1,137 ======== ======= ======== Income taxes.............................................................. $ 108 $ 128 $ 863 ======== ======= ======== Supplemental schedule of non-cash investing and financing activities............ Sale of oil and gas assets and pipeline: Prepaid transportation received from purchaser............................ ($ 3,000) ========= Accrued expenses offset against gain...................................... ($ 2,733) ========= Other liabilities assumed by purchaser.................................... $ 1,623 ========= Accrued dividends............................................................ $ 368 $ 707 ======== ========== Conversion of Penn Octane Corporation note to marketable securities.......... $ 1,000 ======== Unrealized gain on investment in available-for-sale marketable securities.... $ 2,396 ========
The accompanying notes are an integral part of these financial statements -31- CASTLE ENERGY CORPORATION CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND OTHER COMPREHENSIVE INCOME ("000's" Omitted Except Share Amounts)
Years Ended September 30, 1999, 1998 and 1997 -------------------------------------------------------------------- Accumulated Additional Other Common Stock Paid-In Comprehensive Comprehensive Shares Amount Capital Income Income ------ ------ ---------- ------------- ------------- Balance - October 1, 1996...... 6,693,646 3,347 $66,316 Stock acquired................. Options exercised.............. 105,000 52 745 Dividends declared ($.30 per share) Net income..................... --------- ----- ------ Balance - September 30, 1997... 6,798,646 3,399 67,061 Stock acquired................. Options exercised.............. 5,000 3 61 Dividends declared ($.45 per share) Net income..................... --------- ----- ------- Balance - September 30, 1998... 6,803,646 3,402 67,122 Stock acquired................. Options exercised.............. 25,000 12 243 Dividends declared ($.75 per share) Comprehensive income........... Net income................... $ 8,266 Other comprehensive income: Unrealized gain on marketable securities, net of tax.. 2,396 $2,396 --------- ------ ------- ------- ------ Balance - September 30, 1999... 6,828,646 $3,414 $67,365 $10,662 $2,396 ========= ====== ======= ======= ======
The accompanying notes are an integral part of these financial statements
Years Ended September 30, 1999, 1998 and 1997 --------------------------------------------- Retained Treasury Stock Earnings --------------------- (Deficit) Shares Amount Total ----------- --------- -------- -------- Balance - October 1, 1996...... ($2,952) $66,711 Stock acquired................. 2,085,100 ($25,163) (25,163) Options exercised.............. 797 Dividends declared ($.30 per share) (1,446) (1,446) Net income..................... 26,866 26,866 ------ --------- -------- -------- Balance - September 30, 1997... 22,468 2,085,100 (25,163) 67,765 Stock acquired................. 1,777,817 (28,644) (28,644) Options exercised.............. 64 Dividends declared ($.45 per share) (1,688) (1,688) Net income..................... 14,056 14,056 ------- --------- -------- -------- Balance - September 30, 1998... 34,836 3,862,917 (53,807) 51,553 Stock acquired................. 419,300 (6,919) (6,919) Options exercised.............. 255 Dividends declared ($.75 per share) (2,048) (2,048) Comprehensive income........... Net income................... 8,266 8,266 Other comprehensive income: Unrealized gain on marketable securities, net of tax.. 2,396 ------- --------- -------- ------- Balance - September 30, 1999... $41,054 4,282,217 ($60,726) $53,503 ======= ========= ======== =======
The accompanying notes are an integral part of these financial statements -32- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) NOTE 1 - BUSINESS AND ORGANIZATION Business Segments 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 percent (20%) of the Company's outstanding common stock at September 30, 1999. The Company's only line of business at September 30, 1999 and at present is oil and gas exploration and production. The Company's operations are conducted in the United States and, to a minor extent, in Romania. Prior to September 30, 1995 several of the Company's subsidiaries or former subsidiaries were involved in the refining business. These subsidiaries discontinued refining operations effective September 30, 1995, however several contingencies related to closure of these refining assets are still outstanding. From December 1992 to May 31, 1999, several of the Company's subsidiaries were involved in the natural gas marketing business and from December 1992 to May 1997, another subsidiary was involved in the gas transmission business. In May 1997, the Company sold its gas transmission pipeline. All of the related long-term gas sales and gas purchase contracts expired by their terms on May 31, 1999. References to the Company mean Castle Energy Corporation, the parent, and its subsidiaries. Such references are used for convenience and are not intended to describe legal relationships. Oil and Gas Exploration and Production In May 1997, the Company sold the Rusk County, Texas oil and gas properties which it acquired from Atlantic Richfield Company ("ARCO") to Union Pacific Resources Company ("UPRC"). The reserves associated with such properties constituted approximately 84% of the Company's proved oil and gas reserves at the time (see Note 4). In June 1999, the Company acquired all of the oil and gas assets of AmBrit Energy Corp. ("AmBrit"). The AmBrit oil and gas assets included interests in approximately 180 wells located in eight states. The proved oil and gas reserves associated with the AmBrit acquisition were estimated to be approximately 12.5 billion cubic feet of natural gas and 2,000 barrels of crude oil or approximately one hundred and fifty percent (150%) of the Company's proved reserves before such acquisition (see Note 4). During fiscal 1999, the Company entered into two drilling agreements with other exploration and production companies to participate in the drilling of approximately sixteen exploratory wells in South Texas. During this period, the Company also entered into an agreement to participate in the drilling of several wildcat wells in Romania over a two to three year period. Finally, in November 1999, the Company entered into an agreement to acquire majority interests in twenty-six wells located in offshore Louisiana. Such interests, if ultimately acquired as expected, will represent the Company's first investment in offshore drilling (see Note 22). 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 May 31, 1999 by their own terms and were not replaced by other third party gas marketing business. The Company has not replaced these contracts because it sold its pipeline assets to a subsidiary of UPRC in May 1997 and because it is unlikely that similar profitable long-term contracts can be negotiated since most gas purchasers buy gas on the spot market. Although the Company is currently seeking additional natural gas marketing operations, it is currently operating exclusively in the exploration and production segment of the energy industry. -33- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) Refining IRLP The Company indirectly entered the refining business in 1989 when one of its subsidiaries acquired the operating assets of an idle refinery located in Lawrenceville, Illinois (the "Indian Refinery"). The Indian Refinery was subsequently operated by one of the Company's subsidiaries, Indian Refining I Limited Partnership ("IRLP"), until September 30, 1995 when it was shut down. On December 12, 1995, IRLP sold the Indian Refinery assets to American Western Refining, L.P. ("American Western"). American Western subsequently filed for bankruptcy and sold the Indian Refinery to an outside party which, we understand, is in the process of dismantling it. Powerine In October 1993, a former subsidiary of the Company purchased Powerine Oil Company ("Powerine"), the owner of a refinery located in Santa Fe Springs, California (the "Powerine Refinery") from MG. On September 29, 1995, Powerine sold substantially all of its refining plant to Kenyen Projects Limited ("Kenyen"). On January 16, 1996, Powerine merged into a subsidiary of Energy Merchant Corp. ("EMC") and EMC, an unaffiliated entity, acquired the refinery from Kenyen. EMC subsequently sold the refinery to an outside party which, we are informed, is seeking financing to restart it. As a result of the transactions with American Western, Kenyen and EMC, the Company's refining subsidiaries disposed of their interests in the refining business. The results of refining operations were shown as discontinued operations in the Consolidated Statement of Operations for the year ended September 30, 1995 and retroactively. Discontinued refining operations have not impacted operations since fiscal 1995. Amounts on the balance sheet reflect the remaining assets and liabilities that are pending final resolution of related contingencies. 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, 1997, 1998 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 significant intercompany transactions have been eliminated in consolidation. Revenue Recognition Natural Gas Marketing Revenues are recorded when deliveries are 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. Fees from well operations are recorded when earned. -34- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and 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 life of the assets. Furniture, fixtures and equipment are depreciated on a straight-line basis over periods of three to ten years and rolling stock is depreciated on a straight-line basis over four to five years, the estimated useful lives of these assets. Oil and Gas Properties The Company follows the full-cost method of accounting for oil and gas properties and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the acquisition, exploration and development of oil and gas reserves are capitalized. Capitalized costs are amortized on a composite unit-of-production method by country using estimates of proved reserves. Capitalized costs which relate to unevaluated oil and gas properties are not amortized until proved reserves are associated with such costs or impairment of the related property occurs. Management and drilling fees earned in connection with the transfer of oil and gas properties to a joint venture and proceeds from the sale of oil and gas properties are recorded as reductions in capitalized costs unless such sales are material and involve a significant change in the relationship between the cost and the value of the remaining proved reserves in which case a gain or loss is recognized. Expenditures for repairs and maintenance of wellhead equipment are expensed as incurred. Net capitalized costs, less related deferred income taxes, in excess of the present value of net future cash inflows (oil and gas sales less production expenses) from proved reserves, tax-effected and discounted at 10% and the cost of properties not being amortized, if any, are charged to current expense. Amortization and excess capitalized costs, if any, are computed separately for the Company's investment in Romania. Environmental Costs The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future expected economic benefit to the Company. -35- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Impairment of Long-Term Assets The Company reviews its long-term assets other than oil and gas properties for impairment whenever events or changes in circumstance indicate 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 is less than the carrying amount of the asset, an impairment loss is 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." 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 Notes 1 and 14). 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 changes in the hedged item. Exploration and Production The Company currently uses hedging strategies to hedge a significant portion of its crude oil and natural gas production. The Company uses futures contracts to hedge such production. Gains and losses from hedging activities are deferred and are debited and credited to the item being hedged, oil and gas sales, when they occur. In order to qualify as a hedge the change in fair market value of the hedging instrument must be highly correlated with the corresponding changes in the hedged item. When the hedging instrument ceases to qualify as a hedge, changes in fair value are charged against or credit 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 The Company operates pursuant to several natural gas sales contracts where one interest owner is entitled to sell other interest owners' shares of natural gas produced if such other owners do not elect to sell their shares of production. Under the terms of the related joint operating agreements, the non-selling owners are entitled to make up gas sales from the selling owner's share of production in the future. The Company records its sales of other owners' production as deferred revenue and recognizes such deferred revenue when the other owners make up their gas balancing deficiency from the Company's share of production. Conversely, the Company records sales of its production by other owners as deferred assets and recognizes such deferred assets when the Company makes up its gas balancing deficiency from the other owners' share of production. Deferred assets and liabilities are recorded at cost at the production date. Comprehensive Income The Company adopted SFAS No. 130, "Reporting Comprehensive Income," effective October 1, 1998. Comprehensive income includes net income and all changes in an enterprise's other comprehensive income including, among other things, foreign currency translation adjustments, and unrealized gains and losses on certain investments in debt and equity securities. -36- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) Stock Based Compensation Effective July 1, 1996, the Company adopted Statement of Financial Accounting Standards No. 123, ("SFAS 123"). SFAS 123 allows an entity to continue to measure compensation costs in accordance with Accounting Principle Board Opinion No. 25 ("APB 25"). The Company has elected to continue to measure compensation cost in accordance with APB 25 and to comply with the required disclosure-only provisions of SFAS 123. Income Taxes The Company follows Statement of Financial Accounting Standards No. 109 ("SFAS 109"), "Accounting for Income Taxes." SFAS 109 is an accounting approach that requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the Company's financial statements or tax returns. In estimating future tax consequences, SFAS 109 generally considers all expected future events other than anticipated enactments of changes in the tax law or tax rates (see Note 18). SFAS 109 also requires that deferred tax assets, if any, be reduced by a valuation reserve based upon whether realization of such deferred tax asset is or is not more likely than not. 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. In February 1997, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 128 ("SFAS 128"), "Earnings Per Share," which established standards for computing and presenting earnings per share ("EPS") for entities with publicly held common stock. SFAS 128 simplified the standards for computing EPS previously found in Accounting Principles Board Opinion No. 15, "Earnings Per Share," and made them comparable to international EPS standards. It replaces the presentation of primary EPS with a presentation of basic EPS, and required dual presentations of basic and diluted EPS on the face of the income statement. SFAS 128 was effective for fiscal years ending after December 15, 1997, and early adoption was not permitted. The Company has adopted SFAS 128 for the fiscal year ended September 30, 1998 and has retroactively restated EPS for fiscal 1997 in accordance with SFAS 128. An analysis of basic and diluted earnings per share for each of the three years ended September 30, 1999 is as follows:
Year Ended September 30, -------------------------------------------- 1999 1998 1997 ---- ---- ---- Weighted shares outstanding at beginning of the year............. 2,940,729 4,713,546 6,693,646 Options exercised................................................ 6,508 3,247 40,512 Stock repurchased................................................ (212,070) (926,693) (970,113) ---------- --------- --------- Basic shares..................................................... 2,735,167 3,790,100 5,764,045 Assumed option exercise.......................................... 47,477 47,803 31,296 --------- --------- --------- Diluted shares................................................... 2,782,644 3,837,903 5,795,341 ========= ========= =========
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. -37- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) New Accounting Pronouncements In June 1997, FASB issued Statement of Financial Accounting Standards No. 130 ("SFAS 130") regarding reporting comprehensive income, which establishes standards for reporting and display of comprehensive income and its components. The components of comprehensive income refer to revenues, expenses, gains and losses that are excluded from net income under current accounting standards, including foreign currency translation items, minimum pension liability adjustments and unrealized gains and losses on certain investments in debt and equity securities. SFAS 130 requires that all items recognized under accounting standards as components of comprehensive income be reported in a financial statement displayed in equal prominence with the other financial statements; the total of other comprehensive income for a period is required to be transferred to a component of equity that is separately displayed in a statement of financial condition at the end of an accounting period. SFAS 130 was effective for both interim and annual periods for companies having fiscal years beginning after December 15, 1997. Reclassification of financial statements for earlier periods provided for comparative purposes was required. The Company adopted SFAS 130, effective October 1, 1998. In June 1997, FASB issued Financial Accounting Standards Board No. 131 ("SFAS 131") regarding disclosures about segments of an enterprise and related information. SFAS 131 established standards for reporting information about operating segments in annual financial statements and required the reporting of selected information about operating segments in interim financial reports issued to stockholders. It also established standards for related disclosures about products and services, geographic areas and major customers. SFAS 131 was effective for companies having fiscal years beginning after December 15, 1997. The Company adopted SFAS No. 131 as of October 1, 1998. The provisions of SFAS 131 have not materially changed the Company's disclosures and reported financial information to the present because the Company presented the required segment information in its consolidated statements of operations for several years before SFAS 131 was effective and continues to do so. Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities ("SFAS 133"), was issued by the Financial Accounting Standards Board in June 1998. SFAS 133 standardizes the accounting for derivative instruments, including certain derivative instruments embedded in other contracts. Under the standard, entities are required to carry all derivative instruments in the statement of financial position at fair value. The accounting for changes in the fair value (i.e., gains or losses) of a derivative instrument depends on whether it has been designated and qualifies as part of a hedging relationship and, if so, 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. SFAS 133 is effective for all fiscal quarters of fiscal years beginning after June 15, 2000. The Company anticipates that it will adopt SFAS 133 effective October 1, 2000. The Company has not yet determined the impact of SFAS 133 on its financial statements or results of operations. -38- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and 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, 1996 to September 30, 1999 is as follows:
Estimated Realizable Value of Discontinued Net Refining Net Refining Assets Liabilities Retained ------------------- -------------------- Balance - October 1, 1996............................................ $6,288 $11,079 Recovery related to the MG SWAP litigation........................... 703 Provision for platinum recovery...................................... (100) Provision for American Western Note.................................. (2,469) Cash transactions.................................................... (1,860) Adjustments to vendor liabilities.................................... (1,722) Other................................................................ (144) ------- ------ Balance - September 30, 1997......................................... 4,422 7,353 Reduction in estimated platinum recovery............................. (364) Excess of MG Note over actual recovery in Powerine Arbitration....... (1,300) Recovery of platinum proceeds........................................ (435) Adjustment of vendor liabilities..................................... (732) Cash transactions.................................................... (192) ------- ------ Balance - September 30, 1998......................................... 3,623 5,129 Reduction in estimated MG SWAP litigation recovery................... (129) (129) Collection of MG SWAP litigation proceeds............................ (575) (575) Additional recovery in connection with the Powerine Arbitration...... 900 Reduction in estimated recoverable value of note receivable from American Western........................................ (2,119) Adjustment of vendor liabilities..................................... (2,119) Other................................................................ (1) ------- ------- Balance - September 30, 1999......................................... $ 800 $ 3,205 ======= =======
As of September 30, 1999, the estimated realizable value of discontinued net refining assets consists of $800 of estimated recoverable proceeds from the American Western note. The estimated value of net refining liabilities retained consist of vendor liabilities of $1,470 and accrued costs related to discontinued refining operations of $2,407, offset by cash of $672. "Estimated realizable value of discontinued net refining assets" is based on the transactions consummated by the Company with American Western and transactions consummated by American Western and IRLP subsequently with others and includes management's best estimates of the amounts expected to be realized on upon the complete disposal of the refining segment. "Net refining liabilities retained" includes management's best estimates of amounts expected to be paid and amounts expected to be realized on the settlement of this net liability. The amounts the Company ultimately realizes or pays could differ materially in the near term from such amounts. See Notes 12 and 13. -39- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) NOTE 4 - ACQUISITIONS AND DISPOSITIONS On May 30, 1997, the Company consummated the sale of its Texas oil and gas properties and pipeline to UPRC and Union Pacific Intrastate Pipeline Company ("UPIPC"), a wholly-owned subsidiary of UPRC, respectively. The effective date of the sale was May 1, 1997. The assets sold included approximately 8,150 net acres, 100 producing oil and gas wells and a 77-mile pipeline which gathered gas from the producing wells and delivered it to a pipeline owned by Lone Star. The proved reserves associated with the oil and gas properties that were sold comprised approximately 84% of the Company's proved reserves at that time. The purchase price received by the Company was $54,759 and consisted of $50,184 cash, $1,575 of the Company's liabilities assumed by UPRC and $3,000 of prepaid gas transportation expense. The gas transportation prepayment related to transportation of natural gas that the Company was required to supply to Lone Star through May 31, 1999. As a result of the sale, the Company realized a gain of $19,667 in fiscal 1997. On June 1, 1999, the Company consummated the purchase of all of the oil and gas properties of AmBrit. The oil and gas properties purchased include interests in approximately 180 oil and gas wells in Alabama, Louisiana, Mississippi, Montana, New Mexico, Oklahoma, Texas and Wyoming, as well as undrilled acreage in several of these states. The effective date of the sale for purposes of determining the purchase price was January 1, 1999. The adjusted purchase price after accounting for all transactions between the effective date, January 1, 1999, and the closing date, May 31, 1999, was $20,170. The entire adjusted purchase price was allocated to "Oil and Gas Properties - Proved Properties". Based upon reserve reports initially prepared by the Company's petroleum reservoir engineers, the proved reserves (unaudited) associated with the AmBrit oil and gas assets approximated 2,000 barrels of crude oil and 12,500 mcf (thousand cubic feet) of natural gas, which, together, approximate 150% of the Company's oil and gas reserves before the acquisition. In addition, the production acquired has increased the Company's consolidated production by approximately 425%. The results of operations on a pro-forma basis as though the oil and gas properties of AmBrit had been acquired as of the beginning of the periods indicated are as follows:
Year Ended September 30, ----------------------------------- 1999 1998 ------------ ------------- (Unaudited) (Unaudited) Revenues.............................................................. $ 63,441 $ 81,993 Net income............................................................ $ 7,958 $ 14,208 Net income per share.................................................. $ 2.86 $ 3.70 Shares outstanding (diluted).......................................... 2,782,644 3,837,903
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 May 1999, the Company entered into a joint operating agreement with another exploration and production company to drill up to twelve exploratory wells in South Texas. The Company's commitment to the joint venture is $5,300 although most of this commitment may be rescinded by the Company if initial drilling results are not as estimated. Subsequent to September 30, 1999, the first exploratory well was drilled and resulted in a dry hole (see Note 22). As of September 30, 1999, the Company's investment in this exploratory program was $928. Such amount is included in "Oil and Gas Properties Unproved Properties Not Being Amortized" in the "Consolidated Balance Sheets". -40- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) In August 1999, the Company entered into another joint operating agreement with a different exploration and production company to drill four exploratory wells in South Texas. The total cost to the Company is expected to approximate $2,200. Investment in Romanian Concessions In April 1999, the Company purchased an option to acquire fifty percent (50%) of three oil and gas concessions granted to a subsidiary of Costilla Energy Corporation ("Costilla"), by the Romanian government. The Company paid Costilla $65 for the option. In May 1999, the Company exercised the option. The Company expects that its minimum obligation for the Romanian concessions will be approximately $3,000. As of September 30, 1999, the Company's investment in Romania was $934. Such amount is included in "Oil and Gas Properties - Unproved Properties Not Being Amortized" in the "Consolidated Balance Sheets". In November 1999, the Company entered into an agreement to acquire majority operating interests in twenty-six (26) wells in offshore Louisiana and additional interests in several wells in Alabama and Pennsylvania (see Note 22). NOTE 5 - RESTRICTED CASH Restricted cash consists of the following:
September 30, --------------------- 1999 1998 ---- ---- Drilling deposits in escrow - Romania............................ $551 Funds supporting letters of credit issued for operating bonds.... 219 $218 Other............................................................ 395 ---- ---- $770 $613 ==== ====
The drilling deposits in escrow in Romania are to be used only to conduct exploratory and drilling activities in Romania and cannot be withdrawn or used for other purposes by the Company. Subsequent to September 30, 1999, the Company incurred $354 of exploration costs, which were paid from the drilling deposit escrow account. NOTE 6 - ACCOUNTS RECEIVABLE Based upon past customer experiences, the limited number of customer accounts receivable relationships, and the fact that the Company's subsidiaries can generally offset unpaid accounts receivable against an outside owner's share of oil and gas revenues, management believes substantially all receivables are collectible. Accounts receivable consist of the following:
September 30, ------------------------ 1999 1998 ---- ---- Natural gas marketing - trade.................................... $6,870 Exploration and production - trade............................... $3,354 1,343 Margin account - hedging......................................... 1,750 Interest......................................................... 68 168 ------ ------ $5,172 $8,381 ====== ======
Accounts receivable due from Lone Star aggregated zero, $6,719 and $3,441 at September 30, 1999, 1998 and 1997, respectively. -41- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) NOTE 7 - MARKETABLE SECURITIES All of the Company's investment in marketable securities consists of common shares of Penn Octane Corp. ("Penn Octane"), a public company involved in sales of liquid propane gas to northern Mexico. At September 30, 1998, the Company accounted for its investment as trading securities. The 766,667 share increase from September 30, 1998 to September 30, 1999 resulted because the Company purchased 200,000 registered Penn Octane common shares on the market and ultimately received 566,667 unregistered common shares in exchange for its $1,000 note after first converting most of the note to Penn Octane preferred stock. In March 1999, the Company began to account for its investment as available-for-sale securities. The Company's investment in Penn Octane common stock was as follows: September 30, -------------------- 1999 1998 ---- ---- Gross cost....................................... $ 1,750 $ 575 Unrealized gain (loss)........................... 2,444 (104) --------- -------- Book value....................................... $ 4,194 $ 471 ========= ======== Shares of Penn Octane common stock owned: Registered................................. 501,000 301,000 Unregistered............................... 566,667 --------- -------- 1,067,667 301,000 ========= ======== The fair market value of Penn Octane shares was based on one hundred percent (100%) of the closing price on September 30, 1999. In addition to the foregoing, the Company owns options to purchase 225,000 common shares of Penn Octane common stock at $1.75 per share and options to purchase 166,667 common shares of Penn Octane common stock at $6.00 per share. The options to purchase 225,000 shares of Penn Octane common stock at $1.75 per share have no book value but have a market value of $492 at September 30, 1999 based upon the closing market price of Penn Octane common stock at September 30, 1999. In November 1999, Penn Octane informed the Company that it was registering the Company's unregistered shares and options. NOTE 8 - FURNITURE, FIXTURES AND EQUIPMENT Furniture, fixtures and equipment are as follows: September 30, --------------------- 1999 1998 ---- ---- Cost: Furniture and fixtures.......... $603 $532 Automobile and trucks........... 106 76 ---- ---- 709 608 Accumulated depreciation.............. (411) (301) ---- ---- $298 $307 ==== ==== -42- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) NOTE 9 - GAS CONTRACTS Gas contracts consisted of the following: September 30, ---------------------- 1999 1998 ---- ---- Gas contracts............................... $61,151 Less: Accumulated amortization.......... (54,866) ------- $ 6,285 ======= NOTE 10 - OIL AND GAS PROPERTIES Oil and gas properties consist of the following:
September 30, ----------------------- 1999 1998 ----- ---- Proved properties........................................... $34,684 $12,367 Less: Accumulated depreciation, depletion and amortization. (9,919) (7,982) ------- ------- 24,765 4,385 Unproved properties......................................... 1,862 215 ------- ------- $26,627 $ 4,600 ======= =======
Capital costs incurred by the Company in oil and gas activities are as follows:
Year Ended September 30, -------------------------------------------------------------- 1999 --------------------------------- United 1998 1997 States Romania Total (U.S.) (U.S.) ------ ------- ----- ------ ------ Acquisition of properties: Proved properties.............................. $21,029 $21,029 $ 17 $ 274 Unproved properties............................ 928 $934 1,862 Exploration....................................... Development....................................... 1,073 1,073 2,195 1,266 ------- ---- ------- ------ ------ $23,030 $934 $23,964 $2,212 $1,540 ======= ==== ======= ====== ======
Until September 30, 1998, all of the Company's capital costs were incurred in the United States. As of September 30, 1999, the Company had incurred $934 in Romania for unproven property acquisition costs. 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, -------------------------------------- 1999 1998 1997 ---- ---- ---- Revenues: Crude oil, condensate, natural gas liquids and natural gas sales.... $6,712 $2,373 $6,740 ------ ------ ------ Costs and expenses: Production costs.................................................... 2,388 775 1,940 Depreciation, depletion and amortization............................ 1,937 367 1,560 ------ ------ ------ Total costs and expenses............................................ 4,325 1,142 3,500 ------ ------ ------ Income tax provision.................................................... 859 443 1,166 ------ ------ ------ Income from oil and gas producing activities............................ $1,528 $ 788 $2,074 ====== ====== ======
-43- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) The income tax provision is computed at a blended rate (Federal and state combined) of 36%. 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, --------------------------------------- 1999 1998 1997 ---- ---- ---- Depletion rate per equivalent MCF of natural gas.......... $0.71 $0.37 $ 0.58 ===== ===== =======
The significant increase in the depletion rate in fiscal 1999 resulted primarily from the acquisition of the oil and gas properties of AmBrit in June 1999. The cost per equivalent mcf of natural gas acquired was approximately $.82 versus a cost of $.37 per equivalent mcf of natural gas applicable to the Company's other oil and gas properties. The significant decrease in the depletion rate in fiscal 1998 resulted from the Company's sale of its oil and gas assets to UPRC in May 1997. After the sale, the cost per cubic foot equivalent of natural gas for the Company's remaining reserves was significantly less than it was before the sale as a result of accounting for the sale to UPRC as a disposition under the full cost method. NOTE 11 - PROVED OIL AND GAS RESERVES AND RESERVE VALUATION (UNAUDITED) Reserve estimates are based upon subjective engineering judgements made by the Company's independent petroleum reservoir engineers, Huntley & Huntley (fiscal 1999, 1998 and 1997) and Ralph E. Davis Associates, Inc. (fiscal 1999) and may be affected by the limitations inherent in such estimations. The process of estimating reserves is subject to continuous revisions as additional information is made available through drilling, testing, reservoir studies and production history. There can be no assurance such estimates will not be materially revised in subsequent periods. Estimated quantities of proved reserves and changes therein, all of which are domestic reserves, are summarized below:
Oil (BBLS) Natural Gas (MCF) ---------- ----------------- Proved developed and undeveloped reserves: As of October 1, 1996.......................... 462 69,629 Revisions of previous estimates............ 59 5,591 Sale of minerals in place.................. (279) (57,074) Production................................. (36) (2,454) ---- ------- As of September 30, 1997....................... 206 15,692 Revisions of previous estimates............ 69 501 Production................................. (20) (869) ------ ------- As of September 30, 1998....................... 255 15,324 Acquisitions............................... 2,021 12,529 Revisions of previous estimates............ (122) 2,520 Production................................. (124) (1,971) ----- ------ As of September 30, 1999....................... 2,030 28,402 ===== ====== Proved developed reserves: September 30, 1996............................. 312 34,764 ====== ====== September 30, 1997............................. 206 11,480 ====== ====== September 30, 1998............................. 162 13,589 ====== ====== September 30, 1999............................. 1,788 23,547 ===== ======
Although the Company has recently invested in a Romanian drilling concession no proved reserves have yet been discovered. As a result, all of the Company's proved oil and gas reserves are located in the United States. -44- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and 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, --------------------------------------- 1999 1998 1997 ---- ---- ---- Future cash inflows................................................ $118,794 $40,576 $46,595 Future production costs............................................ (42,934) (14,141) (13,979) Future development costs........................................... (4,229) (1,283) (2,025) Future income tax expense.......................................... (8,538) (4,868) (7,045) -------- ------- ------- Future net cash flows.............................................. 63,093 20,284 23,546 Discount factor of 10% for estimated timing of future cash flows... (21,849) (10,338) (12,779) -------- ------- ------- Standardized measure of discounted future cash flows............... $ 41,244 $ 9,946 $10,767 ======== ======== =======
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 mineral 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, ---------------------------------------- 1999 1998 1997 ---- ---- ---- Standardized measure, beginning of year............................. $ 9,946 $10,767 $24,494 Sale of oil and gas, net of production costs........................ (4,324) (1,598) (4,800) Net changes in prices............................................... 2,163 (2,498) 1,461 Sale of reserves in place........................................... (17,849) Purchase of reserves in place....................................... 22,215 Changes in estimated future development costs....................... 2,405 (615) (120) Development costs incurred during the period that reduced future development costs................................................ 1,073 2,195 349 Revisions in reserve quantity estimates............................. 1,438 594 4,675 Net changes in income taxes......................................... 745 831 529 Accretion of discount............................................... 995 1,077 2,449 Other, principal changes in timing of production.................... 4,588 (807) (421) ------- ------- ------- Standardized measure, end of year................................... $41,244 $ 9,946 $10,767 ======= ======= =======
NOTE 12 - ENVIRONMENTAL MATTERS In December 1995, IRLP sold the Indian Refinery to American Western. As part of the related purchase and sale agreement, American Western assumed all environmental liabilities and indemnified the Company with respect thereto. Subsequently American Western filed for bankruptcy and sold the Indian Refinery to an outside party pursuant to a bankruptcy proceeding. The new owner is currently dismantling the Indian Refinery. During fiscal 1998, the Company was also informed that the United States Environmental Protection Agency ("EPA") has investigated offsite acid sludge waste found near the Indian Refinery and was also investigating and remediating surface contamination in the Indian Refinery property. Neither the Company nor IRLP was named with respect to these two actions. In October 1998, the EPA named the Company and two of its refining subsidiaries as potentially responsible parties for the expected clean-up of the Indian Refinery. In addition, eighteen other parties were named including Texaco Refining and Marketing, Inc., 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. -45- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) In November 1999, the Company received a request for information from the EPA concerning the Company's involvement in the ownership and operation of the Indian Refinery. The Company expects that it will respond to the EPA information request during the second quarter of fiscal 2000. In September 1995, Powerine sold the Powerine Refinery to Kenyen. In January 1996, Powerine merged into a subsidiary of EMC and EMC assumed all environmental liabilities. In August 1998, EMC sold the Powerine Refinery to a third party which is seeking financing to restart the Powerine Refinery. In July of 1996, the Company was named a defendant in a class action lawsuit concerning emissions from the Powerine Refinery. In April of 1997, the court granted the Company's motion to quash the plaintiff's summons based upon lack of jurisdiction and the Company is no longer involved in the case. Although the environmental liabilities related to the Indian Refinery and Powerine Refinery have been transferred to others, there can be no assurance that the parties assuming such liabilities will be able to pay them. American Western, owner of the Indian Refinery, filed for bankruptcy and is in the process of liquidation. EMC, which assumed the environmental liabilities of Powerine, sold the Powerine Refinery to an unrelated party, which we understand is still seeking financing to restart that refinery. Furthermore, as noted above, the EPA named the Company as a potentially responsible party for remediation of the Indian Refinery and has requested relevant information from the Company. Estimated gross clean up costs for this refinery are $80,000 - $150,000 according to third parties. If the Company were found liable for the remediation of the Indian Refinery, it could be required to pay a percentage of the clean-up costs. Since the Company's subsidiary only operated the Indian Refinery five years whereas Texaco and others operated it over fifty years, the Company would expect that its share of any remediation liability, if any, would be proportional to its years of operation although such may not be the case. An opinion issued by the U.S. Supreme Court in June 1998 in a comparable matter supports the Company's position. Nevertheless, if funds for environmental clean-up are not provided by these former and/or present owners, it is possible that the Company and/or one of its former refining subsidiaries could be named a party in additional legal actions to recover remediation costs. In recent years, government and other plaintiffs have often sought redress for environmental liabilities from the party most capable of payment without regard to responsibility or fault. Whether or not the Company is ultimately held liable in such a circumstance, should litigation involving the Company and/or IRLP occur, the Company would probably incur substantial legal fees and experience a diversion of management resources from other operations. Although the Company does not believe it is liable for any of its subsidiaries' clean-up costs and intends to vigorously defend itself in such regard, the Company cannot predict the ultimate outcome of these matters due to inherent uncertainties. 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, 1999:
Lease Sublease Year Ending September 30, Commitments Rentals - ------------------------- ----------- --------- 2000........................................................ $ 328 $ 63 2001........................................................ 295 64 2002........................................................ 247 65 2003........................................................ 208 66 2004........................................................ 39 ----- ---- 1,117 $258 ===== ====
Rent expense for the years ended September 30, 1999, 1998 and 1997 was $386, $245 and $200, respectively. -46- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) Severance/Retention Obligations The Company and one of its subsidiaries have severance agreements with substantially all of their employees that provide for severance compensation in the event substantially all of the Company's or the subsidiary's assets are sold and the employees are terminated as a result of such sale. Such termination severance commitments aggregated approximate $861 at September 30, 1999. No severance obligations are outstanding at September 30, 1999. Letters of Credit At September 30, 1999, the Company had issued letters of credit of $219 for oil and gas drilling, operating and plugging bonds. The letters of credit are renewed semi-annually or annually. Legal Proceedings Contingent Environmental Liabilities See Note 12. General Powerine Arbitration In June 1997, an arbitrator ruled in the Company's favor in an arbitration hearing concerning a contract dispute between MGNG and Powerine which had been assigned to the Company. In October 1997, the Company recovered $8,700 from the arbitration and sought an additional $2,142 plus interest. In January 1999, the Company recovered $900 in connection with the $2,142 sought. Rex Nichols et al Lawsuit In March of 1998, the Company, one of its subsidiaries and one of its officers were sued by two outside interest owners owning interests in several wells formerly operated by one of the Company's exploration and production subsidiaries until May 1997. The lawsuit was filed in the Fourth Judicial District at Rusk County, Texas. The lawsuit, as initially filed, sought unspecified net production revenues resulting from reversionary interests on several wells operated by the subsidiary. Management believes the Company's exposure on the matter, if any, is less than $50. Subsequently the plaintiffs expanded their petition claiming amounts due in excess of $250 based upon their interpretation of other provisions in the underlying oil and gas leases. The case is currently in discovery and no date has been set for a trial. Management believes that the plaintiffs additional claims are without merit and intends to vigorously defend its position. SWAP Agreement - MGR&M In January 1998, IRLP filed suit against MG Refining and Marketing, Inc. ("MGR&M"), a subsidiary of MG, to collect $704 plus interest. The dispute concerned funds owed to IRLP but not paid by MGR&M. In February 1998, MG contended that the $704 was not owed to IRLP and that it had liquidated MGR&M. In April 1999, IRLP recovered $575 of the $704 sought. The difference between the book value, $704, and the actual recovery, $575, was recorded as a reduction in the value of discontinued net refining assets since the recovery relates to IRLP's discontinued refining operations (See Note 3). Powerine/EMC/Litigation In July 1998, the Company sued Powerine and EMC to recover $330 plus interest. The amount sought represented amounts that Powerine or EMC were required to pay to the Company under the January 1996 purchase and sale agreement -47- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) whereby Powerine merged into a subsidiary of EMC. In April 1999, the Company recovered $355 from EMC. The recovery was recorded as other income. Larry Long Litigation In May 1996, Larry Long, representing himself and allegedly "others similarly situated," filed suit against the Company, three of the Company's natural gas marketing and transmission and exploration and production subsidiaries, Atlantic Richfield Company ("ARCO"), B&A Pipeline Company, a former subsidiary of ARCO ("B&A"), and MGNG in the Fourth Judicial District Court of Rusk County, Texas. The plaintiff originally claimed, among other things, that the defendants underpaid non-operating working interest owners, royalty interest owners, and overriding royalty interest owners with respect to gas sold to Lone Star pursuant to the Lone Star Contract. Although no amount of actual damages was specified in the plaintiff's initial pleadings, it appeared that, based upon the volumes of gas sold to Lone Star, the plaintiff may have been seeking actual damages in excess of $40 million. 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 have apparently now 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. No hearing has been held on the plaintiffs' request for class certification. After a lengthy period of inactivity the plaintiff's counsel has only recently sought to continue or settle the case. At present no class has been certified and no trial date set. Based upon the revised pleadings, management of the Company initially determined that the possible exposure of the Company and its subsidiary limited partnerships for all gas sold to Lone Star in the past and in the future, were they to lose the case on all points, was less than $3,000. However, the Company sold all of its Rusk County oil and gas properties to UPRC in May of 1997. The sale to UPRC effectively removed any possibility of exposure by the Company or its subsidiary limited partnerships to claims for additional royalties with respect to future production, thus reducing the exposure of the Company and its subsidiaries to less than $2,000 in actual damages if they were to lose the case on all points. Although the Company believes that the plaintiff's claims are without merit and intends to continue to vigorously defend itself in this matter, the Company cannot predict the ultimate outcome. MGNG Litigation On May 4, 1998, Production 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 seeks to recover gas measurement and transportation expenses charged by the defendants in breach of a certain gas purchase contract. Improper charges exceed $750 before interest. In October of 1998, MGNG and MGC filed a suit in Harris County, Texas. This suit seeks indemnification from two of the Company's subsidiaries in the event the Company's subsidiary wins its lawsuit against MGNG and MGC. The MG entities have 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 Company is pursuing this case using all legal remedies. The parties participated in mediation but were not able to resolve the issue. The case is expected to be scheduled for trail in May 2000. UPRC, to whom the Company sold its Rusk County, Texas oil and gas properties, has also informed the Company that it intends to sue MGNG on the same transportation expense issue. On October 1999, MGNG filed a second lawsuit against the Company and three of its subsidiaries claiming $772 was owed to MGNG under a gas supply contract between one of the Company's subsidiaries and MGNG. The suit was filed in the district court of Harris County, Texas. The Company and its subsidiaries believe that they do not owe $772 and are entitled to legally offset some or all of the $772 claimed against amounts owed to Production by MGNG for improper gas measurement and transportation deductions. The Castle entities have answered this suit denying MGNG's claims based partially on the right of offset. -48- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) GAMXX On February 27, 1998, the Company entered into an agreement with Alexander Allen, Inc. ("AA") concerning amounts owed to the Company by AA and its subsidiary, GAMXX Energy, Inc. ("GAMXX"). The Company had made loans to GAMXX through 1991 in the aggregate amount of approximately $8,000. When GAMXX was unable to obtain financing, the Company recorded a one hundred percent loss provision on its loans to GAMXX in 1991 and 1992 while still retaining its lender's lien against GAMXX. Pursuant to the terms of the GAMXX Agreement, the Company is to receive $1,000 cash in settlement for its loans when GAMXX closes on its financing. GAMXX expected such closing not later than May 31, 1998 but such closing has not yet occurred. The Company has carried its loans to GAMXX at zero the last six years. The Company will record the $1,000 proceeds as "other income" if and when it collects such amount. There can be no assurance that GAMXX will close on its financing. Hedging Activities Until June 1, 1999, the Company's natural gas marketing subsidiary utilized natural gas swaps to reduce its exposure to changes in the market price of natural gas. Effective May 31, 1999 all natural gas marketing contracts terminated by their own terms. As a result of these hedging transactions, the cost of gas purchases increased $609 and $410 for the years ended September 30, 1999 and 1998, respectively, and decreased $624 for the year ended September 30, 1997. As of September 30, 1999, the subsidiary had no natural gas purchase hedging contracts outstanding. On June 1, 1999, the Company acquired all of the oil and gas assets of AmBrit (see Note 4) and thereafter commenced hedging sales of the related oil and gas production. As of September 30, 1999, the Company had hedged approximately 54% of its anticipated consolidated crude oil production and approximately 39% of its anticipated consolidated natural gas production for the period from October 1, 1999 to September 30, 2000. In addition, at September 30, 1999, the Company had hedged approximately 14% of its anticipated natural gas production for the fiscal year ended September 30, 2001. The Company has 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, are $19.85 per barrel of crude oil and $2.66 per mcf of gas. The Company anticipates that these futures contracts will be accounted for as hedges and that differences between the hedged price and the exchange price will increase or decrease the oil and gas revenues resulting from the sale of production by the Company. Oil and gas production was not hedged through July 1999 production. As a result of these hedging transactions, oil and gas sales decreased $149 for the year ended September 30, 1999. The volumes of oil and gas production hedged and the notional dollar amounts of the related hedging contracts were as follows:
Fair September 30, 1999 Value ----------------------------------------------------- Amount Dollars Volumes ------ ------- --------------------------------------- Future contracts to sell natural gas........... (530) $5,568 2,100,000 MMbtu (British Thermal Units) Futures contracts to sell crude oil............ (60) 3,933 198,000 Barrels ------ ------ ($590) $9,501 ====== ======
At September 30, 1999, the market value of these hedges was an unrealized loss of $590. At September 30, 1999, the Company had a $1,750 hedging margin escrow deposit with the broker (see Note 6). To the extent that the future oil and gas sales prices increase above their levels at September 30, 1999, the Company could be obligated to increase its hedging margin escrow deposits. -49- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) Line of Credit In February 1999, the Company received a $30,000 line of credit from an energy bank. The line of credit expires in February 2001. The amount that can be borrowed by the Company will be limited to a borrowing base which is to be determined annually by the energy bank. The interest rate to be paid by the Company will depend upon the amount borrowed and the collateral provided but is not expected to exceed the prime rate. In exchange for receiving the line of credit, the Company paid a syndication fee of $40 and must pay an additional fee of 1/2% of each borrowing under the facility. The Company has not yet used the line of credit. 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, 1999, 1998 and 1997, the Company's contributions to the Plan aggregated $37, $23 and $38, respectively. Post Retirement Benefits Neither the Company nor its subsidiaries provide any other post retirement plans for employees. NOTE 15 - STOCKHOLDERS' EQUITY From November 1996 until September 30, 1999, the Company's Board of Directors authorized the Company to purchase up to 4,750,000 of its outstanding shares of common stock on the open market. As of September 30, 1999, 4,282,217 shares had been repurchased at a cost of $60,726. The repurchased shares are held in treasury. Subsequent to September 30, 1999, the Company purchased an additional 203,800 shares at a cost of $3,466 (see Note 22). On June 30, 1997, the Company's Board of Directors approved a dividend policy of $.60 per share per year, payable quarterly. The dividend policy remains in effect until rescinded or changed by the Board of Directors. Quarterly dividends of $.15 per share have subsequently been paid. NOTE 16 - STOCK OPTIONS AND WARRANTS Option and warrant activities during each of the three years ended September 30, 1999 are as follows (in whole units):
Non- Incentive Incentive Qualified Plan Other Options Options Options Options Total --------- --------- --------- ------- -------- Outstanding - October 1, 1996............. 2,500 77,500 288,000 20,000 388,000 Issued.................................... 57,000 20,000 77,000 Exercised................................. (2,500) (67,500) (35,000) (105,000) Cancelled................................. (10,000) (10,000) Expired................................... (147,500) (15,000) (162,500) ----- ------- -------- ------- -------- Outstanding at September 30, 1997......... 162,500 25,000 187,500 Issued.................................... 55,000 55,000 Exercised................................. (5,000) (5,000) Repurchased............................... (17,500) (5,000) (22,500) Expired................................... ----- ------- -------- ------- -------- Outstanding at September 30, 1998......... 195,000 20,000 215,000
-50- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts)
Non- Incentive Incentive Qualified Plan Other Options Options Options Options Total --------- --------- --------- ------- ------- Issued.................................... 15,000 15,000 Exercised................................. (25,000) (25,000) Repurchased............................... (10,000) (10,000) Expired................................... --------- --------- -------- ------- ------- Outstanding at September 30, 1999......... 175,000 20,000 195,000 ========= ========= ======== ======= ======= Exercisable at September 30, 1999......... 175,000 20,000 195,000 ======= ======= ======= Reserved at September 30, 1999............ 562,500 20,000 582,500 ======= ======= ======= Reserved at September 30, 1998............ 562,500 20,000 582,500 ========= ========= ======== ======= ======= Reserved at September 30, 1997............ 562,500 25,000 587,500 ========= ========= ======== ======= ======= Exercise prices at: September 30, 1999................ $10.25- $11.375 $17.25 September 30, 1998................ N/A N/A $10.25- $10.75- $17.25 $11.375 September 30, 1997................ N/A N/A $ 8.44- $11.00- $14.25 $11.375 Exercise Termination Dates........ N/A N/A 5/17/2003- 4/23/2007 5/17/2003- 1/03/2009 1/03/2009
In fiscal 1993, the Company adopted the 1992 Executive Equity Incentive Plan (the "Incentive Plan"). The purpose of the Incentive Plan is to increase the ownership of common stock of the Company by those non-union key employees (including officers and directors who are officers) and outside directors who contribute to the continued growth, development and financial success of the Company and its subsidiaries, and to attract and retain key employees and reward them for the Company's profitable performance. The Incentive Plan provides that an aggregate of 562,500 shares 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 5,000 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. -51- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) A summary of the Company's stock option and warrant activity from October 1, 1996 to September 30, 1999 is as follows:
Weighted Average Options Price --------- -------- Balance outstanding - October 1, 1996...................... 388,000 $10.59 Issued..................................................... 77,000 10.78 Exercised.................................................. (105,000) 7.60 Cancelled.................................................. (10,000) 8.00 Expired.................................................... (162,500) 11.50 ------- ------ Outstanding - September 30, 1997........................... 187,500 11.69 Issued..................................................... 55,000 16.23 Exercised.................................................. (5,000) 12.65 Repurchased................................................ (22,500) 10.43 Expired.................................................... ------- ------ Outstanding - September 30, 1998........................... 215,000 12.96 Issued..................................................... 15,000 17.25 Exercised.................................................. (25,000) (10.25) Repurchased................................................ (10,000) 10.75 Expired.................................................... ------- ------ Outstanding - September 30, 1999........................... 195,000 $13.75 ======= ======
At September 30, 1999 exercise prices for outstanding options ranged from $10.25 to $17.25. The weighted average remaining contractual life of such options was 6.7 years. The per share weighted average fair values of stock options issued during fiscal 1999 , fiscal 1998 and fiscal 1997 were $4.56, $3.92 and $2.84, respectively, on the dates of issuance using the Black-Scholes option pricing model with the following weighted average assumptions: expected dividend yield - 3.5% in 1999, 3.6% in 1998 and 4.3% in 1997; risk free interest rate - 6.32% in 1999, 5.03% in 1998 and 5.81% in 1997; expected life of 10 years in 1999, 1998 and 1997 and volatility factor of .22 in 1999, .24 in 1998 and .30 in 1997. 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. Pro-forma 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, ------------------------------------------ 1999 1998 1997 ---- ---- ---- Net income as reported............................................... $8,266 $14,056 $26,866 Adjustment required by FAS 123....................................... (152) (132) (214) ------ ------- ------- Pro-forma net income................................................. $8,114 $13,924 $26,652 ====== ======= ======= Pro-forma net income per share: Basic............................................................. $ 2.97 $ 3.67 $ 4.62 ====== ======= ======= Diluted........................................................... $ 2.92 $ 3.63 $ 4.60 ====== ======= =======
-52- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) NOTE 17 - INCOME TAXES Provisions for (benefit of) income taxes consist of:
September 30, ------------------------------------------ 1999 1998 1997 ---- ---- ---- Provision for (benefit of) income taxes: Current: Federal....................................................... $ 193 $ 223 $ 862 State......................................................... (2) 13 37 Deferred: Federal....................................................... 2,209 1,653 13,506 State......................................................... 68 47 362 Adjustment to the valuation allowance for deferred taxes: Federal....................................................... 475 (712) (9,824) State......................................................... 13 (20) (280) ------ ------ -------- $2,956 $1,204 $ 4,663 ====== ====== ========
Deferred tax assets (liabilities) are comprised of the following at September 30, 1999 and 1998:
September 30, ---------------------- 1999 1998 ---- ---- Operating losses and tax credit carryforwards....................................... $3,775 $5,781 Depletion accounting................................................................ (1,044) (890) Amortization (gas contracts)........................................................ 439 Discontinued net refining operations................................................ 866 543 ------ ------ 3,597 5,873 Valuation allowance................................................................. (3,597) (3,108) ------ ------ - $2,765 ====== ====== Deferred tax assets - current....................................................... $2,765 Deferred tax assets - non-current................................................... ------ ------ $2,765 ====== ======
In 1999, the Company increased its valuation allowance by $489 to $3,597 because all of the taxable income expected from the Lone Star Contract, upon which the net deferred tax asset was previously based, had been received by September 30, 1999 and utilization of the Company's net operating losses was not anticipated given the Company's large exploratory and wildcat drilling commitments, the expiration of the Lone Star Contract, contingent environmental liabilities and other factors. In fiscal 1998, the Company reduced its valuation reserve by $732 to $3,108 based upon the decreased probability of additional losses related to discontinued refining operations. In fiscal 1997, the Company reduced its valuation reserve by $10,104 to $3,840 in anticipation of future taxable income from the Lone Star Contract. The Company has not recorded a net deferred tax asset at September 30, 1999 because realization of such net deferred tax asset is not more likely than not given the expiration of the Lone Star Contract, oil/gas price risk, operational risks, drilling risks and reserve risks. -53- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) The income tax provision (benefit) differs from the amount computed by applying the statutory federal income tax rate to income (loss) before income taxes as follows:
Year Ended September 30, ------------------------------------ 1999 1998 1997 ---- ---- ---- Tax at statutory rate.................................................... $3,928 $5,341 $11,035 State taxes, net of federal benefit...................................... 51 26 315 Reversal of tax estimates and contingencies.............................. (151) (3,463) Statutory depletion and tax credits...................................... (1,330) 4,312 Increase (decrease) in valuation allowance............................... 489 (732) (10,104) Other.................................................................... (31) 32 (895) ------ ------ -------- $2,956 $1,204 $ 4,663 ====== ====== ========
At September 30, 1999, the Company had the following tax carryforwards available:
Federal Tax ---------------------------------- Alternative Minimum Regular Tax ------- ----------- Net operating loss...................................................... $1,396 $22,620 Alternative minimum tax credits......................................... $3,273 N/A Statutory depletion..................................................... $9,992 - Investment tax credit................................................... $ 28 N/A
The net operating loss and investment tax credit carryforwards expire from 2000 through 2008. 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 became subject to an annual limitation of $7,845. Such annual limitation, however, was increased by the amount of net built-in gain at the time of the change of ownership. Such net built-in gain aggregated $219,430. During the fiscal years ended September 30, 1999, 1998 and 1997 the Company used $4,367, $10,295 and $45,499, respectively, of its net operating loss carryforwards, including $37,278 of built-in gains. The Company also has approximately $50,000 in individual state tax loss carryforwards available at September 30, 1999. Such carryforwards are primarily available to offset taxable income apportioned to certain states in which the Company has no operations and currently has no plans for future operations. As a result it is probable most of such state tax carryforwards will expire unused. NOTE 18 - RELATED PARTIES Sale of Subsidiaries On March 31, 1993, the Company entered into an agreement to sell to Terrapin Resources, Inc. ("Terrapin") its oil and gas partnership management businesses for $1,100 ($800 note bearing interest at 8% per annum and $300 cash) which approximated book value. The closing of the stock purchase transaction occurred on June 30, 1993. Terrapin is wholly-owned by an officer and director of the Company. In December 1994, the note was repaid. In conjunction with the sale of its partnership management business, the Company and one of its exploration and production subsidiaries entered into two management agreements with Terrapin to manage its exploration and production operations. The second agreement was amended in 1996 to include corporate accounting functions. -54- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts) In June 1997, the Company purchased, for $692, one of the Terrapin management agreements in conjunction with the sale of the Company's Rusk County, Texas oil and gas properties to UPRC. The remaining contract with Terrapin was month to month. In September 1997, Terrapin granted the Company an option to acquire its accounting software and computer equipment. The option price was one dollar plus assumption of Terrapin's office and equipment rentals and employee obligations. Effective June 30, 1998, the Company exercised the option and hired most of Terrapin's employees. Management fees incurred to Terrapin for the years ended September 30, 1999, 1998 and 1997 aggregated zero, $292 and $561, respectively. In June 1999, the Company repurchased 24,700 shares of the Company's common stock from the officer. Such shares were repurchased at the closing stock price on the date of sale less $.125, resulting in a payment of $434 to the officer. The shares were repurchased pursuant to the Company's share repurchase program. 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.
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
Year Ended September 30, 1998 ---------------------------------------------------------------------------------------- Natural Gas Oil & Gas Eliminations Marketing Exploration and and and Refining Corporate Transmission Production (Discontinued) Items Consolidated ------------ ----------- -------------- ------------ ------------ Revenues........................... $70,001 $ 2,603 $72,604 Operating income (loss)............ $15,700 $ 413 ($ 3,081) $13,032 Identifiable assets................ $62,424 $49,724 ($45,144) $67,004 Capital expenditures............... $ 2,457 $ 2,457 Depreciation, depletion and amortization.................... $ 9,462 $ 423 $ 9,885
-55- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts)
Year Ended September 30, 1997 ---------------------------------------------------------------------------------------- Natural Gas Oil & Gas Eliminations Marketing Exploration and and and Refining Corporate Transmission Production (Discontinued) Items Consolidated ------------ ----------- -------------- ------------ ------------ Revenues........................... $68,029 $ 7,113 ($3,423) $71,719 Operating income (loss)............ $12,415 $ 2,425 ($3,370) $11,470 Identifiable assets................ $41,667 $48,666 ($7,616) $82,717 Capital expenditures............... $ 59 $ 1,544 $ 1,603 Depreciation, depletion and amortization.................... $10,639 $ 1,611 $12,250
For the years ended September 30, 1999, 1998 and 1997, sales by the Company's natural gas marketing subsidiary to Lone Star Gas Company under the Lone Star Contract aggregated $46,802, $64,619 and $59,695, respectively. These amounts constituted approximately 82%, 89% and 83%, respectively, of consolidated revenues for the years ended September 30, 1999, 1998 and 1997, respectively. The Lone Star contract terminated in May 1999. At the present time, the Company's consolidated revenues consist primarily of oil and gas sales. Approximately three purchasers of the Company's oil and gas production, each of which accounts for over 10% of the Company's consolidated reserves, currently account for approximately 60% of consolidated revenues and are expected to comprise a similar percentage of oil and gas sales for fiscal 2000. NOTE 20 - DISCLOSURES ABOUT FAIR VALUE OF FINANCIAL INSTRUMENTS Cash and Cash Equivalents -- Cash and cash equivalent, the carrying amount is a reasonable estimate of fair value. Marketable securities are related solely to the Company's investment in Penn Octane common stock and are recorded at fair market value. Market value is computed to equal the closing share price at year end times the number of shares held by the Company. Hedges -- At September 30, 1999, the Company had hedged approximately 198 barrels of crude oil and 2,100 MMbtu of gas that it expects to produce before December 31, 2000. The book value of such hedges is zero and the fair market value of the hedges based upon their market value was an unrealized loss of $590 at September 30, 1999 (See Note 13). 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 - QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
First Second Third Fourth Quarter Quarter Quarter Quarter (December 31) (March 31) (June 30) (September 30) ------------- ---------- --------- -------------- Fiscal 1999: Revenues................................... $20,936 $22,365 $9,668 $4,288 Operating income before interest and income taxes............................ $ 3,455 $ 4,825 $ 145 $ 744 Net income................................. $ 2,511 $ 3,938 $ 900 $ 917 Net income per share (diluted)............. $ .84 $ 1.37 $ .34 $ .35
-56- Castle Energy Corporation Notes to Consolidated Financial Statements ("000's" Omitted Except Share and Per Share Amounts)
First Second Third Fourth Quarter Quarter Quarter Quarter (December 31) (March 31) (June 30) (September 30) ------------- ---------- --------- -------------- Fiscal 1998: Revenues................................. $20,979 $18,504 $17,464 $15,657 Operating income before interest and income taxes.......................... $ 3,752 $ 3,369 $ 3,525 $ 2,386 Net income............................... $ 2,822 $ 2,542 $ 6,864 $ 1,828 Net income per share (diluted)........... $ .60 $ .61 $ 2.02 $ .60
The sums of the quarterly per share amounts for fiscal 1999 ($2.90) and fiscal 1998 ($3.83) differ from the annual per share amounts of $2.97 in fiscal 1999 and $3.66 in fiscal 1998 primarily because the stock purchases made by the Company were not made in equal amounts and at corresponding times each quarter. NOTE 22 - SUBSEQUENT EVENTS Subsequent to September 30, 1999, the Company repurchased an additional 203,800 shares of its common stock at a cost of $3,466. Subsequent to September 30, 1999, CECI acquired additional outside interests in several Alabama wells which it operates for $372. In addition, the Company entered into three agreements to acquire additional oil and gas interests in operated wells in Alabama and Pennsylvania and to acquire majority interests in twenty-six (26) offshore Louisiana wells. The adjusted purchase price for these acquisitions, assuming closings as planned, is expected to approximate $3,075 and will be financed from working capital. Subsequent to September 30, 1999, the first well drilled in one of the Company's South Texas drilling ventures resulted in a dry hole. The Company is planning to participate in the drilling of at least two additional wells. -57- Independent Auditors' Report The Board of Directors Castle Energy Corporation: We have audited the accompanying consolidated balance sheets of Castle Energy Corporation and subsidiaries as of September 30, 1999 and 1998, 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, 1999. 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 generally accepted auditing standards. 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, 1999 and 1998, and the results of their operations and their cash flows for each of the years in the three year period ended September 30, 1999 in conformity with generally accepted accounting principles. KPMG LLP Houston, Texas December 14, 1999 -58- PART III ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE** None ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT** ITEM 11. EXECUTIVE COMPENSATION** ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT** ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS** - -------------- ** The information required by Item 10, 11, 12 and 13 is incorporated by reference to the Registrant's Proxy Statement for its 2000 Annual Meeting of Stockholders. -59- 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) 10.120 Option Agreement dated July 10, 1997 between Terrapin Resources, Inc. and Castle Energy Corporation(19) 10.121 Closing Agreement, dated May 30, 1997 by and among Castle Energy Corporation, Castle Texas Production L.P., Union Pacific Resources Company and Castle Exploration Company, Inc. (25) 10.122 Purchase and Sale Agreement by and among Castle Energy Corporation and Castle Texas Pipeline L.P. and Union Pacific Intrastate Pipeline Company, dated May 16, 1997 (20) 10.123 Purchase and Sale Agreement by and among Castle Energy Corporation and Castle Texas Production L.P. and Union Pacific Resources Company dated May 16, 1997 (20) 10.124 Asset Purchase Agreement dated February 27, 1998 by and between Castle Energy Corporation and Alexander Allen, Inc. (21) 10.125 Rollover and Assignment Agreement, dated December 1, 1998 between Penn Octane Corporation and Certain Lenders, including Castle Energy Corporation (22) 10.126 Purchase and Sale Agreement by and between AmBrit Energy Corp. and Castle Exploration Company, Inc., effective January 1, 1999 (23) 10.127 Agreement to Exchange $.9 Million Secured Notes Into Senior Preferred Stock of Penn Octane Corporation dated March 3, 1999 (23) 10.128 Credit Agreement by and among Castle Exploration Company, Inc. and Comerica Bank-Texas, effective May 28, 1999 (24) 10.129 Purchase and Sale Agreement by and between Costilla Redeco Energy LLC and Castle Exploration Company, Inc., effective May 31, 1999 (24) 10.130 Letter dated July 22, 1999 between Penn Octane Corporation and Castle Energy Corporation 10.131 Letter dated July 29, 1999 between Penn Octane Corporation and Castle Energy Corporation 10.132 Castle Energy Corporation Severance Benefit Plan 11.1 Statement re: Computation of Earnings Per Share 21 List of subsidiaries of Registrant -60- Exhibit Number Description of Document -------------- ----------------------- 23.2 Consent of Ralph E. Davis Associates, Inc. 23.3 Consent of Huntley & Huntley, Inc. 23.4 Consent of KPMG LLP 27 Financial Data Schedule (b) Reports on Form 8-K The Company filed one report on Form 8-K during the last quarter of the Company's fiscal year ended September 30, 1999. That report is dated June 15, 1999. The report concerned the acquisition of AmBrit's oil and gas properties. A subsequent amendment to this report, dated August 11, 1999, containing proforma financial statements, was subsequently filed. - ------------------ (8) Incorporated by reference to the Registrant's Form S-1 (Registration Statement), dated September 29, 1993 (10) Incorporated by reference to the Registrant's Form 10-Q for the second quarter ended March 31, 1994 (15) Incorporated by reference to the Registrant's Form 10-K for the fiscal year ended September 30, 1994 (19) Incorporated by reference to the Registrant's Form 10-K for the fiscal year ended September 30, 1997. (20) Incorporated by reference to the Registrant's Form 8-K dated May 30, 1997 (21) Incorporated by reference to the Registrant's Form 10-Q for quarter ended March 31, 1998 (22) Incorporated by reference to the Registrant's Form 10-Q for quarter ended December 31, 1998 (23) Incorporated by reference to the Registrant's Form 10-Q for quarter ended March 31, 1999 (24) Incorporated by reference to the Registrant's Form 10-Q for quarter ended June 30, 1999 (25) Incorporated by reference to the Registrant's Form 10-K for the fiscal year ended September 30, 1998 -61- SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. CASTLE ENERGY CORPORATION Date: December 6, 1999 By:/s/JOSEPH L. CASTLE II ----------------------------------- Joseph L. Castle II Chairman of the Board and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant in the capacities and on the dates indicated.
/s/JOSEPH L. CASTLE II - --------------------------- Chairman of the Board and Chief December 6, 1999 Joseph L. Castle II Executive Officer Director /s/MARTIN R. HOFFMANN - --------------------------- Director December 6, 1999 Martin R. Hoffmann /s/JOHN P. KELLER - ---------------------------- Director December 6, 1999 John P. Keller /s/RICHARD E. STAEDTLER - ---------------------------- Senior Vice President December 6, 1999 Richard E. Staedtler Chief Financial Officer Chief Accounting Officer Director /s/SIDNEY F. WENTZ - --------------------------- Director December 6, 1999 Sidney F. Wentz
-62- DIRECTORS AND OFFICERS BOARD OF DIRECTORS (November 30, 1999) JOSEPH L. CASTLE II RICHARD E. STAEDTLER Chairman & Chief Executive Officer Chief Financial Officer and Chief Accounting Officer MARTIN R. HOFFMANN SIDNEY F. WENTZ Of Counsel to Washington, D.C. Former Chairman of The Robert Wood Office of Skadden, Arps, Slate, Johnson Foundation Meagher & Flom JOHN P. KELLER President, Keller Group, Inc. OPERATING OFFICERS JOSEPH L. CASTLE II RICHARD E. STAEDTLER Chief Executive Officer Chief Financial Officer Chief Accounting Officer TIMOTHY M. MURIN President - Exploration and Production PRINCIPAL OFFICES One Radnor Corporate Center 531 Plymouth Road, Suite 525 Suite 250 Plymouth Meeting, PA 19462 100 Matsonford Road Radnor, PA 19087 12731 Power Plant Road 61 McMurray Road, Suite 204 Tuscaloosa, AL 35406 Pittsburgh, PA 15241-1633 P.O. Box 425 Acme, PA 15610-0425 PROFESSIONALS Counsel Independent Reservoir Engineers Duane, Morris & Heckscher LLP Huntley & Huntley, Inc. One Liberty Place, 42nd Floor Corporate One II, Suite 100 Philadelphia, PA 19103-7396 4075 Monroeville Blvd. Monroeville, PA 15146 Independent Accountants Ralph E. Davis Associates, Inc. 3555 Timmons Lane, Suite 1105 KPMG LLP Houston, Texas 77027 700 Louisiana Houston, Texas 77002 Registrar and Transfer Agent American Stock Transfer & Trust Company 40 Wall Street, 46th Floor New York, New York 10005 EX-10.130 2 EXHIBIT 10.130 POCC Exhibit 10.130 Penn Octane Corporation - -------------------------------------------------------------------------------- July 22, 1999 Mr. Joseph Castle President Castle Energy Corporation One Radnor Corporate Center, Suite 250 100 Matsonford Road Radnor, PA 19087 Via Facsimile - ------------- Dear Joe: This letter will confirm Castle Energy Corporation's ("CEC") decision to convert $100,000 of the principal amount of note receivable due June 30, 1999, from Penn Octane Corporation into new shares of common stock of Penn Octane Corporation. The conversion rate shall be one (1) share for each $1.50 of principal amount of indebtedness (total of 66,667 shares). The anticipated date of closing is July 29, 1999. Any interest accrued and unpaid as of July 29, 1999 shall be paid on July 29, 1999. Please acknowledge your agreement with the above by signing below and returning a faxed copy to 562 929-1921. Regards, /s/IAN T. BOTHWELL ------------------ Ian T. Bothwell Accepted and Agreed to this 26th day of July, 1999 By:/s/Joseph Castle ------------- Name: Castle cc: J.B. Richter R. Staedtler EX-10.131 3 EXHIBIT 10.131 POCC Exhibit 10.131 Penn Octane Corporation - -------------------------------------------------------------------------------- July 29, 1999 Mr. Joseph Castle President Castle Energy Corporation One Radnor Corporate Center, Suite 250 100 Matsonford Road Radnor, PA 10987 Via Facsimile - ------------- Dear Joe: This letter will confirm that the issues surrounding the Certificate of Designation, Powers, Preferences and Rights of the Series B Convertible Redeemable Preferred Stock (the "Preferred Stock"), including those regarding anti-dilution, arising in connection with the $900,000 preferred stock transaction between Castle Energy Corporation and Penn Octane Corporation in March 1999, have been resolved between parties based on the following changes: 1. The conversion rate of the Preferred Stock will be increased from 4 shares of common stock of Penn Octane Corporation for each share of Preferred Stock to 5 shares of common stock of Penn Octane Corporation for each share of Preferred Stock (subject to adjustment as more fully described in the Certificate of Designation), and 2. The annual dividend rate on the Preferred Stock will be reduced to $1.00 per share from $1.20 per share. Based on the above, we will modify the latest draft Certificate of Designation for these changes and immediately file the Certificate with the State of Delaware. Please acknowledge your agreement with the above by signing below and returning a faxed copy to 562 929-1921. Regards, /s/ IAN T. BOTHWELL ------------------- Ian T. Bothwell Accepted and Agreed to this 30th day of July, 1999 By: /s/ Joseph Castle ----------------- Name: Jos. L. Castle EX-10.132 4 EXHIBIT 10.132 Exhibit 10.132 CASTLE ENERGY CORPORATION SEVERANCE BENEFIT PLAN CASTLE ENERGY CORPORATION SEVERANCE BENEFIT PLAN This Castle Energy Corporation Severance Benefit Plan is designed to provide severance benefits to a select group of management employees of Castle Exploration Company, Inc. and its affiliates in the event their employment is involuntarily terminated without cause. Article 1: Definitions As used herein the following terms have the meanings set forth in this Article 1, unless a different meaning is plainly required by the context. 1.1 "Board" means the Board of Directors of the Company. 1.2 "Cause" means conduct detrimental to the Employer and its employees, including: 1.2.1 fraud, embezzlement, misappropriation or other criminal conduct; 1.2.2 neglect of duties or responsibilities as an employee; 1.2.3 falsification of Employer records or reports; 1.2.4 deliberate or reckless action which causes actual or potential injury or loss to the Employer or its employees; 1.2.5 material violation of Employer policies or rules; or 1.2.6 illegal acts on Employer property or in representing the Employer. 1.3 "Compensation" means the cash compensation, including bonuses, paid to an Eligible Employee for his services to the Employer. "Compensation" shall be determined before reduction for any employee contributions to savings or health benefit plans maintained by the Employer. 1.4 "Compensation Committee" means the Compensation Committee of the Board. 1.5 "Company" means Castle Energy Corporation, a Delaware corporation. 1.6 "Eligible Employee" means an individual designated by the Compensation Committee as eligible to participate in this Plan and whose name appears in Exhibit A. 1.7 "Employer" means the Company, Castle Exploration Company, Inc., and any of its affiliates. For purposes of Sections 1.3, 2.1 and 4.3, Employer means 1 all of these entities; for purposes of Section 1.2 and 3.4, Employer means any of them; and for purposes of Section 3.1, it means only those that have actually employed the Eligible Employee. 1.8 "Plan" means the Castle Energy Corporation Severance Benefit Plan set forth in this document, as it may be amended from time to time. 1.9 "Plan Year" means each calendar year that the Plan is in effect. 1.10 "Severance Benefit" means the benefit payable under Article 3. 1.11 "Severance Date" means the date selected by the Employer on which an Eligible Employee's employment termination becomes effective. 1.12 "Termination Event" means (i) a reduction of at least 30% in the Eligible Employee's then current Compensation from the Employer; or (ii) the permanent assignment of the Eligible Employee to an office that is situated beyond a radius of 50 miles from the office to which the Eligible Employee is currently assigned. Article 2: Eligibility for Severance Benefits 2.1 An Eligible Employee whose employment with the Employer has been involuntarily terminated shall be entitled to receive a Severance Benefit, provided: 2.1.1 his employment is not terminated for Cause; 2.1.2 he does not voluntarily resign before his Severance Date; 2.1.3 he executes and returns to the Company a written general release, in form and substance satisfactory to the Company, of any and all claims against the Employer and all related parties with respect to all matters arising out of his employment by the Employer or his employment termination; and 2.1.4 he agrees to perform up to 125 hours of post-severance service for the Employer as described in Section 3.4. 2.2 For purposes of Section 2.1, an Eligible Employee's employment with the Employer shall be considered to have been involuntarily terminated if the Eligible Employee resigns within 45 days after a Termination Event occurs. Article 3: Payment of Severance Benefits 3.1 Amount and Form of Benefits. Except as otherwise provided in Section 3.3, an Eligible Employee who satisfies the requirements of Section 2.1 and 3.4 shall receive from his Employer a Severance Benefit in an amount equal 2 to his Compensation for the twelve month period ending on his Severance Date. The Severance Benefit shall be paid in seven unequal monthly installments: the first installment shall equal 50% of the Severance Benefit, each of the next five installments shall equal 8.33% thereof and the last installment shall equal the remaining 8.35%. 3.2 Timing of Payments. Payment of an Eligible Employee's Severance Benefit shall commence as soon as administratively feasible following his Severance Date and the Company's receipt of the executed written release required by Section 2.1.3, but in no case more than one month after the release is executed. 3.3 Termination of Payments. An Eligible Employee shall cease to participate in the Plan and any remaining Severance Benefit payments shall cease upon discovery of Cause, whether or not such discovery occurs before the Eligible Employee's Severance Date. 3.4 Post Severance Services of Eligible Employees. During the period over which the Severance Benefit is paid and as a condition of continuing to receive those payments, the Eligible Employee shall assist the Employer by performing up to 125 hours of service on matters with which the Eligible Employee had been involved while an active employee, if requested by the Employer. The scheduling of this work shall be done by the Employer after taking into account the Eligible Employee's personal schedule and work requirements. If the Employer requires more than 125 hours of service from an Eligible Employee, the Employer shall pay the Eligible Employee the reasonable hourly rate agreed upon by the parties for each hour in excess of 125. The Employer may request all or a portion of the 125 hours as soon as it has paid the first installment pursuant to Section 3.1. Article 4: General Provisions 4.1 Plan Administration. The Plan shall be administered by the Company, which shall be the Plan's "named fiduciary" and "administrator" as those terms are used in the Employee Retirement Income Security Act of 1974, as amended. As administrator, the Company shall have the power to interpret and construe any ambiguous or disputable provisions of the Plan and to decide related questions that may arise in connection with the operation of the Plan, including the determination of disputed facts and application of Plan provisions to unanticipated circumstances. The Company may consult with an attorney, accountant, actuary or other experts and rely upon their opinions as it deems necessary and proper. The decision, determination or action of the Company with respect to any questions arising out of or in connection with the administration, operation and interpretation of the Plan shall be conclusive and binding upon all persons having or claiming an interest in the Plan. 4.2 Funding of the Plan. This Plan shall be unfunded, and the payment of benefits hereunder shall be made from the general assets of the Company. 3 4.3 Right to Amend or Terminate Plan. The Board may amend the Plan from time to time or terminate the Plan at any time; provided, however, that no amendment or termination shall reduce the benefits to which an Eligible Employee is entitled hereunder during the four year period beginning on the date that the Eligible Employee is so designated by the Board. 4.4 Benefit Claims Procedures. In the event a claim by a terminated Eligible Employee relating to the amount of his benefit or its method of payment is denied, such person will be given written notice by the Company of such denial, which notice will set forth the reason for the denial. The terminated Eligible Employee may, within 60 days after receiving the notice, request a review of such denial by filing a notice in writing with the Company. The Company in its discretion may request a meeting with the terminated Eligible Employee to clarify any matters it deems pertinent. The Company will render a written decision within 60 days after receipt of such request stating the reasons for its decision. If the Company is unable to respond within 60 days, an additional 60 days may be taken by the Company to respond. The terminated Eligible Employee will be notified if this additional time is necessary by the end of the initial 60-day period. 4.5 Nonalienation of Severance Benefits. No Eligible Employee shall have the right to alienate, anticipate, pledge, assign or in any way create a lien upon any benefit payable hereunder, and no benefit shall be assignable in anticipation of payment either by voluntary or involuntary acts, or by operation of law. 4.6 No Right to Employment. Nothing herein shall be deemed to give any Eligible Employee the right to be retained in the service of the Employer or to interfere with the rights of the Employer to discharge any Eligible Employee at any time. 4.7 Exclusive Severance Benefit. This Plan supersedes and is in lieu of any other severance arrangements that an Eligible Employee has with the Employer. 4.8 Payment Due Persons Under Disability. If the Company determines that any person to whom a payment is due hereunder is unable to care for his affairs by reason of physical or mental incapacity, the Company shall have the power to direct that the benefit payment due to such person be made to another for his benefit without any responsibility to see to the application of such payment. Any payment so made shall, as to the amount of such payment, operate as a complete discharge of the Company therefor. 4.9 Records, Reporting and Disclosure. The Company shall keep all records necessary for the proper operation of the Plan. Such records shall be made available to each Eligible Employee for examination during business hours except that an Eligible Employee shall examine only such records as pertain exclusively to such examining Eligible Employee and to the Plan text. The Company shall prepare and shall file as required by law or regulation all reports, forms, documents and other items required by the Employee Retirement Income Security Act of 1974, as amended, the Internal Revenue Code of 1986, as amended, and each other relevant statute, including without limitation those 4 relating to withholding of income taxes, Social Security taxes and other amounts which may be similarly reportable. 4.10 Lost Payees. A Severance Benefit shall be deemed forfeited if the Company, after reasonable efforts, is unable to locate a terminated Eligible Employee to whom a Severance Benefit is due. Such Severance Benefit shall be reinstated if application is made therefor by the terminated Eligible Employee while this Plan is in operation but in no event more than one year after the Severance Benefit first becomes due and payable. 4.11 Expenses. All expenses of administering the Plan shall be paid by the Employer. 4.12 Gender. Whenever used herein, unless the context otherwise indicates, words in the masculine form shall be deemed to refer to females as well as males. 4.13 Titles and Headings. The titles of Articles and headings of Sections in this Plan are for convenience of reference only and in case of any conflict the text of the Plan, rather than such titles and headings, shall control. 4.14 Governing Law. This Plan shall be construed and enforced according to the internal laws of the Commonwealth of Pennsylvania, to the extent not preempted by federal law. IN WITNESS WHEREOF, and as evidence of its adoption of this Plan, the Company, on behalf of itself and the other adopting Employer, has caused the same to be executed by its duly authorized officers and its corporate seal to be affixed hereto as of August 19, 1999. Attest: CASTLE ENERGY CORPORATION /s/SUSAN PYLE By: /s/JOSEPH L. CASTLE - ---------------------- ---------------------- Secretary President 5 Exhibit A Eligible Employees under the Castle Energy Corporation Severance Benefit Plan Richard E. Staedtler Timothy M. Murin Susan Pyle Mary Cade 6 EX-11.1 5 EXHIBIT 11.1 Exhibit 11.1 1 of 2 Castle Energy Corporation Statement of Computation of Earnings Per Share (Dollars in thousands, except per share amounts) (Unaudited)
Three Months Ended September 30, ---------------------------------------------------------------------- 1999 1998 --------------------------------- ----------------------------- Basic Diluted Basic Diluted ---------- ---------- ---------- ---------- I. Weighted Shares Outstanding, Net of Treasury Stock Outstanding - Beginning of Period: Stock, net 2,591,329 2,591,329 3,014,029 3,014,029 Purchase of treasury stock (weighted) (16,594) (16,594) (42,148) (42,148) ---------- ---------- ---------- ---------- 2,574,735 2,574,735 2,971,881 2,971,881 II. Weighted Equivalent Shares: Options and warrants assumed exercised 40,922 56,661 ---------- ---------- ---------- ---------- III. Weighted Average Shares and Equivalent Shares 2,574,735 2,615,657 2,971,881 3,028,542 ========== ========== ========== ========== IV. Net Income $ 917 $ 917 $ 1,828 $ 1,828 ========== ========== =========== ========== V. Net Income Per Share $ .36 $ .35 $ .62 $ .60 ========== ========== ========== ==========
Exhibit 11.1 2 of 2 Castle Energy Corporation Statement of Computation of Earnings Per Share (Dollars in thousands, except per share amounts) (Unaudited)
Twelve Months Ended September 30, ------------------------------------------------------------------------ 1999 1998 --------------------------------- --------------------------------- Basic Diluted Basic Diluted ---------- ---------- ---------- ---------- I. Weighted Shares Outstanding, Net of Treasury Stock Outstanding - Beginning of Period: 2,940,729 2,940,729 4,713,546 4,713,546 Options and warrants exercised 6,508 6,508 3,247 3,247 Stock repurchased (212,070) (212,070) (926,693) (926,693) II. Weighted Equivalent Shares: Options and warrants assumed exercised 47,477 47,803 ---------- ---------- ---------- ---------- III. Weighted Average Shares and Equivalent Shares 2,735,167 2,782,644 3,790,100 3,837,903 ========== ========== ========== ========== IV. Net Income $ 8,266 $ 8,266 $ 14,056 $ 14,056 ========== ========== ========== ========== V. Net Income Per Share (Diluted) $ 3.02 $ 2.97 $ 3.71 $ 3.66 ========== ========== ========== ==========
EX-21 6 EXHIBIT 21 Exhibit 21 CASTLE ENERGY CORPORATION Listing of Parent and Subsidiaries As of November 22, 1999
Relationship Company's to Ownership Entity Company Business Percentage - -------------------------------------- ------------ ---------------------------------- ---------- Parent Castle Energy Corporation Parent Holding Company N/A Refining Indian Oil Company Subsidiary Inactive 100% Indian Refining I. L.P. Subsidiary- Inactive 100% Limited Partnership Indian Refining & Marketing I. Inc. Subsidiary General Partner of IRLP - Inactive 100% Natural Gas Marketing Castle Pipeline Company Subsidiary General Partner - Pipeline 100% Partnership - Inactive Castle Texas Pipeline L.P. Subsidiary Natural Gas Transmission - Inactive 100% Limited Partnership CEC Marketing Company Subsidiary General Partner - Gas Marketing 100% Partnership - Inactive CEC Marketing Resources Company Subsidiary Limited Partner - Gas Marketing 100% Partnership - Inactive CEC Gas Marketing L.P. Subsidiary- Gas Marketing - Inactive 100% Limited Partnership Exploration and Production Castle Production Company Subsidiary General Partner - Production 100% Partnership - Inactive Castle Production Resources Company Subsidiary Limited Partner - Production 100% Partnership - Inactive Castle Texas Production L.P. Subsidiary- Oil and Gas Production - Inactive 100% Limited Partnership Castle Exploration Company, Inc. Subsidiary Oil and gas development, drilling 100% and well operations - United States Redeco Petroleum Company Limited Subsidiary Oil and gas development, drilling 100% and well operations - Romania Passive Investment CEC, Inc. Subsidiary Passive Activities 100%
EX-23.2 7 EXHIBIT 23.2 Exhibit 23.2 RALPH E. DAVIS ASSOCIATES, INC. CONSULTANTS - PETROLEUM AND NATURAL GAS 3555 TIMMONS LANE, SUITE 1105 HOUSTON, TEXAS 77027 (713) 626-8955 CONSENT OF INDEPENDENT PETROLEUM ENGINEERS We hereby consent to the use of our name and the reference to our reports dated October 22, 1999 in the Form 10-K of Castle Energy Corporation for the year ended September 30, 1999. RALPH E. DAVIS ASSOCIATES, INC. /s/ALLEN C. BARRON ------------------------------- Allen C. Barron, P.E. Vice President Houston, Texas December 3, 1999 EX-23.3 8 EXHIBIT 23.3 Exhibit 23.3 HUNTLEY & HUNTLEY, INC. GEOLOGISTS AND ENGINEERS L.G. HUNTLEY 1912-1970 ESTABLISHED 1912 340 MANSFIELD AVENUE J.R. WYLIE, JR. 1927-1974 PITTSBURGH, PA 15220 R.S. STEWART 1948-1988 ---- T. BARTHOLOMEW, II AREA CODE 412 1988-1994 920-0800 Fax Number (412)380-4003 Mr. Richard E. Staedtler Chief Financial Officer Castle Energy Corporation One Radnor Corporate Center, Suite 250 Radnor, PA 19087 Dear Mr. Staedtler: We hereby consent to the use of our name and reference to our report dated October 21, 1998 in the Form 10-K of Castle Energy Corporation for the year ended September 30, 1998. Sincerely, By:/s/KEITH N. MANGINI ----------------------------- President December 3, 1999 EX-23.4 9 EXHIBIT 23.4 Exhibit 23.4 INDEPENDENT AUDITORS' CONSENT The Board of Directors Castle Energy Corporation: We consent to incorporation by reference in the registration statement (No. 33-88760) on Form S-8 of Castle Energy Corporation of our report dated December 14, 1999, relating to the consolidated balance sheets of Castle Energy Corporation and subsidiaries as of September 30, 1999 and 1998, 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, 1999, which report appears in the September 30, 1999, annual report on Form 10- K of Castle Energy Corporation. KPMG LLP Houston, Texas December 21, 1999 EX-27 10 FINANCIAL DATA SCHEDULE
5 This schedule contains summary financial data extracted from the Company's consolidated financial statements for the fiscal year ended September 30, 1999 included in Item 8 Financial Statements and financial statement schedules and is qualified in its entirety by reference to such financial statements. YEAR SEP-30-1999 SEP-30-1999 22,252,000 3,761,000 5,172,000 0 0 33,349,000 37,315,000 10,330,000 60,363,000 7,285,000 0 0 0 3,414,000 49,664,000 60,363,000 57,257,000 57,257,000 31,052,000 48,088,000 0 0 0 11,222,000 2,956,000 8,266,000 0 0 0 8,266,000 3.02 2.97
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