-----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, GEOEo8sfOctnXEL//kjUpSCCckPrA6HYYO/Hzs+MKTIOet9tW1uv2N7eLAr70PyN lugdUsGGrb6suFnBMkp6ew== 0000899243-97-000290.txt : 19970226 0000899243-97-000290.hdr.sgml : 19970226 ACCESSION NUMBER: 0000899243-97-000290 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19941231 FILED AS OF DATE: 19970225 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: TGX CORP CENTRAL INDEX KEY: 0000319650 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 720890264 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K/A SEC ACT: 1934 Act SEC FILE NUMBER: 000-10201 FILM NUMBER: 97542945 BUSINESS ADDRESS: STREET 1: 222 PENNBRIGHT STE 200 CITY: HOUSTON STATE: TX ZIP: 77090 BUSINESS PHONE: 7138720500 MAIL ADDRESS: STREET 1: 222 PENNBRIGHT STREET 2: STE 200 CITY: HOUSTON STATE: TX ZIP: 77090 FORMER COMPANY: FORMER CONFORMED NAME: TEMPLETON ENERGY INC DATE OF NAME CHANGE: 19870708 10-K/A 1 FORM 10-K/A UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K/A [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (FEE REQUIRED) For the fiscal year ended December 31, 1994 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED) For the transition period from ____________________ to ____________________ Commission file number 0-10201 TGX CORPORATION (Exact name of registrant as specified in its charter) Delaware 72-0890264 (State or other jurisdiction (I.R.S. Employer- of incorporation or organization) Identification No.) 222 Pennbright, Suite 200 Houston, Texas 77090 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (281) 872-0500 SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Name of each Exchange Title of each class on which registered ------------------- --------------------- Common Stock, $.01 par value Not Applicable Series A Senior Preferred Stock, $1 par value Not Applicable 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/A or any amendment to this Form 10-K/A: [X] APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PRECEDING FIVE YEARS: Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes [X] No [ ] The aggregate market value of the voting stock held by non-affiliates as of March 28, 1995 was approximately $25,314. As of March 28, 1995 there were 25,313,533 shares of Common Stock outstanding. DOCUMENTS INCORPORATED BY REFERENCE None INDEX ----- ITEM PAGE NUMBER - ---- ----------- PART I. ITEM 1. BUSINESS ................................................ 1 ITEM 2. PROPERTIES .............................................. 14 ITEM 3. LEGAL PROCEEDINGS ....................................... 14 ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS ............................................... 15 PART II. ITEM 5. MARKET FOR THE REGISTRANT'S SECURITIES AND RELATED STOCKHOLDERS MATTERS .......................... 16 ITEM 6. SELECTED FINANCIAL DATA ................................. 17 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ......... 18 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ............. 26 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE ................... 49 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ..... 50 ITEM 11. EXECUTIVE COMPENSATION ................................. 52 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT ....................................... 53 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ......... 55 PART IV. ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K .................................. 57 SIGNATURES ............................................. 60 PART I. ITEM I. BUSINESS THE COMPANY General TGX Corporation ("TGX"), formerly named Templeton Energy, Inc., is a Delaware corporation that was organized in June 1980. TGX's executive offices are at 222 Pennbright, Suite 200, Houston, Texas 77090 (telephone number 281/872-0500). TGX (collectively with its subsidiaries, the "Company") is a domestic independent energy company engaged in the production of oil and natural gas and, to a lesser degree, in oil and natural gas exploration for its direct account and, previously, beneficially through general and limited partnerships which were sold to public and private investors. The Company is also engaged in intrastate natural gas gathering and treating. TGX commenced operations on July 1, 1981 as the result of the consummation of an offer in which shares of its common stock $.01 par value, ("Common Stock"), were issued in exchange for certain interests in developed and undeveloped oil and natural gas properties held by various affiliated and unaffiliated entities. On December 5, 1985, TGX acquired Amarex, Inc.("Amarex") (renamed Temex Energy, Inc. ("Temex")), an oil and gas exploration company operating primarily through general and limited partnerships (the "Amarex Partnerships"), in exchange for the payment of approximately $52,000,000 in cash and the issuance of 11,475,000 shares of Common Stock to former creditors of Amarex. On August 8, 1988, Temex was merged with and into TGX. Since this acquisition, TGX, as successor in interest to Temex, has acted as general partner of the Amarex Partnerships. From November 1986 through August 1991, TGX, through its then wholly owned subsidiary LEDCO, Inc. ("LEDCO"), was also engaged in natural gas marketing and, to a limited degree, providing natural gas transportation services to producers, local distribution companies and industrial end-users. On February 22, 1990, TGX filed a voluntary petition in the United States Bankruptcy Court for the Western District of Louisiana (the "Bankruptcy Court") for reorganization (the "Reorganization Proceeding") pursuant to Chapter 11 ("Chapter 11") of Title 11 of the United States Bankruptcy Code (the "Bankruptcy Code"). Effective August 31, 1991, TGX sold LEDCO to Ledco Acquisition Company, Inc., a company wholly owned by Steinhardt Partners, L.P., a Delaware limited partnership ("Steinhardt"), and related entities for $2.9 million and the assignment to TGX by Steinhardt of $2.145 million principal amount of claims related to TGX's Senior Subordinated Fixed Rate Notes ("Senior Subordinated Notes"). On January 7, 1992, an Amended Plan of Reorganization (the "Plan") was confirmed by the Bankruptcy Court and the Plan became effective on January 21, 1992 (the "Effective Date"). On October 2, 1992, the Bankruptcy Court's order of substantial consummation regarding the Plan became final and non-appealable. For further information concerning the Plan, see "Reorganization Proceeding" below. Business Strategy After substantial consummation of the Plan, and in order to maximize stockholder value, the Company embarked on a strategy of eliminating non-core assets, reducing overhead, restructuring its debt and, possibly, capital structure, and enhancing its productive assets. During 1993 and 1994, a substantial portion of management's efforts were utilized in implementing the components of a business plan to effect this strategy. 1 In early 1993, the Company relocated and consolidated its offices in Houston, Texas, thereby reducing expenses and began a program of down-sizing and possibly out-sourcing certain financial and administrative services. Following the office consolidation, the Company retained an investment banker to conduct an extensive review of the Company's operations and assets to determine the most appropriate means for implementing management's strategy. The Company's efforts also involved the restructuring and replacing of its secured long-term debt with the Bank of Montreal ("BMO"), the renegotiation of its debt with certain persons holding notes arising from administrative claims incurred during the Reorganization Proceeding, and the program to liquidate and dissolve substantially all public and private oil and gas drilling and production purchase programs for which the Company acted as a general partner. The Company also implemented a program of selling assets which were either non-core to the Company's strategy or which could provide a significant immediate cash infusion to relieve debt obligations and long term benefit by reducing overhead. As a result of these strategies, in 1994, the Company completed the sale of substantially all of its oil and gas properties in Ohio and New York to Belden & Blake Corporation ("BBC") for approximately $16.2 million, restructured its bank indebtedness as set forth under "Bank Indebtedness," liquidated 17 oil and gas partnerships and began the process of dissolving and winding up an additional eight partnerships which will be completed in 1995, and sold approximately 31 partnership properties for $1,424,000 which management believed were non-core to the Company's strategy. During 1994, the Company was able to reduce its number of employees from 27 to 13, excluding contract personnel, and its general and administrative expenses from $3,323,000 to $2,239,000. In addition to the on-going oil and gas production operations, a key factor in the Company's future will be the final resolution of the long-standing litigation (the "NFG Litigation") with National Fuel Gas Distribution Corporation ("NFG"). While the Company has attempted to commence settlement negotiations with NFG, to date no meaningful discussions have taken place. If a settlement cannot be reached, the Company is committed to prosecuting the NFG Litigation with every reasonable resource available to it. The outcome of the NFG Litigation, which may be many years away if a settlement cannot be reached, could materially affect the Company's future. See "Bank Indebtedness" and "NFG Litigation." In 1995, the Company will be looking to further reduce its overhead, eliminate non-core assets, and maximize the return on the assets it retains. It will also review its current capital structure to determine if a restructuring would better reflect the Company's financial position. At the same time, the Company will review growth opportunities consistent with its available capital, to determine if asset enhancement can be obtained either through drilling or acquisition. However, given the Company's current financial position and the inability to predict (i) whether or not any capital restructure will be effective; (ii) the outcome of the NFG Litigation; and (iii) the success of any cost reductions, the Company cannot currently determine if it will be able to successfully implement its business plan and strategy. Bank Indebtedness Prior to the Reorganization Proceeding, BMO was TGX's principal secured lender. At the time of the Chapter 11 filing, TGX owed $29.7 million to BMO (the "Existing BMO Debt") which was secured by substantially all of TGX's assets. TGX also guaranteed to BMO certain of the debt of a then wholly owned subsidiary. Pursuant to the Plan, TGX entered into an Amended and Restated Credit Agreement (the "Amended Credit Agreement") under which the Existing BMO Debt was continued and preserved, but was evidenced by new loans ("New BMO Loans"), in the original aggregate principal amount of approximately $27 million which continued to be secured by substantially all of TGX's assets and TGX also entered into a revolving credit agreement for working capital or the issuance of letters of credit in the maximum amount of $1,000,000. The guaranty of the debt of the subsidiary was also eliminated. In early 1993, the Company was notified that Events of Default had occurred under the Amended Credit Agreement. During 1993, the Company did not cure the Events of Default and, as a result, BMO had the right to take certain actions under the Amended Credit Agreement, including, but not limited to, the acceleration of all of the New BMO Loans. 2 In January 1994, in conjunction with the Company's sale of certain assets to BBC, as described under "Proved Oil and Natural Gas Reserves - Sale of New York and Ohio Properties", the Company made a debt service payment of approximately $14.3 million to BMO and entered into a limited forbearance agreement, pursuant to which, TGX was required to make a payment (the "Required Payment") of $18 million plus accrued interest and fees less (i) the $14.3 million paid to BMO and (ii) any amounts paid to BMO subsequent to January 1, 1994, that were applied toward the Required Payment. On July 13,1994, TGX entered into a series of agreements with BMO and Bank One, Texas, N.A. ("Bank One") whereby the New BMO Loans were restructured and all BMO Events of Default resolved. Pursuant to the restructuring, Bank One established a borrowing-based facility of $2,350,000 under which TGX immediately borrowed $1,600,000 of which $1,452,000 was paid to BMO in satisfaction of the remaining amount due of the Required Payment. The Bank One facility bears interest at Bank One's stated rate plus 2% and is secured by substantially all of TGX's oil and gas properties. The loan is repayable in 36 months through monthly principal reductions and the borrowing base is redetermined at a minimum of every six months or at Bank One's discretion. The Bank One facility requires the maintenance of certain financial ratios including a working capital ratio of 1.2 to 1 and a tangible net worth of a minimum of $5,000,000 and other ratios. The Company was in compliance with all financial ratios and covenants at December 31, 1994, but can give no assurance that it will be able to continually meet the Bank One ratios. Simultaneously with the securance of the Bank One facility and payment of the Required Payment, BMO released all of its liens on TGX's properties with the exception of its lien on the NFG Litigation. As part of the loan restructuring, BMO converted $4,652,000 (the "BMOF Principal") of the New BMO Loans, including fees and expenses, to a non-recourse note secured only by the NFG Litigation and any proceeds that might be received therefrom. BMO subsequently assigned its rights to the loan, security and TGX note, to BMO's wholly owned subsidiary, BMO Financial, Inc. ("BMOF"). Pursuant to agreement, after repayment of the BMOF Principal, including interest, from NFG Litigation proceeds, if any, BMOF will, in certain instances, after TGX has received a sum equal to the amount paid to BMOF, be entitled to receive up to fifty percent interest in certain additional litigation proceeds. If NFG Litigation proceeds are insufficient to repay the BMOF Principal, plus applicable interest, TGX will have no further obligation for such repayment. The BMOF note matures on December 31, 1997, subject to each party having the right to extend the maturity date, and bears interest at the rate of 10% per annum. However, until December 31, 1997, and for such further time as BMOF elects to extend the maturity date of such note, no cash payment for such interest is required; instead TGX will pay interest in kind through the issuance of additional notes to BMOF. As of December 31, 1994 total accrued interest pursuant to the BMOF note was $218,000, resulting in a total year-end BMOF note balance of $4,870,000. See Notes 3 and 15 of the Notes to Consolidated Financial Statements. Administrative Claims During the Reorganization Proceeding, TGX incurred, and claimants filed applications for, approximately $7,131,000 in administrative fees and expenses relating to the reorganization ("Administrative Claims"). TGX objected to certain of the Administrative Claims and negotiated settlement amounts and terms of payment with certain holders of Administrative Claims. As a result, each of these administrative claimants, other than three designated administrative claimants whose administrative claims were satisfied in a different manner, were entitled to receive a promissory note (the "Administrative Notes") due December 31, 1994, in satisfaction of each claimant's unpaid Administrative Claim. Such Administrative Notes were to be issued upon the execution of releases in favor of the Company and others. Substantially all persons entitled to Administrative Notes executed such releases. See "Reorganization Proceeding-Overview of the Plan." The Administrative Notes bore interest at a rate not to exceed 8% and were secured with certain collateral (the "Consummation Collateral"). If the proceeds related to the Consummation Collateral were not sufficient to satisfy the Company's obligations under the Administrative Notes, the Company's excess operating funds, if any, would be applied toward the balances due. During 1994 and early 1995, the Company renegotiated the terms of substantially all of the Administrative Notes. As a result, Administrative Notes totaling approximately $990,000 in principal and $230,000 in accrued interest charges were renegotiated with the Company making cash payments of $389,000, issuing 141,518 shares of the Company's Series A Senior Preferred Stock (the "Senior Preferred") and a $90,000 principal amount of non-recourse note payable out of TGX's share of proceeds, if any, to be received from the NFG 3 Litigation. As a result of the Administrative Note renegotiations the Company reflected an extraordinary net gain of $831,000. Efforts to settle the remaining outstanding notes on a discounted basis continue. NFG Litigation Since November 30, 1984, TGX has been involved in litigation in the United States District Court for the Western District of New York ("New York Federal Court") (Civ. No. 84-1372-E) with NFG concerning the validity of a contract (the "Contract") pursuant to which TGX (as successor-in-interest to Paragon Resources, Inc. ("Paragon"), the original contracting party) sold certain natural gas production to NFG. The litigation addresses, among other things, the validity of the Contract, the price for natural gas sold, and certain take-or- pay claims. In December 1983, certain pricing provisions of the Contract were disapproved by the New York Public Service Commission ("PSC") and as a result, in January 1991, the New York Federal Court determined that the contract was invalidated. However, on December 3,1991, the Court of Appeals for the Second Circuit ("Court of Appeals") (Case No. 91 -7127) reversed the New York Federal Court and held that the Contract remained in effect subject to the pricing provisions set forth therein. The Court of Appeals remanded the case to the New York Federal Court for further proceedings not inconsistent with their opinion. During the Reorganization Proceeding, TGX filed an adversary proceeding (the "Turnover Proceeding") in the Bankruptcy Court to compel NFG to pay the amount due to TGX pursuant to the provisions of the Contract. Effective June 19, 1992, TGX and NFG entered into a partial settlement agreement, regarding the settlement of some, but not all, of their disputes. Pursuant to the provisions of the partial settlement agreement, in consideration of a payment of $2,940,000 (the "Payment") from NFG, TGX (i) dismissed the Turnover Proceeding without prejudice (ii) released NFG (subject to certain limitations) from any and all liability and affirmative claims for relief alleged to arise from or based upon certain evidence presented by TGX in the Turnover Proceeding, and (iii) reserved its rights regarding the assumption or rejection of certain other relatively minor gas purchase agreements with NFG. The Payment will be credited against any additional amount due to TGX from NFG. In July 1992, the New York Federal Court denied a motion filed by NFG for partial summary judgment wherein NFG sought a finding that it had properly suspended performance under, and eventually terminated, the Contract. A subsequent rehearing upheld this conclusion, but determined that certain matters relating to this issue were questions of fact that cannot be resolved by summary judgment. In December 1992, NFG filed a motion with the PSC requesting a hearing to determine pricing issues related to the Contract. In 1993, the PSC determined that it would hold the requested hearing, and in November 1994, the Administrative Law Judge ("ALJ") appointed by the PSC issued a preliminary Recommended Decision stating that the PSC should find that from December 20,1983 through November, 1992, the maximum contract price that would be just and reasonable within the meaning of the Public Service Law had been $3.714 per Mcf of gas. The ALJ also recommended that the Commission should determine only NFG's entitlement to cost recovery from its customers, and should not adjudicate the respective rights of TGX and NFG vis-a-vis one another. TGX, NFG and the staff of the PSC have filed exceptions to the ALJ's recommended rulings, but the PSC had not ruled on the recommended decision or the filed exceptions as of March 1, 1995. In January 1993, the New York Federal Court granted TGX's motion for partial summary judgment regarding the price to be paid under the Contract. Based on the New York Federal Court's order, TGX has concluded that from December 1983, until at least, January 1, 1993, the date Federal price controls were terminated, the Contract price is equal to the lower of (i) the applicable maximum lawful price for December 1983 and for each month thereafter as established by the Natural Gas Policy Act ("NGPA") subject to the escalations provided by the NGPA or (ii) the December 1983 permitted Contract price of approximately $4.41 per MCF. The Federal Court's decision might be interpreted such that the December 1983 permitted contract price would be $4.41 per Mcf during the winter months and $4.01 per Mcf during the summer months. Based on TGX's calculations, the gross difference between the price actually paid by NFG and the price required by the New York Federal Court's order (assuming a contract price of $4.41 for winter and $4.01 for summer per Mcf) is approximately $23,912,000 as of December 31, 1994, including permitted statutory interest. The New York Federal Court's order did not determine the impact of the termination of the NGPA, the effect of any subsequent PSC order, or NFG's defense, including the alleged repudiation by TGX of the NFG contract. As part of its sale of substantially all of its oil and gas properties in Ohio and New York to BBC, TGX assigned the Contract effective December 1, 1993. TGX's 4 assignment of the Contract did not include TGX's rights in its existing claims against NFG, any proceeds therefrom, and TGX's rights, claims or causes of action, even if they had not yet been asserted, that arose prior to the effective time of the assignment. In November 1994, the New York Federal Court appointed a Magistrate to review and hear various aspects of the Federal Court litigation, including certain motions, scheduling, and certain pre-trial discovery. In early 1995, in anticipation of the issuance of a decision by the PSC in March 1995, the Magistrate held that all discovery would be stayed pending a further meeting with the Magistrate in May 1995 to discuss the state of the case. While TGX is continuing the litigation with NFG regarding the Contract, TGX's management has determined that it will also continue to seek a negotiated settlement with NFG. However, there can be no assurances that any such settlement negotiations will be held or, if held, will be productive. Absent settlement, TGX will vigorously pursue the NFG Litigation. In either event, the ultimate result of the litigation or any settlement with NFG could have a material effect on TGX's financial condition. Also, as a result of the debt restructuring completed on July 13, 1994, BMO, through its wholly owned subsidiary, BMOF, is entitled to receive the initial $4,652,000, plus interest, of any NFG Litigation proceeds and will, in certain instances after TGX has received the same amount as is paid to BMOF, be entitled to receive up to 50% of certain additional proceeds. See "Bank Indebtedness." Furthermore, in connection with the settlement of certain administrative claims, TGX has agreed that subsequent to the BMOF payment, amounts equal to $90,000 plus interest would be paid to certain administrative claimants in partial settlement of their previously outstanding Administrative Notes. See "Administrative Claims." TGX can make no prediction as to when, if ever, the NFG Litigation will finally be resolved. Prior Period Adjustments In July 1994, the Company restructured and converted its BMO debt of $4,652,000 to a nonrecourse note secured only by proceeds, if any, which might be received from the NFG Litigation. This restructuring and conversion was accounted for as an exchange transaction presented as an extinguishment of debt in accordance with Emerging Issues Task Force Consensus No. 86-18 and resulted in the recognition of an extraordinary gain, net of transaction costs of $492,000, of $4,160,000 in the third quarter of 1994. In connection with responding to comments from the Securities and Exchange Commission in connection with a 1996 filing, the Company accepted the securities and Exchange Commission's determination that generally accepted accounting principles require the Company to account for the restructuring and conversion of debt as a troubled debt restructuring in accordance with Statement of Financial Accounting Standards No. 15. As a result of this change, the financial statements for September 30, 1994 through the current reported period have been restated to restore the liability for the nonrecourse BMO debt, including accrued interest, and to reverse the extraordinary gain recognized in 1994. This restatement did not impact cash flow during the period September 30, 1994 through the current reported period. The Company did, however, upon resolution of the NFG Litigation in April 1996, reflect a net gain from litigation settlement of $7,100,000 and an extraordinary debt extinguishment gain of $1,868,000, and made a final debt payment to BMO of $3,600,000. See Note 15 of the Notes to Consolidated Financial Statements. Fresh Start Reporting As a result of the substantial consummation of the Plan and due to (i) the reallocation of the voting rights of equity interest owners and (ii) the reorganization value of TGX's assets being less than the total of all of its post-petition liabilities and allowed claims, as of October 2, 1992, the effects of the Reorganization Proceeding were accounted for in accordance with the fresh start reporting standards promulgated under the American Institute of Certified Public Accountants Statement of Position 90-7 "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code" ("SOP 90-7"). In conjunction with implementing fresh start reporting, the Company's management determined a reorganization value ("RV") which attempted to establish the fair market value of the Company as of the date of substantial consummation of the Plan. Oil and gas property and other related asset values were estimated by discounting future net revenues on the basis of actual, or in some instances, assumed prices. Other assets were valued at their book value. The Company's Senior Preferred Stock, which was issued pursuant to the Plan, was determined on the basis of the difference between the RV of the Company's assets less the present value of 5 liabilities and the par value of preconsummation equity interests. For further information concerning the method of calculating the RV, see Note 2 of the Notes to Consolidated Financial Statements. The RV was determined by management on the basis of its best judgment of what it considered to be the fair market value ("FMV") of the Company's assets and liabilities after reviewing relevant facts concerning the price at which similar assets were being sold between willing buyers and sellers. However, there can be no assurances that the RV and the FMV are comparable and the difference between the Company's calculated RV and the FMV may, in fact, be material. In conjunction with the implementation of fresh start reporting, the Company also adopted the successful efforts method, rather than the full cost method, of accounting for oil and natural gas properties. In the opinion of the Company's management, this accounting method was preferable since it would result in a better matching of oil and natural gas revenues with the related exploration and production costs and expenses. See Note 1 to Notes to Consolidated Financial Statements. REORGANIZATION PROCEEDING Overview of the Plan The following is a brief summary of certain information regarding the Plan. The summary is necessarily incomplete and selective and is qualified in its entirety by reference to the Plan, the full terms of which are hereby incorporated by reference. Pursuant to the Plan, the Company entered into the Amended Credit Agreement with BMO, and, depending on the amount of the claim, satisfied unsecured claims with cash or Senior Preferred Stock. See "The Company -Bank Indebtedness", and Terms of Preferred and Common Stock". In addition, certain specified classes of claims were paid in cash, retained or otherwise provided for. Administrative claimants holding allowed Administrative Claims under the Plan were paid in cash or had their claims otherwise satisfied, and, numerous executory contracts were assumed or rejected by TGX. See "The Company -Administrative Claims." Currently, the aggregate balance of pre-petition obligations related to assumed executory contracts is approximately $317,000 which is related to undistributed net oil and gas revenues and which is in a "suspended pay" status. As of the Effective Date of the Plan, the preferred and common stockholders selected a new Board of Directors (the "New Board") comprised of eight individuals to serve until January 1995, or until their successors were duly elected and qualified. The New Board consisted of five members selected by holders of the Senior Preferred (two of which were designees of Steinhardt, and one of which could not be an affiliate of any holder of the Senior Preferred) and two members selected by holders of the other classes of stock acting as one class. The remaining member of the New Board was the chief executive officer of the Company. Subsequent to the Effective Date, two members of the Board of Directors have resigned and have not been replaced. See "Item 10. Directors and Executive Officers of the Registrant". While the existing Board of Directors will retain their positions until their successors are duly elected and have qualified, subsequent to January 21, 1995, the Board's structure was no longer fixed by the Plan and as a result when new directors are elected, the Plan provides that eight directors are to be elected without regard to class representation. However, holders of Senior Preferred have 95% of the voting power of the Company and a plurality of such holders can, therefore effectively elect all Directors. In addition, two additional directors are to be elected solely by the Senior Preferred Stockholders until the Company has made up its dividend arrearages. See "Unsecured Claims -Senior Preferred." Administrative Expenses During the Reorganization Proceeding, certain claimants filed applications for Administrative Claims of approximately $7,131,000 in administrative fees and expenses related to the Reorganization Proceeding. Three of the large administrative claimants (the "Opposing Administrative Claimants") agreed that in consideration for the satisfaction in full of the balance of their Administrative Claims as of the date of substantial consummation they would receive (i) a payment of $300,000 (ii) 55,000 shares of the Senior Preferred and (iii) the conveyance of approximately 29,400 acres of undeveloped land in Culberson and Hudspeth Counties, Texas. For information concerning the payment of other Administrative Claims see "Business of the Company-Administrative Claims". 6 Unsecured Claims General Pursuant to the Plan, the Company has designated a Series A Senior Preferred Stock ($1 par value) and a Series B Preferred Stock ($1 par value) ("Junior Preferred") to be issued to holders of certain classes of claims and retains its Old Preferred and Common Stock. The total number of authorized shares of Senior Preferred is 10,000,000. Senior Preferred The Plan provides for a total of 8,529,246 shares of Senior Preferred to be issued to holders of certain unsecured claims on the basis of one share of Senior Preferred for every $10 of certain finally allowed or otherwise agreed upon claim. The Senior Preferred entitles its holders to receive a 10% annual compounded cash dividend, payable quarterly, provided however, that the payment of such dividend does not violate Delaware law or certain covenants in the Company's bank loan agreements. At any time after January 21, 1995, whenever quarterly dividends payable on the Senior Preferred are in arrears in an aggregate amount equal to six full quarterly dividends (which need not be consecutive), the number of directors of the Company is increased by two and such additional directors are elected by the holders of the Senior Preferred at the next succeeding annual meeting of stockholders (and at each succeeding annual meeting of stockholders thereafter until such right shall terminate as provided pursuant to the Plan). The Company has not paid any of the quarterly dividends required since the Effective Date of the Plan and, based on the current financial position of the Company, it does not expect to make any such dividend payments in the near future. See "Overview of the Plan." The Senior Preferred is being issued without registration under the Securities Act of 1933, as amended (the "Securities Act") in reliance upon the exemption from registration available under Section 1145 of the Bankruptcy Code. Holders of Senior and Junior Preferred have a liquidation preference in the amount of $10 per share, with the holders of Senior Preferred having priority over the liquidation preference afforded the holders of Junior Preferred, Old Preferred and Common Stock. At the option of the Company, the Senior and Junior Preferred are redeemable in whole or in part at any time at a price per share equal to the liquidation preference amount per share, plus all accrued and unpaid dividends through the date of redemption. The Company must redeem all outstanding shares of the Senior Preferred at the full redemption price on or before ten years from the Effective Date of the Plan unless such redemption would violate Delaware law, in which case the Company must redeem the Senior Preferred as soon as it is possible in accordance with Delaware law. Holders of Senior Preferred have 95% of the voting rights of TGX with the remaining 5% of voting rights being allocated collectively among holders of the Junior Preferred, Old Preferred and Common Stock (herein collectively called the "Other Stock"). In connection with the distribution of the Senior Preferred Stock to claimants holding Senior Subordinated Notes, the Bank of New York ("BONY"), as indenture trustee pursuant to the indenture defining the rights of the holders of the previously outstanding Senior Subordinated Notes, alleged that it was entitled to collection of certain fees and expenses under the Plan. Such fees and expenses were disputed by TGX and certain of the holders of Senior Subordinated Notes. In late 1994, a compromise was effected with BONY whereby TGX has paid to BONY the sum of $90,000 in full settlement of BONY's claims. As a result, BONY has commenced a process of distributing the Senior Preferred. Junior Preferred Stock Any claimants entitled to receive shares of Junior Preferred receive one share of Junior Preferred for every $10 of finally allowed claim. To date, no claims to be satisfied by Junior Preferred have been finally allowed and the Company does not currently anticipate that any such claims will be finally allowed. 7 Old Preferred Stock The 300,000 shares of Old Preferred, $1 par value with a liquidation preference of $10 per share, ranks junior in preference and priority to Senior Preferred. Subject to the prohibitions of Delaware law and the Amended Credit Agreement, Old Preferred receives dividends at the rate of 9% per annum beginning on the Effective Date of the Plan, payable annually on the first business day of January of each year, with such dividends being paid in additional shares of Old Preferred until the Senior Preferred is redeemed in full. To date, no dividends related to the Old Preferred have been declared or paid. Subsequent to their sale of LEDCO to TGX, Gaylon D. Simmons and Gloria Annette Turner Simmons (collectively, "Simmons"), the former owners of LEDCO, have been engaged in a series of lawsuits against TGX and certain other parties. Pursuant to the Plan, Simmons will not seek recoveries against the Company in this litigation. In addition, any recoveries by Simmons from other parties, after a reduction for Simmons' reasonable attorneys' fees and costs plus interest, will result in the cancellation of securities issued to Simmons to the extent necessary to assure that Simmons' treatment under the Plan does not result in a double recovery on identical causes of action. The Old Preferred may be converted in whole, at any time, or in part, from time to time, at the option of the holder thereof into fully paid and non- assessable shares of Common Stock at the conversion rate of four shares of Common Stock for each share of Old Preferred. Common Stock The Company is authorized to issue 100,000,000 shares of Common Stock, of which 25,313,533 shares were outstanding as of March 1, 1995. All outstanding shares of the Common Stock are fully paid and non-assessable. The holders of Common Stock are entitled to one vote per share upon all matters presented to them. Pursuant to the Plan, holders of Common Stock are entitled, collectively with holders of Junior Preferred and Old Preferred, to 5% of the total voting power of the Company. The holders of Common Stock are entitled to dividends in such amounts as may be declared from time to time out of any funds legally available for such purposes. However, no dividends are payable until all accrued dividends have been paid to the preferred stockholders. In the event of liquidation, dissolution or winding up of the affairs of the Company, whether voluntary or involuntary, after payment of debts and liquidation preferences on preferred stock, all remaining assets, if any, will be divided and distributed among the holders of Common Stock pro rata according to the number of shares owned by them. The Common Stock does not have preemptive rights and is not subject to redemption. Jurisdiction of Bankruptcy Court The Plan provides that the Bankruptcy Court retains jurisdiction after the confirmation date for certain matters including, but not limited to, (i) modifying the Plan pursuant to the Bankruptcy Code, (ii) assuring the performance by TGX under the Plan, (iii) enforcing and interpreting the terms and conditions of the Plan, (iv) entering into such orders, including injunctions, as are necessary to enforce the title, rights and powers of TGX and to impose such limitations, restrictions, terms and conditions of such title, rights and powers as the Bankruptcy Court may deem necessary and, (v) deciding issues concerning federal tax reporting and withholding which arise in connection with the confirmation of the Plan. BUSINESS SEGMENT INFORMATION The only segment in which the company operates is the development and production of, and to a lesser degree the exploration for, oil and natural gas plus intrastate natural gas gathering and treating. General Conditions in the Oil and Gas Industry In recent years, the natural gas industry has experienced the adverse effects of domestic recessions, increased conservation measures and mild winter weather which has resulted in lower demand and a corresponding precipitous decrease in natural gas prices. The current NYMEX natural gas future contract price for the delivery month of April 1995 is $1.46/MMBTU as compared to $2.00/MMBTU for the same period in 1994. As a result of weather, availability of alternative fuels and natural gas surplus in storage, the price for natural gas may continue to have downward price pressures in the near term. As of March 1, 1995, the per barrel future price 8 for West Texas Intermediate oil production ("WTI"), which serves as the benchmark for domestic oil prices, was $16.75 as compared to $13.00 for the same date in 1994. Though oil prices are currently higher than the prior year, the price continues to fluctuate significantly. The uncertainty in the oil and natural gas industry over the duration and extent of economic and political conditions have adversely affected the industry. These conditions, added to other factors particularly affecting TGX, have adversely affected the business of the Company. Oil and Gas Exploration and Production The Company's principal activity is the production of oil and natural gas. In recent years the Company has reduced its oil and natural gas exploration and property acquisition activities due to reduced oil and natural gas prices and its financial condition. The Company continues to maintain a staff of professional and support personnel required to manage its existing properties, including one geologist, two engineers, and three marketing and land personnel. In addition, the Company has engaged petroleum geologists and engineers on a contract basis, as required. Proved Oil and Natural Gas Reserves Reserves and Reserve Values (a) General: Estimating economically recoverable crude oil and natural gas reserves and the future net revenues therefrom is not an exact science and is based upon a number of variable factors, such as historical production of the subject properties as compared with similar producing properties, and assumptions such as the effects of regulation by governmental agencies, future taxes, and development and other costs, all of which may vary considerably from actual results. All such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of economically recoverable reserves of crude oil and natural gas attributable to any particular group of properties, the classification and risk of recovering such reserves, and estimates of the future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates with respect to proved undeveloped and proved developed non-producing reserves that may be developed and produced in the future are based upon volumetric calculations or upon analogy to similar types of reservoirs. Later studies of the same reservoirs based upon production history may result in variations, which may be substantial. The actual production, revenues, severance and excise taxes, development costs, and operating expenditures with respect to the Company's reserves as reflected herein may vary from estimates, and such variances may be material. Based on the independent petroleum engineering report of Netherland, Sewell & Associates, Inc., as of January 1, 1995, utilizing year end product prices and costs held constant, the Company's proved oil and natural gas reserves in thousands of barrels ("MBbls") and billion of cubic feet ("BCF"), and associated estimated future net revenues, undiscounted and discounted at 10% ("PV 10"), are as follows (dollars in thousands): Estimated Future Net Revenues ----------------------------- Oil (MBbls) Gas (Bcf) Undiscounted PV10 ----------- --------- ------------ ---- Proved developed 444 7.8 $ 9,571 $ 6,594 Proved undeveloped 487 2.6 5,243 2,213 - -------------------------------------------------------------------------------- Total proved reserves 931 10.4 $14,814 $ 8,807 ================================================================================ Due to TGX's financial condition, prior year disclosures utilized only proved developed reserves because of to the uncertainty regarding TGX's ability to develop proved undeveloped reserves. As a result of TGX's debt restructuring (See "Indebtedness" above) and anticipated 1995 cash flow, TGX has included proved undeveloped reserves in preparing the 1994 report disclosures. The addition of the proved undeveloped reserves 9 is reflected as 1994 extensions and discoveries. All prior year reserve disclosures continue to be reported utilizing only proved developed reserves. See Note 12 of the Notes to Consolidated Financial Statements for a discussion of the calculation of the estimated future net revenues on an undiscounted and discounted basis. (b) Sale of New York and Ohio Properties: In January 1994, but effective as of December 1, 1993, the Company sold substantially all of its New York and Ohio properties (the "Sold Properties") to BBC for $16.2 million. In conjunction with this transaction, the Company assigned to BBC the Company's contract with NFG, pursuant to which a substantial portion of the Company's natural gas underlying the Sold Properties was marketed. The assignment of the NFG Contract was made with certain reservations relating to the NFG Litigation. At the time of the sale, BMO released its liens on the Sold Properties and the proceeds from the sale were used to repay a substantial portion of the Company's debt to BMO. See "Bank Indebtedness" above. (c) Tabular Information: The table below sets forth an analysis of the change in the Company's proved oil and natural gas reserves during 1994: Oil(MBbls) Gas(Bcf) - -------------------------------------------------------------------------------- Estimated proved developed reserves as of December 31, 1993 525 9.1 Sale of reserves in place (37) (0.5) Extensions and discoveries (1) 487 2.6 Revisions of previous estimates 18 1.4 Production (62) (2.2) - -------------------------------------------------------------------------------- Estimated proved reserves as of December 31, 1994 931 10.4 ================================================================================ (1) Reflects inclusion of proved undeveloped reserves that had been excluded in prior years' reporting. Except for the data contained in filings with the Securities and Exchange Commission ("SEC") and information furnished in conjunction with the Reorganization Proceeding pursuant to the order of the Bankruptcy Court, the Company has not filed information relating to estimates of its proved oil and natural gas reserves with any federal agencies. Oil and Gas Production Information pertaining to the Company's oil and natural gas production is set forth in the table below. Year Ended December 31, ----------------------- 1994 1993 1992 - -------------------------------------------------------------------------------- Oil production (MBbls) 62 87 82 Average price per barrel $ 15.16 $ 17.03 $ 19.40 Natural gas production (Bcf) 2.241 3.712 3.545 Average price per Mcf $ 1.72 $ 2.22 $ 2.13 Equivalent Mcf (6:1) 2.613 4.234 4.037 Lease operating expense per equivalent Mcf $ 1.22 $ .93 $ .98 Net oil and natural gas revenues (in thousands): Sale of production $ 4,802 $ 9,730 $ 9,142 Lease operating expenses (3,188) (3,935) (3,968) - -------------------------------------------------------------------------------- Net oil and natural gas revenues $ 1,614 $ 5,795 $ 5,174 ================================================================================ 10 Drilling Activity For the past three years, the Company has participated in no significant drilling operations. Leasehold Acreage and Productive Wells The following table sets forth the Company's interest in undeveloped acreage, developed acreage and productive wells in which it owns a working interest. Undeveloped Developed Productive Acreage Acreage Wells /1/ ----------- ---------- ------------ Gross Net Gross Net Gross Net - -------------------------------------------------------------------------------- Arkansas 50 31 2,760 1,355 41 15 Louisiana 0 0 4,712 535 12 1 Oklahoma 316 263 75,419 3,733 186 7 Texas 0 0 16,895 713 70 3 Other states 0 0 27,905 1,480 639 3 - -------------------------------------------------------------------------------- Total 366 294 127,691 7,816 948 29 ================================================================================ /1/ Productive wells are wells capable of producing oil or natural gas in economic quantities. The following table provides, as of December 31 for each year presented below with the Sold Properties being excluded for 1993 and 1994, additional information pertaining to the productive wells in which the Company owns a working interest. Gross /1/ Net /2/ ----------------------------------------------------- Oil Gas Total Oil Gas Total - -------------------------------------------------------------------------------- 1992 844 1,407 2,251 23 932 955 1993 756 276 1,032 19 26 45 1994 771 177 948 17 12 29 - -------------------------------------------------------------------------------- /1/ "Gross" wells are the total number of wells in which the Company owns an interest. /2/ "Net" represents the Company's working interest in each "Gross" well. A Summary of the Sold Properties is: Developed Productive Acreage Wells - -------------------------------------------------------------------------------- Gross Net Gross Net ----- --- ----- --- Louisiana 1,635 93 3 1 New Mexico 80 5 2 0.5 New York 13,123 449 117 4 Oklahoma 160 160 1 1 Texas 3,097 385 19 1 - -------------------------------------------------------------------------------- Total 18,095 1,092 142 7.5 ================================================================================ Partnerships Prior to 1985, the Company was actively engaged in the formation of limited or general partnerships structured to (i) drill for-oil-and natural gas or (ii) acquire oil and natural gas producing properties. In 1985, the Company acquired Amarex which was engaged in oil and natural gas exploration and production for its own 11 account and beneficially through the Amarex Partnerships. The Company liquidated 17 partnerships during 1994, due to such partnerships' financial condition and limited reserve values. As a result of the 1994 partnership liquidations the Company, as settlement of outstanding partnership notes and receivable, was assigned additional direct interests in related oil and natural gas properties having an estimated value of $381,000 and realized from such sales recoupment of $751,000 in previous allowed for receivables and notes. At December 31, 1994, the Company served as the managing general partner of eight oil and natural gas partnerships. TGX intends to pursue the liquidation of substantially all of the remaining partnerships during 1995. The liquidation of these partnerships could result in liquidating cash distributions to TGX and the collection of other amounts due to TGX from the partnerships. In addition, TGX will be able to reduce certain of its administrative expenses as a result of the liquidation of the partnerships. Natural Gas Treating Plant Through a joint venture, the Company owns an interest in a natural gas treating plant located in the Comite Field, East Baton Rouge Parish, Louisiana. Natural gas from two wells operated by the Company and one well operated by a third party is currently transported to the plant where it is treated to satisfy pipeline specifications. The plant also provides condensate handling and saltwater disposal facilities. The Company receives cash distributions from the joint venture for its share of net cash flow. For information concerning this treating plant, see Note 5 of the Notes to Consolidated Financial Statements. Competition, Markets and Other External Factors Competition and Marketing -Oil and Natural Gas Industry The oil and natural gas industry is highly competitive both in the search for and acquisition of oil and natural gas reserves and in the refining, processing and marketing of petroleum products. Competitors include the major and independent crude oil and natural gas companies, individual producers and operators, and major pipeline companies. Other sources of energy, such as coal and nuclear power, also provide competition, and crude oil and natural gas are subject to substantial competition from foreign sources. The price the Company receives for its oil production depends on many variables over which it has no control, such as the world supply of, and demand for, oil, the level of imports, and the political stability of foreign governments. The influence exerted by these and other factors has caused domestic oil prices to fluctuate dramatically. The availability of a ready market as well as the price received for natural gas produced and sold by the Company also depends upon numerous factors beyond its control, including the proximity of producing natural gas properties to pipelines, the capacity of such pipelines' fluctuations in seasonal or overall demand, domestic deliverability, government regulations, and competition from alternative forms of energy. Major Customers Information concerning sales to customers who accounted for more than 10% of total revenues, the loss of any of which could have a material adverse effect on the Company's operations if alterative customers could not be found, is contained in Note 11 of the Notes to Consolidated Financial Statements appearing elsewhere herein. As a result of the sale of properties to BBC, the Company no longer has any significant natural gas sales to NFG. Production and Development Hazards Hazards such as unexpected formations, blow-outs, cratering and fires are involved in crude oil and natural gas drilling, production and development activities. Such hazards, as well as adverse weather conditions, may hinder or delay drilling and development operations. TGX maintains insurance coverage customary in the crude oil and natural gas industry, but may be subject to liability for pollution and other damages or may lose substantial portions of its properties due to hazards against which it is impossible or impractical (due to prohibitive premium requirements) to maintain insurance. Governmental regulations relating to environmental matters could also increase TGX's cost of production and development operations or require it to cease production and development operations in certain areas. 12 Regulation Environmental Regulation The drilling for, production, transportation and storage of oil and natural gas and the operation and maintenance of natural gas treating plants are subject to various federal and state laws and regulations designed to protect the environment. Moreover, various state and governmental agencies are considering, and some have adopted, other laws and regulations regarding environmental control which could adversely affect the business of the Company. Compliance with such legislation and regulations, together with any penalties resulting from noncompliance therewith, may increase the cost of the Company's operations or may affect the Company's ability to complete, in a timely fashion, existing or future activities. However, the Company does not believe that such regulations could materially and adversely affect its financial condition or operations at the present time. State Regulation All states in which the Company conducts oil and natural gas production operations have statutory provisions regulating the drilling for, production, transportation, storage and sale of oil and natural gas. Such statutes, and the regulations promulgated in connection therewith, generally are intended to prevent the waste of oil and natural gas and to protect correlative rights and opportunities to produce oil and natural gas as between owners of interests in a common reservoir. Certain state regulatory authorities also regulate the amount of oil and natural gas produced by assigning allowable rates of production to each well or proration unit. Federal Regulation The Company's sale of its natural gas has historically been regulated by the Federal Energy Regulatory Commission ("FERC") under the authority of the Natural Gas Policy Act of 1978, which established price controls for various classifications of gas. However, as a result of the Wellhead Decontrol Act of 1989, all price controls were terminated as of January 1, 1993. The Company believes that this has had little or no impact on its natural gas sales, since its reserves were either previously deregulated, or sold under contracts with alternate pricing. FERC Order No. 636, revised to 636-B in November, 1992, ("Order 636") may however, have an impact on the Company's natural gas sales. Order 636 is a restructuring rule applicable to interstate pipelines which provides for "unbundling" or separating the various components of its services, i.e., supply, storage, gathering, transportation and sales. A current issue related to Order No. 636 is the regulation of natural gas gathering. Generally, natural gas producers are concerned that the transfer of gathering facilities to non- regulated entities will result in decreased competitiveness and accessibility to markets. Neither the FERC nor the courts have resolved this matter, and, at this time, the Company is unable to determine the effect that this matter may have on its operations. The Company may conduct operations on federal oil and natural gas leases, and such operations must comply with numerous regulatory restrictions and requirements issued by the Mineral Management Service, including various nondiscrimination statutes, and certain of such operations must be conducted pursuant to appropriate permits issued by the Bureau of Land Management. Employees As of December 31, 1994, the Company employed 13 persons, none of whom are represented by a labor union or collective bargaining agent. Also at December 31, 1994, the Company had engaged five persons on a temporary contract basis to perform certain financial and administrative functions. The Company considers its relations with its employees to be good and has experienced no work stoppages associated with labor disputes or grievances. 13 ITEM 2. PROPERTIES Information. For information concerning the Company's properties, see "Item 1. Business - Business Segment ITEM 3. LEGAL PROCEEDINGS Reorganization Proceeding For information concerning the Company's Reorganization Proceeding, see "Item 1. Business-Reorganization Proceeding". NFG Litigation For information concerning the NFG Litigation, see "Item 1. Business-NFG Litigation". New York Department of Environmental Conservation In January 1990, the New York State Department of Environmental Conservation, Division of Mineral Resources ("DEC") notified TGX that it considered TGX to be in violation of certain provisions of the environmental and conservation laws of the State of New York concerning approximately 150 natural gas wells and production facilities located in Chautauqua and Erie Counties. To settle this dispute, TGX entered into a consent order (the "Agreed Order") providing that TGX will (a) furnish status reports that will disclose the production history for certain wells, (b) install dehydration equipment on certain wells, and (c) submit to the DEC (i) a schedule identifying certain wells to be serviced, (ii) a "Plugging and Abandonment Program" for certain wells, and (iii)) a testing and reporting schedule for certain wells. The Agreed Order imposed a civil penalty on TGX in the amount of $139,000, which was suspended permanently as a result of TGX complying with the terms of the Agreed Order. TGX has completed operations on all wells subject to the Agreed Order. Pursuant to the DEC's requirements, TGX provided a letter of credit from BMO in the amount of $300,000 which was to be utilized by the DEC if TGX did not comply with the Agreed Order. Such letter of credit was collateralized with the Company's cash, held by BMO. In May 1994, the DEC agreed to reduce the letter of credit amount to $150,000 and a like amount of cash collateral was released. In February 1995, the letter of credit was completely eliminated and the remaining cash collateral released by BMO. Litigation Against Former Officers and Directors TGX is currently involved in litigation against certain former officers and directors. See "Item 13. Certain Relationships and Related Transactions -Paragon Resources, lnc." Other In August 1992, certain unleased mineral interest owners commenced a legal action against TGX, as operator of certain wells, in the 19th Judicial District Court for East Baton Rouge Parish, Louisiana (Case Number 383844, Division "A"). The complaint alleges that revenues in excess of the reasonable costs of drilling, completing, and operating certain wells have not been credited to the interests of the unleased mineral interest owners. This case is in the discovery stage and if settlement negotiations are not successful, TGX will vigorously defend itself in the litigation. In March 1994, a hearing was conducted in the Bankruptcy Court regarding the final allowance of pre-petition and administrative claims related to an overriding royalty interest previously conveyed by TGX. As a result of this hearing, the Bankruptcy Court established the method for computing these claim amounts. The parties stipulated that the finally allowed pre-petition claim amount was $600,000 which has been satisfied with the issuance of Senior Preferred. Previously, the Company had estimated this claim amount and therefore it had been included in the financial statements for prior years. Pursuant to the Bankruptcy Court's order, certain post-petition but prior to October 2, 1992 claims are to be treated as administrative claims. The administrative claim amount will be calculated by the claimant, subject to review and approval by the Company, and pursuant to the terms of the Plan. Any claims subsequent to October 2,1992 are subject to the Bankruptcy Court's review, including ownership of the overriding royalty interest. 14 From time to time, in the normal course of business, the Company is a party to various other litigation matters the outcome of which, to the extent not otherwise provided for, should not have a material adverse effect on the Company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. During the fourth quarter of 1994, no matters were submitted to a vote of the security holders. 15 PART II. ITEM 5. MARKET FOR THE REGISTRANTS SECURITIES AND RELATED STOCKHOLDER MATTERS As a result of TGX's Chapter 11 filing, in March 1991, the National Association of Securities Dealers, Inc. (the "NASD") notified TGX that it was terminating the inclusion of TGX's Common Stock on the Nasdaq National Market System. Through June 1992, the Company's common stock price continued to be reported on Nasdaq. Since July 1, 1992, TGX's Common Stock is not and the Senior Preferred will not be included on the Nasdaq National Market System. TGX's Common Stock is traded through the NASD's "bulletin board". As of March 1,1995, there were approximately 4,000 holders of record of the Company's Common Stock. The Senior Preferred will be issued to approximately 950 parties. For the period through June 30, 1992, the following table presents the high and low bid prices for the Common Stock as reported by Nasdaq. For the periods ending subsequent to June 30, 1992, the following table sets forth bid prices reported by the National Quotations Bureau, Inc. All quotations represent bid prices between dealers without retail markup or markdown or commission and do not reflect actual transactions. Quarter Ended High Low ------------- ---- --- 1994: ----- March 31 $.001 $.001 June 30 .001 .001 September 30 .001 .001 December 31 .01 .001 1993: ----- March 31 $.001 $.001 June 30 .001 .001 September 30 .001 .001 December 31 .001 .001 1992: ----- March 31 $.063 $.063 June 30 .063 .063 September 30 .015 .001 December 31 .001 .001 Holders of Senior Preferred have a dividend and liquidation preference over holders of other classes of Preferred Stock or the Common Stockholders. As of December 31, 1994, the redemption value and accrued dividends related to the Senior Preferred were $87,282,000 and $26,454,000, respectively. The Senior Preferred dividends must be paid in full prior to paying any dividends for the Common Stock. Under a liquidation scenario, after secured debt and other liabilities have been paid or provided for, the Senior Preferred redemption value of $87,282,000 plus any accrued dividends must be paid in full before any liquidating distributions are made to the holders of other Preferred or Common Stock. The Company has not paid, and for the near future, does not anticipate paying, any cash dividends to its Preferred or Common Stockholders. The Company is prohibited from paying dividends on its Common Stock at any time that it is in arrears in paying dividends on any class of its preferred stock. The Company is currently in arrears in making such payments. For information concerning the rights of preferred and common stockholders regarding dividends see "Item 1. Business-Terms of Preferred and Common Stock.. On March 28,1995, the closing price per share of the Common Stock, as reported by the National Quotations Bureau, Inc., was $.001. The Senior Preferred has not been publicly traded, and therefore, the Company cannot determine the market value, if any, therefor. 16 ITEM 6. SELECTED FINANCIAL DATA The following selected financial data should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's consolidated financial statements and the related notes thereto appearing elsewhere herein.
Reorganized Company/1/ Predecessor Company/1/ ------------------------------------------------- ------------------------------------------ (Restated) October 2, January 1, Year Ended Year Ended through through Year Ended Year Ended December 31, December 31, December 31, October 1, December 31, December 31, (Thousands, except per share data) 1994 (4) 1993 1992 1992 1991 1990 - ------------------------------------------------------------------------------------------------------------------------------------ RESULTS OF OPERATIONS: From continuing oil and natural gas operations: Revenues $ 6,477 $ 10,997 $ 2,993 $ 9,830 $ 8,997 $ 15,706 Gross profit 1,614 5,795 1,638 3,536 4,885 7,565 Net (loss) applicable to common stock (15,476) (26,951) (3,184) (4,916) (132,399) (11,107) Per common share (.61) (1.06) (.13) (.19) (5.23) (.44) Income (loss) from discontinued operations - - - - (4,718)/2/ 265 Per common share - - - - (.19) .01 Capital expenditures 27 394 79 154 2,648 751 Average common shares outstanding 25,314 25,314 25,314 25,314 25,314 25,314 FINANCIAL POSITION AT END OF PERIOD Working capital (deficit)/3/ $ (1,319) $ (9,209) $ (24,047) $ (4,503) $ (2,533) $ 8,096 Property and equipment, net 7,257 9,404 39,070 42,815 48,751 151,679 Net assets of discontinued operation - - - - - 5,088 Total assets 10,676 30,065 45,129 51,657 56,026 174,837 Liabilities subject to compromise - - - - 88,098 72,650 Long-term debt 6,020 - - 21,958 - - Stockholders' equity (deficit) (43,711) (28,505) (1,824) (69,650) (65,437) 71,680 COMMON STOCK: Shares outstanding at end of period 25,314 25,314 25,314 25,314 25,314 25,314 Cash dividends paid - - - - - -
___________________________ /1/ As used herein, "Predecessor Company" means the operations of the Company prior to October 2, 1992, the effective date of the order regarding substantial consummation of the Plan, and "Reorganized Company" means the operations of the Company subsequent to that date. The effects of the Reorganization Proceeding were accounted for in accordance with the fresh start reporting standards promulgated under SOP 90-7. See "Item 1. The Company-Fresh Start Reporting" and Note 2 of the Notes to the Consolidated Financial Statements included elsewhere herein. /2/ Includes $4,144 attributable to Loss on Sale on Discontinued Operations. /3/ Excludes pre-petition liabilities as of December 31, 1991 and 1990. /4/ Period results restated as discussed in Note 15 of the Notes to the Consolidated Financial Statements included elsewhere herein. 17 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS As a result of the Reorganization Proceeding, which was substantially consummated on October 2, 1992, the Company is required to present its financial statements pursuant to fresh start reporting standards, and accordingly, the financial statements of the Reorganized Company are not comparable to the financial statements of the Predecessor Company. However, in the case of the consolidated statement of operations, the Company believes that comments comparing calendar years are appropriate in order to provide a more meaningful understanding of the Company's operations. The following discussion provides information which management believes is relevant to an understanding and assessment of the Company's results of operations, financial condition, and those presently known events, trends or uncertainties that are reasonably likely to have a material impact on the Company's future results of operations or financial condition or that are reasonably likely to cause the historical financial statements not to be necessarily indicative of future operating results or financial condition. It should be read in conjunction with the selected financial data appearing in the preceding section and the consolidated financial statements and related notes appearing elsewhere herein. Amounts in this discussion and analysis have been restated as disclosed in Note 15 of the Notes to Consolidated Financial Statements. RESULTS OF OPERATIONS 1994 Compared to 1993 A comparison of significant operating income components is (amounts in thousands): 1994 1993 Change ---- ---- ------ Oil and natural gas sales $ 4,802 $ 9,730 (51%) Gas gathering and treating revenues 727 938 (22%) Gain on property sales, net, and other revenues 948 329 189% Operating expenses (3,188) (3,935) (19%) Depletion, depreciation and amortization (1,414) (2,995) (53%) General and administrative expenses (2,239) (3,323) (33%) ------- ------- Operating income (loss) $ (364) $ 744 (149%) ======= ======= Revenues Consolidated revenues for 1994 decreased 41% or $4,520,000 to $6,477,000 from $10,997,000 for 1993. This decrease was related to property sales and production loss related to the Starkey No.1 well. The decrease in revenues was partially offset by significant gas balancing revenues recorded in 1994. Excluding the gain on property sales and other revenues, which represent primarily nonrecurring items, consolidated revenues decreased $5,139,000 or 48% to $5,529,000 as compared to $10,668,000 for 1993. Oil and natural gas production revenues for 1994 decreased by 51% or $4,928,000. This decrease was primarily due to lower production volumes resulting from property sales. The contribution to 1993 revenues from the New York and Ohio properties sold was approximately $4,655,000. Oil and natural gas revenues for 1994 were also impacted by average product price declines for both oil and gas. The production decline impact on revenues was partially reduced by gross gas balancing revenues of $809,000 received during 1994. The Company records gas revenues on the net sales method and thus revenues are recorded when received as opposed to the entitlement method. 18 The gas balancing payments received represented sales, net to the Company, of 590,000 Mcf. A summary of the components of the revenue decrease, including gas balancing and properties sold revenues, is (in thousands): Production Total Volume Price ----- ---------- ----- Oil $ (542) $ (426) $ (116) Natural gas (4,386) (3,300) (1,086) ------- ---------- -------- $(4,928) $ (3,726) $ (1,202) ======= ========== ======== A summary of oil and natural gas sales volume and revenues for the respective years is: Summary of Oil Volume and Revenues ---------------------------------- 1994 1993 Change - -------------------------------------------------------------------------------- Oil revenues (in thousands) $ 940 $ 1,482 (37%) Oil sales volume (barrels) 62,000 87,000 (29%) Oil average price per barrel 15.16 $ 17.03 (11%) - -------------------------------------------------------------------------------- Summary of Natural Gas Sales Volume and Revenues ------------------------------------------------ 1994 1993 Change - -------------------------------------------------------------------------------- Natural gas revenues (in thousands) 3,862 $ 8,248 (53%) Natural gas sales volume (Bcf) 2.241 3.712 (40%) Natural gas average sales price per Mcf 1.72 $ 2.22 (23%) - -------------------------------------------------------------------------------- In early 1994 the Company, in two unrelated sales, sold all of its New York and Ohio oil and natural gas properties and related assets. As a result of the BBC sale being effective December 1, 1993 and the later sale begins effective March 1,1994, the 1994 operating results contained only limited financial activity related to these sold properties as compared to 1993. The following summary details the oil and natural gas production activity and related financial results included in 1993 results for these sold properties (dollars in thousands): Oil sale volume (MBBLS) 5 Gas sale volume (BCF) 1.912 Oil and natural gas revenue $ 4,655 Operating expenses 2,130 -------- Net revenue $ 2,525 ======== On an equivalent unit basis (one barrel of oil equals six MCF of natural gas on a heating value basis), natural gas for 1994 represents 86% of the Company's oil and natural gas sales volume and 80% of total oil and natural gas revenues. Based on the January 1,1995 independent reserve report, gas production will continue to be the dominant product and will represent approximately 75% of the Company's future oil and natural gas production volumes on an equivalent unit basis. Natural gas gathering and treating revenues decreased by 22% or $211,000 to $727,000 in 1994 as compared to $938,000 in 1993. This decrease is primarily attributable to decreased volume throughput due to the Starkey No. 1 well going off production in December 1993. Efforts to return the Starkey to production to date have not been successful. During 1994, the Company sold partnership producing properties and undeveloped properties for a total of $2,174,000. This compares to 1993's sale of 164 producing wells for $441,000 which resulted in a net gain of 19 $58,000. The producing properties sold in 1994, for $1,424,000, represented the Company's interest in approximately 31 gross wells from liquidated partnerships, resulting in a net gain of $766,000. This sale was primarily the result of the Company's continuing effort to liquidate various private and public partnerships for which it was managing general partner and certain non-strategic assets. The undeveloped property sale represented acreage in the New York area and was sold to BBC, the primary purchaser of the Company's New York assets, for $750,000 which represented net book value. Costs and Expenses Consolidated costs and expenses decreased by $16,907,000 or 68% to $8,007,000 for 1994 as compared to $24,914,000 for 1993. Included in 1993 costs and expenses is a non-cash charge of $12,415,000 for a provision for loss on sale of assets which represents the net book value of the Sold Properties, plus transaction costs, in excess of the net consideration received. Excluding the 1993 charge for loss on sale of assets, consolidated costs and expenses for 1994 decreased by $4,492,000 or 36%. For 1994, operating expenses decreased $747,000 or 19% to $3,188,000 as compared to $3,935,000 for 1993. Operating expenses for 1994 and 1993 were 66% and 40%, respectively, of oil and natural gas revenues and were $1.22 and $.93 on an equivalent Mcf basis, respectively. The higher rate per equivalent Mcf for the current year is partially attributable to the Company's remaining properties being of a mature nature thus resulting in lower production rates and higher costs as certain operating costs are fixed and do not vary with production rates or product price. Also included in 1994 is $583,000 of workover costs. Workover costs for 1994 consisted primarily of $416,000 of costs related to the unsuccessful attempts to return the Starkey No. 1 located in Comite Field, East Baton Rouge Parish to production. Exclusion of the Starkey workover costs would have reduced operating expenses as a percent of oil and natural gas revenues to 58% and cost per equivalent Mcf to $1.06. The overall decrease in current year operating expenses is primarily the result of Sold Property expenses of $2,130,000 being included in 1993 activity, reduced by 1994 increases for nonrecurring costs. Operating expenses in 1994 also included $174,000 of transportation costs related to the $809,000 of gas balancing revenues recorded during the year and the reclassification of approximately $260,000 of net general and umbrella liability costs. Operating expenses during 1993 also included certain nonrecurring costs aggregating approximately $419,000. These 1993 costs were attributable to operation enhancement activities and unscheduled maintenance costs ($94,000), increased natural gas treating, gathering and compression cost ($80,000), producing well overhead rates and well control insurance adjustments ($47,000), abandonment costs ($56,000), and operating expenses related to the Amarex Partnerships ($142,000). Depreciation, depletion and amortization ("DD&A") decreased by $1,581,000 or 53% due to lower sales volumes and a lower weighted average DD&A rate. In 1994, management determined that as a result of the Company's improving financial condition, including expected cash flow for 1995 and beyond, it could fund development of its oil and gas reserves which had previously not been classified as proved undeveloped. Accordingly, in 1994 the Company treated these reserves as proved undeveloped for purposes of accounting estimates and financial statement disclosures. As a result of utilizing total proved reserves in the calculation, DD&A expense for 1994 was reduced by $847,000. The weighted average DD&A rate for 1994 on an equivalent Mcf basis was $ .50 as compared to 1993's rate of $ .78. General and administrative expenses in 1994 decreased $1,084,000 or 33% to $2,239,000 from $3,323,000 in 1993. This decrease was primarily the result of staff reductions and the outsourcing of certain financial and administrative functions and accounts receivable recoveries. In 1994 the Company liquidated various partnerships for which it was managing general partner. Certain of these partnerships owed the Company note and receivable amounts which had been fully allowed for as a doubtful account in prior years. As a result of the partnership property sales and other collection efforts, the Company recorded approximately $751,000 of net accounts receivable recoveries as a reduction to general and administrative expense. Administrative costs in 1994 were further decreased by approximately $336,000 of gross insurance costs that were reallocated from administrative costs to operating expenses. This insurance allocation results in the better matching of costs to operations and allowed the Company to recoup a portion of these costs from third parties who benefitted from such coverages on operated and partnership properties. Also, included in 1994 expenses is $492,000 of nondeferable debt restructuring costs related to the BMO debt restructuring. Included in 1993 are office relocations costs of approximately $225,000 and certain legal fees of $350,000. Interest expense decreased $1,080,000 or 48% in 1994 to $1,166,000 from $2,246,000 in 1993. This decrease is primarily attributable to lower average debt outstanding and lower interest rates. Total secured debt 20 and note payments for 1994 totaled $16,301,000. The interest rate under the Bank One facility is the bank's base rate plus 2% which resulted in a weighted average effective rate of approximately 9.74% during 1994. The BMO debt agreement minimum interest rate was 13%, but in conjunction with debt restructuring on July 13, 1994, the interest rate was lowered to 10% on the remaining debt. Due to tax loss carry forwards, the Company currently pays federal and state alternative minimum income taxes only. The 1994 tax provision of $17,000 was primarily due to state taxes. The extraordinary gain in 1994 of $831,000 was derived from the settlement, on discounted basis, of certain Administrative Notes. 1993 Compared to 1992 A comparison of operating income is (amounts in thousands): 1993 1992 Change -------- -------- -------- Oil and natural gas production $ 9,730 $ 9,142 6% Natural gas gathering and treating 938 848 11% Gain on property sales, net and other revenue 329 2,833 (88%) Operating expenses (3,935) (3,968) (1%) Depletion, depreciation and amortization (2,995) (2,800) 7% General and administrative expenses (3,323) (3,592) (7%) ------- ------- Operating income $ 744 $ 2,463 (70%) ======= ======= Revenues Consolidated revenues for 1993 decreased 14% to $10,997,000 compared to $12,823,000 for 1992. Consolidated revenues for 1992 included $2,940,000 related to the partial settlement agreement proceeds received from NFG. Excluding gain on net property sales and other revenues from both periods, which is primarily related to the partial settlement agreement proceeds and nonrecurring items, consolidated revenues for 1993 increased 7% or $678,000 to $10,668,000 as compared to $9,990,000 for 1992. Oil and natural gas production revenues for 1993 increased by $588,000 to $9,730,000 compared to $9,142,000 for 1992. Oil and natural gas production revenue increased due to the recognition of greater production volumes and higher average natural gas prices which were partially offset with lower average oil prices. A summary of the components of this increase is (in thousands of dollars): Production Total Volume Price ----- ---------- ----- Oil $ (102) $ 98 $ (200) Natural gas 690 356 334 ------- ------ ------- $ 588 $ 454 $ 134 ======= ====== ======= A summary of oil and natural gas production and revenues for the respective years is: Summary of Oil Sales Volume Production and Revenues --------------------------------------------------- 1993 1992 Change - -------------------------------------------------------------------------------- Oil revenues (in thousands) $ 1,482 $ 1,591 (7%) Oil sales volume (barrels) 87,000 82,000 6% Oil average price per barrel $ 17.03 $ 19.40 (12%) - -------------------------------------------------------------------------------- 21 Summary of Natural Gas Sales Volume and Revenues ------------------------------------------------ 1993 1992 Change - -------------------------------------------------------------------------------- Natural gas revenues (in thousands) $ 8,248 $ 7,551 9% Natural gas sales volume (Bcf) 3.712 3.545 5% Natural gas average sales price per Mcf $ 2.22 $ 2.13 4% - -------------------------------------------------------------------------------- On an equivalent unit basis (one barrel of oil equals six Mcf of natural gas on a heating value basis), natural gas for 1993 represents 88% of the Company's oil and natural gas sales volumes and 85% of oil and natural gas revenues. Based on the December 31, 1993 estimates of the Company's oil and natural gas reserves, which excludes the Sold Properties, natural gas will represent approximately 80% of the Company's future oil and natural gas sales volumes on an equivalent unit basis. A major factor affecting 1993 natural gas sales volumes was the decrease in natural gas deliveries during the three month period May through July 1993 of approximately 88,000 Mcf due to pipeline compressor repairs. Also in 1993, the Company sold its interest in 164 wells for $441,000. These wells had a net book value of $383,000 and the $58,000 gain related to the sale of these wells is included in other revenue. The net reserve quantities attributable to these wells were 27,500 barrels of oil and 526,000 Mcf of natural gas. The expected decrease in sales volumes related to the sale of the wells and the normal production decline was offset by improved production techniques and the current recognition of beneficial interests in the operating income of certain Amarex Partnerships. In conjunction with the consummation of plans of reorganization for certain Amarex Partnerships, in December 1985, the Company advanced approximately $2,445,000 on behalf of those Amarex Partnerships. The repayment of these advances was subordinated to the payment in full by the Amarex Partnerships of a production payment issued in satisfaction of certain claims. Due to the uncertainty related to the collection of the advances, the Company did not record them as assets at the time they were made. In September 1993, the production payment was paid in full and the Company began receiving repayment of the advances from the Amarex Partnerships which will be recorded as beneficial interest in the operating income of the Amarex Partnerships. A summary of the net operating income that was recognized in 1993 is (amounts in thousands): Oil sales volume (Mbbls) 4.3 Gas sales volume (Mmcf) 270 Oil and natural gas sales $ 611 Other revenue 67 Operating expenses (142) General and administrative expenses (16) ----- Operating income $ 520 ===== The price that the Company receives for its oil and natural gas production depends on many variables over which it has little or no control. Average natural gas prices for 1993 were higher than recent prior periods due to numerous factors including, but not limited to, (i) lower than expected natural gas storage levels, (ii) anticipation of pipeline restructuring filing under the FERC Order 636, (iii) the revision of natural gas production proration rules in Oklahoma and Texas, and (iv) reduced competition resulting from declining deliverability of existing United States wells. Due to the current imbalance between supply and demand, 1993 oil prices have decreased compared to 1992. The Company is unable to predict the extent or duration of the current trend for oil and natural gas prices. During 1993, the weighted average price paid for natural gas under the NFG Contract was $2.26 per MCF compared to $2.72 per MCF in 1992. NFG notified TGX that for a six month period commencing May 1993, it would accept delivery of fifty percent (50%) of TGX's production for natural gas dedicated under the Contract and would pay for such deliveries based on the a price equal to the average long-term contract price between NFG and other 22 natural gas producers ("NFG L-T Price"). NFG also notified TGX that any deliveries to it in excess of this specified quantity ("Excess Gas") would be paid for at a price equal to NFG's spot price for similar production and that NFG might discontinue or limit deliveries of Excess Gas. For the period from May through October 1993, the average price paid by NFG was $2.24 which was less than TGX's average spot price for the sale of other natural gas production in the area. The Company is litigating various provisions, including the price to be paid, of the NFG Contract. See "Item 1. NFG Litigation". Natural gas gathering and treating revenues increased 11% to $938,000 in 1993 compared to $848,000 in 1992. This increase is primarily attributable to increased volume throughput and higher treating fees which had been reduced in early 1992 due to low natural gas prices. Costs and Expenses Consolidated costs and expenses increased by $10,572,000 or 74% to $24,914,000 for 1993 compared to $14,342,000 for 1992. Included in 1993 costs and expenses is a non-cash charge of $12,415,000 for a provision for loss on sale of assets which represents the net book value of the Sold Properties, plus transaction costs, in excess of the net consideration received. Excluding the 1993 charge for loss on sale of assets and the 1992 full cost ceiling adjustment of $1,505,000 and reorganization expense credit of $400,000, consolidated costs and expenses for 1993 decreased 6% or $738,000 to $12,499,000 as compared to $13,237,000 for 1992. For 1993, operating expenses decreased $33,000 or 1% to $3,935,000 compared to $3,968,000 for 1992. Operating expenses for 1993 and 1992 were 40% and 43% respectively of oil and natural gas revenues and were $.93 and $.98 on an equivalent MCF basis, respectively. Operating expenses during 1993 include costs aggregating $419,000 attributable to (i) operations related to the Company's oil and natural gas properties in Arkansas and New York that were conducted to enhance or maintain oil and natural gas production volumes ($55,000) (ii) unplanned compressor and meter repairs in New York ($39,000), (iii) increased natural gas treating, gathering and compression costs rates for properties located in Arkansas and Louisiana due to increased production ($80,000), (iv) adjustments related to producing well overhead rates and well control insurance ($47,000), (v) the abandonment of certain wells ($56,000), and (vi) operating expenses related to the Amarex Partnerships ($142,000). Certain operating expenses are fixed and accordingly will not vary with increases or decreases in oil and natural gas production. Effective October 2, 1992, the Company adopted the successful efforts accounting method for oil and natural gas operating activities. Depletion, depreciation, and amortization increased by 7% or $195,000 to $2,995,000 in 1993 from $2,800,000 in 1992 primarily due to a higher per unit depletion and depreciation rates for oil and natural gas computed on a field basis under successful efforts accounting. For 1993, the aggregate depletion and depreciation rate for oil and natural gas properties was $.78 per equivalent MCF and based on current information, it is estimated that this rate for 1994 will be $.90 per equivalent MCF. The depletion and depreciation rate could be materially affected by various events including but not limited to (i) the ability of the Company to conduct oil and natural gas operations and (ii) consistent rates of production from each field throughout the year. General and administrative expenses in 1993 decreased $269,000 or 7% to $3,323,000 form $3,592,000 in 1992. In order to reduce costs and improve efficiency, the Company consolidated its operations and administrative offices during 1993 and approximately $225,000 for relocation and transition costs related to this consolidation is included in 1993 general and administrative expenses. Also, 1993 general and administrative expense includes $100,000 for the amortization of deferred executive compensation which is a charge that was not incurred in 1992. Interest expense decreased $631,000 or 22% in 1993 to $2,246,000 from $2,877,000 in 1992 which included $333,000 related to the amortization of debt issuance costs. This decrease is primarily attributable to the Company's weighted average secured indebtedness for 1993 decreasing to $23,086,000 compared to $26,097,000 for 1992. The weighted average interest rate on secured debt in 1993 and 1992, excluding amortization of debt issuance costs, was 9.93% and 9.75%, respectively. In January 1994, the Company repaid approximately $14.3 million of its outstanding bank debt and it expects to reduce its bank debt to approximately $3.75 million as a result of its financial restructuring. The interest rate for the restructured bank debt will be the bank's base rate plus 2% (approximately 8.75%). In 1992, reorganization expense included $235,000 related to the accrual of post-petition contractual interest through January 21, 1992, the Effective Date of the Plan. In 1992, the Bankruptcy Court set finally allowed amounts for certain claims that were less than the amounts accrued by the Company. As a result, the Company adjusted the accruals to actual and realized a benefit of $1,335,000 which was offset by $700,000 for professional fees related 23 to (i) the objection to certain administrative claims related to the Reorganization Proceeding and (ii) the consummation of the Plan, as modified. Subsequent to the Effective Date, the Company has no obligation for contractual interest related to unsecured finally allowed claims. Since the Plan has been consummated, the Company no longer incurs reorganization expenses. FINANCIAL CONDITION In 1994, the Company's capital expenditures were not significant. However, property additions of $381,000 were recorded representing properties received from certain affiliated partnerships in satisfaction of notes and receivables. The Company also incurred workover costs of $583,000. In 1995, the Company anticipates increasing its capital and workover expenditures through the development of existing proved undeveloped and developed non-producing reserves, drilling or acquisition. At December 31, 1994, the Company's working capital deficit was $1,319,000 which included $203,000 of principal and interest due on the Administrative Notes and $934,000 related to various pre-petition obligations. The July 13, 1994 debt restructuring with BMO and establishment of a new line of credit with Bank One significantly improved the Company's financial condition while curing the BMO Events of Default. The Bank One credit facility's borrowings outstanding as of December 31, 1994 totaled $1,150,000 with a borrowing base of $2,070,000 which is reduced monthly by $56,000. Due to the excess of borrowing base over year end borrowing and the current monthly facility reduction rate, no current maturities are reflected. The borrowing base is redetermined on a semi-annual basis or at any time at Bank One's election. The next scheduled redetermination date is May 1, 1995. The Bank One credit facility is secured by substantially all of the Company's assets and incudes financial and default covenants standard in the industry. Pursuant to the terms of the Bank One credit agreement, the Company is required to maintain certain financial ratios including a current ratio of 1.2 to 1 after excluding certain liabilities and making other adjustments as allowed under the facility. After making such current ratio adjustments, the Company at December 31, 1994 was in compliance with the current ratio and other financial ratios and covenants. Though the Company has complied with all covenant requirements to date, there can be no assurance that it will be able to continue such compliance or that its borrowing base may not be significantly reduced during future redeterminations which could result in required principal reductions during 1995. At December 31, 1994, the non-recourse BMOF debt totaled $4,870,000, including total accrued interest of $218,000. The BMOF note is payable from NFG Litigation proceeds, if any, and all related interest is payable in kind through the issuance of additional notes until December 31, 1997, or for such further time as BMOF elects to extend maturity of such note. The Senior Preferred has a liquidation preference value of $10 per share and is redeemable in whole or in part at the option of the Company at any time at a price per share equal to the liquidation preference amount per share plus all accrued and unpaid dividends to the date of redemption. Subject to Delaware law, the Company must redeem all outstanding shares of Senior Preferred on or before January 21, 2002. The Senior Preferred is entitled to receive cumulative, compounded 10% annual dividends payable quarterly. Payment of the dividends on the Senior Preferred is mandatory if sufficient surplus funds (after reasonable reserves for capital budget items and working capital reserves) are legally available for such purpose. Until the Senior Preferred is fully redeemed, the Junior and Old Preferred Stock receive dividends payable in additional shares of Junior or Old Preferred Stock. For financial reporting purposes, the Senior Preferred has both debt and equity characteristics. Accordingly, it is not classified as a component of stockholders' equity. At December 31,1994, the Senior Preferred redemption value and accrued dividends were $87,282,000 and $26,454,000, respectively. This amount plus any additional accrued dividends must be satisfied before any value can be attributed to the holders of Old Preferred and Common Stock. At December 31,1994, the Stockholders' deficit was $43,711,000. Due to the dividend requirements for the Senior, Junior, and Old Preferred Stock and accretion of the redemption value of Senior Preferred, under the current capital structure, it is probable that the Company's Stockholders' equity will remain a deficit for the foreseeable future. LIQUIDITY AND CAPITAL RESOURCES For 1994, the Company's cash provided by operating activities was $11,999,000. The cash flow from operations was primarily due to 1994 property sales receivable collection. Substantially all of 1994's operating cash flow was dedicated to debt retirement. 24 The July 13, 1994 debt restructuring with BMO and establishment of a new line of credit with Bank One significantly improved the Company's liquidity while curing the BMO Events of Default. Based on the December 31, 1994 borrowing base of $2,070,000 and outstandings of $1,150,000, the Company had availability under the facility of $920,000. Amounts borrowed under the line of credit are due July 1997. In conjunction with applying the net proceeds related to the sale of assets to BBC, BMO reserved $300,000 for a TGX contingent liability under a letter of credit. In May 1994, the letter of credit amount was reduced by $150,000 and this amount was applied toward BMO obligations. The remaining $150,000 letter of credit was secured by cash and was released to the Company in February 1995. In 1994, a majority of the limited partner interests in two partnerships voted to appoint TGX as the liquidating trustee for the partnerships. As a result, TGX solicited offers to sell the oil and natural gas properties of the partnerships and subsequently accepted an offer to sell certain of the partnerships' oil and natural gas properties for $2.67 million. TGX's share of the liquidating cash distributions from the partnerships ($1.367 million) was applied toward BMO debt obligations. During 1994, the Company continued a program of reviewing the status of affiliated partnerships to determine whether or not the partnerships should be liquidated. Due to the limited remaining asset value for most of these partnerships and their ongoing administrative costs, substantially all of the partnerships will be liquidated. The Company liquidated 17 partnerships in 1994 through sales or foreclosure pursuant to Company held partnership notes and anticipates liquidating through sale the remaining eight public partnerships by mid-1995. As a result of the 1994 partnership liquidations, the Company obtained additional direct interests in related oil and natural gas properties having an estimated value of $381,000 and realized the recoupment of $751,000 of previously reserved receivables and notes. Liquidation of all remaining partnerships in 1995 will eliminate general and administrative reimbursements derived from such partnerships by the Company which should be offset by related administrative cost savings. Pursuant to the terms of various agreements, the Company, as a working interest owner, is responsible for marketing its share of natural gas production from certain properties. If the Company is unable or unwilling to market its share of natural gas production from a property, its under-produced status is subject to balancing with other working interest owners who have sold more than their proportionate share of natural gas production. On an aggregate net basis for certain natural gas properties, it appears that the Company is substantially under-produced and is conducting negotiations to recoup or otherwise settle its net under-produced status. The Company received approximately $634,000, net of expenses, as a result of such negotiations during the fourth quarter of 1994. The Company can give no assurance as to its ability to recoup or otherwise settle any additional net under-produced wells in the immediate future. In addition to the ongoing oil and gas production operations, a key factor in the Company's future will be the final resolution of the litigation with NFG. While the Company has attempted to commence settlement negotiations with NFG, to date no meaningful discussions have taken place. If a settlement cannot be reached, the Company intends to prosecute this litigation with every reasonable resource available to it. The outcome of the NFG Litigation, which may be many years away if a settlement cannot be reached, could materially affect the Company's future. Under the restructured BMO credit agreement, BMO's subsidiary will be entitled to receive the initial $4,652,000 of any settlement proceeds, plus interest, and in certain instances, BMO, after the Company has received the same initial amount paid to BMO, may be entitled to receive up to 50% of any additional settlement proceeds. Based on the Company's calculation, the gross price between the price actually paid by NFG and the price required by the New York Federal Court's order (assuming a contract price of $4.41 per Mcf for winter and $4.01 for summer) is approximately $23,912,000 as of December 31, 1994, including statutory interest. During 1995, the Company will continue to review its investment opportunities, consistent with its available capital, to determine if asset enhancement can be obtained either through development of existing proved developed non-producing reserves, drilling or acquisition. However, considering the Company's current financial position and the inability to predict (i) the outcome of the NFG Litigation and (ii) the success of any cost reductions, the Company cannot currently determine if it will be able to successfully implement its business plan and strategy. INFLATION AND CHANGES IN PRICES The Company's revenues have been and will continue to be affected by changes in oil and natural gas prices which have been unstable. For management purposes, the Company assumes that oil and natural gas prices will escalate at 5% per annum and that costs and expenses will escalate at 4% per annum. The principal effects of 25 inflation on the Company relate to the costs required to drill, complete and operate oil and natural gas properties. Such costs have also been on a general downward trend since the early 1980's due primarily to the industry-wide decrease in drilling activity and the Company's continuing efforts to monitor and reduce operating expenses. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. The Company's consolidated financial statements as of December 31, 1994 and 1993 and for each of the three years in the period ended December 31, 1994, and the reports of Price Waterhouse LLP, independent accountants, follow. 26 REPORT OF INDEPENDENT ACCOUNTANTS POST-EMERGENCE CONSOLIDATED FINANCIAL STATEMENTS To the Board of Directors and Stockholders of TGX Corporation In our opinion, the accompanying consolidated financial statements listed in the index appearing under Item 14(A)(1) and (2) on page 57 present fairly, in all material respects, the financial position of TGX Corporation and its subsidiaries (the Company) at December 31, 1994 and 1993, and the results of their operations and their cash flows for the years ended December 31, 1994 and 1993 and for the period from October 2,1992 to December 31, 1992, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. As discussed in Note 2 to the consolidated financial statements, on January 21, 1992, the United States Bankruptcy Court for the Western District Court confirmed the Company's Amended Plan of Reorganization (the Plan). The Plan was substantially consummated on October 2, 1992, and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start reporting. As a result of the adoption of fresh start reporting, the post-emergence consolidated financial statements are not comparable to the pre-emergence consolidated financial statements. The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 14 to the consolidated financial statements, the Company has a substantial accumulated deficit and has suffered recurring losses from operations, as well as cash flow deficits that raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also discussed in Note 14. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. As discussed in Notes 1 and 9 to the consolidated financial statements, on October 2, 1992, the Company changed its methods of accounting for oil and natural gas properties and income taxes. As discussed in Note 15, the Company has restated its 1994 financial statements to account for the Bank of Montreal ("BMO") debt conversion as a troubled debt restructuring. The BMO debt conversion was originally accounted for as an extinguishment of debt. PRICE WATERHOUSE LLP Houston, Texas March 28, 1995 except as to Note 15 which is as of January 3, 1997 27 REPORT OF INDEPENDENT ACCOUNTANTS PRE-EMERGENCE CONSOLIDATED FINANCIAL STATEMENTS To the Board of Directors and Stockholders of TGX Corporation In our opinion, the accompanying consolidated financial statements listed in the index appearing under Item 14(A)(1) and (2) on page 57 present fairly, in all material respects, the results of operations and cash flows of TGX Corporation and its subsidiaries (the Company) for the period from January 1, 1992 to October 1, 1992, in conformity with generally accepted accounting principles. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for the opinion expressed above. As discussed in Note 2 to the consolidated financial statements, on January 21, 1992, the United States Bankruptcy Court for the Western District Court confirmed the Company's Amended Plan of Reorganization (the Plan). The Plan was substantially consummated on October 2, 1992 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start reporting. As a result of the adoption of fresh start reporting, the post-emergence consolidated financial statements are not comparable to the pre-emergence consolidated financial statements. The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 14 to the consolidated financial statements, the Company has substantial accumulated deficit and has suffered recurring losses form operations, including a net loss before extraordinary gain for debt forgiveness in the current year, as well as cash flow deficits that raise substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also discussed in Note 14. the consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty. As discussed in Notes 1 and 9 to the consolidated financial statements, on October 2, 1992, the Company changed its methods of accounting for oil and natural gas properties and income taxes. PRICE WATERHOUSE LLP Houston, Texas March 28, 1995 28 TGX Corporation and Subsidiaries CONSOLIDATED BALANCE SHEET ================================================================================ (Restated - Note 15) December 31, ------------------------ (Thousands, except for share data) 1994 1993 - -------------------------------------------------------------------------------- ASSETS Current assets: Cash and cash equivalents $ 676 $ 1,220 Accounts receivable, net of allowance for doubtful accounts of $373 and $763, respectively 1,206 1,698 Accounts receivable from affiliates, net -Note 10 504 1,154 Net oil and natural gas properties held for sale - 15,128 Other current assets 60 148 - -------------------------------------------------------------------------------- Total current assets 2,446 19,348 - -------------------------------------------------------------------------------- Property and equipment: Oil and natural gas properties 10,407 11,434 Other property and equipment 157 442 Accumulated depletion, depreciation and amortization (3,307) (2,472) - -------------------------------------------------------------------------------- Property and equipment, net 7,257 9,404 - -------------------------------------------------------------------------------- Accounts and notes receivable from affiliates, net -Note 10 - 100 Investment in Comite Field Plant Venture -Note 5 878 1,015 Other assets 95 198 - -------------------------------------------------------------------------------- Total other assets 973 1,313 - -------------------------------------------------------------------------------- TOTAL ASSETS $ 10,676 $ 30,065 ================================================================================ LIABILITIES AND STOCKHOLDERS' DEFICIT Current liabilities: Accounts payable and accrued liabilities -Note 6 $ 3, 352 $ 7,556 Accounts payable to affiliates 242 101 Current maturities of long-term debt -Note 3 - 19,499 Notes payable 171 1,401 - -------------------------------------------------------------------------------- Total current liabilities 3,765 28,557 - -------------------------------------------------------------------------------- Long-term debt -Note 3 6,020 - - -------------------------------------------------------------------------------- Total liabilities 9,785 28,557 - -------------------------------------------------------------------------------- Commitments and contingencies -Note 4 Redeemable Senior Preferred Stock, 1,498,534 issued; 7,230,712 shares to be issued, redemption value $87,292,000 -Note 7 44,602 30,013 - -------------------------------------------------------------------------------- Stockholders' deficit: -Note 8 9% Cumulative Convertible Preferred stock, 300,000 shares issued plus 131,000 and 104,000, respectively, shares to be issued for dividends 431 404 Common stock, 28,976,791 shares issued; 25,313,533 outstanding 290 290 Additional paid-in capital 1,179 936 Accumulated deficit (45,611) (30,135) - -------------------------------------------------------------------------------- Total stockholders' deficit (43,711) (28,505) - -------------------------------------------------------------------------------- TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT $ 10,676 $ 30,065 ================================================================================ See accompanying notes to consolidated financial statements 29 TGX Corporation and Subsidiaries CONSOLIDATED STATEMENT OF OPERATIONS
Predecessor Reorganized Company(1) Company(1) ------------------------------------- -------------------------- (Restated - Note 15) October 2, January 1, Year Ended Year Ended through through December 31, December 31, December 31, October 1, (Thousands, except per share data) 1994 1993 1992 1992 - ------------------------------------------------------------------------------------------------------------------------------------ REVENUES Oil and natural gas production $ 4,802 9,730 $ 2,641 $ 6,501 Natural gas gathering 309 417 116 285 Share of earnings of natural gas treating plant 418 521 201 246 Gain on property sales, net 766 58 - - Other, net 182 271 35 2,798 - ------------------------------------------------------------------------------------------------------------------------------------ 6,477 10,997 2,993 9,830 - ------------------------------------------------------------------------------------------------------------------------------------ COSTS AND EXPENSES Operating expenses 3,188 3,935 1,003 2,965 Depletion, depreciation and amortization 1,414 2,995 916 1,884 Provision for loss on sale of assets - 12,415 - - Full cost ceiling adjustment - - - 1,505 General and administrative expenses 2,239 3,323 712 2,880 Interest 1,166 2,246 612 2,265 Reorganization expenses, net of post petition interest income - - - (400) - ------------------------------------------------------------------------------------------------------------------------------------ 8,007 24,914 3,243 11,099 - ------------------------------------------------------------------------------------------------------------------------------------ LOSS BEFORE INCOME TAXES AND EXTRAORDINARY GAIN (1,530) (13,917) (250) (1,269) Income tax expense - Note 9 17 - - - - ------------------------------------------------------------------------------------------------------------------------------------ NET LOSS BEFORE EXTRAORDINARY GAIN (1,547) (13,917) (250) (1,269) Extraordinary gain -Note 3 831 - - - - ------------------------------------------------------------------------------------------------------------------------------------ NET LOSS (716) (13,917) (250) (1,269) Preferred stock dividends, net (10,780) (10,139) (2,305) (3,647) Accretion of Senior Preferred redemption value (3,980) (2,895) (629) - - ------------------------------------------------------------------------------------------------------------------------------------ NET LOSS APPLICABLE TO COMMON STOCK $ (15,476) $ (26,951) $ (3,184) $ (4,916) ==================================================================================================================================== PER SHARE OF COMMON STOCK AMOUNTS: Before extraordinary gain $ (.64) $ (1.06) $ (.19) $ (.19) Extraordinary gain .03 - - - ------------------------------------------------------------------------------------------------------------------------------------ NET LOSS $ (.61) $ (1.06) $ (.13) $ (.19) ==================================================================================================================================== AVERAGE COMMON SHARES OUTSTANDING 25,314 25,314 25,314 25,314 ====================================================================================================================================
(1) As used herein, "Predecessor Company" means the operations of the Company prior to October 2, 1992, the effective date of the order regarding substantial consummation of the Amended Plan of Reorganization, and "Reorganized Company" means the operations of the Company subsequent to that date. See accompanying notes to consolidated financial statements 30 TGX Corporation and Subsidiaries CONSOLIDATED STATEMENT OF CASH FLOWS
Predecessor Reorganized Company (1) Company (1) ----------------------------------- ----------------------------- (Restated - Note 15) October 2, January 1, Year Ended Year Ended through through December 31, December 31, December 31, October 1, (Thousands, except per share data) 1994 1993 1992 1992 - ------------------------------------------------------------------------------------------------------------------------------------ Cash flows from operating activities: Net loss $ (716) $ (13,917) $ (250) $ (1,269) Adjustments to reconcile net loss to cash provided by operating activities: Depletion, depreciation and amortization 1,414 2,995 916 3,389 Amortization of debt issuance costs - - - 333 Provision for loss on sale of assets - 12,415 - - Non-cash recovery of affiliate receivable (381) - - - Recovery of accounts receivable loss provisions 751 - - - Interest to be paid through the issuance of additional notes 218 - - - Extraordinary gain (831) - - - Changes in operating assets an liabilities: Decrease in accounts receivable 492 17 100 917 (Increase) decrease in accounts due from/to affiliates, net 40 (531) (15) 781 (Increase) decrease in other current assets 15,128 222 (63) 126 Increase (decrease) in accounts payable and accrued expenses (4,204) 2,337 389 (561) Decrease in other assets 88 - - 232 - ------------------------------------------------------------------------------------------------------------------------------------ Net cash provided by operating activities 11,999 3,538 1,077 3,948 - ------------------------------------------------------------------------------------------------------------------------------------ Cash flows from investing activities: Capital expenditures (27) (394) (79) (154) Disposal of assets, net 1,406 14 - 402 Consideration from disposition of Consummation Collateral - - - 2,286 Decrease (increase) in other assets 74 383 18 (5) - ------------------------------------------------------------------------------------------------------------------------------------ Net cash provided (used) by investing activities 1,453 3 (61) 2,529 - ------------------------------------------------------------------------------------------------------------------------------------
See accompanying notes to consolidated financial statements 31 TGX Corporation and Subsidiaries CONSOLIDATED STATEMENT OF CASH FLOWS (Continued)
Predecessor Reorganized Company(1) Company(1) ------------------------------------- ---------------------------- (Restated - Note 15) October 2, January 1, Year Ended Year Ended through through December 31, December 31, December 31, October 1, (Thousands, except per share data) 1994 1993 1992 1992 - ------------------------------------------------------------------------------------------------------------------------------------ Cash flows from operating activities: Debt issuance costs - - - (1,250) Principal payments of long-term debt and notes payable (16,301) (3,799) (822) (4,041) Payment of pre-petition liabilities and administrative claims - - (635) (4,291) Advances pursuant to Revolving Credit Facility 1,975 90 - 550 Debt transaction costs and other 230 - - - Decrease in affiliate accounts receivable 100 - - - Proceeds related to term loans pursuant to Amended Credit Agreement - - - 1,442 Notes payable issued to administrative claimants - 91 (24) 2,005 - ------------------------------------------------------------------------------------------------------------------------------------ Net cash used by financing activities (13,996) (3,618) (1,481) (5,585) - ------------------------------------------------------------------------------------------------------------------------------------ Net increase (decrease) in cash and cash equivalents (544) (77) (465) 892 Cash and cash equivalents at beginning of period 1,220 1,297 1,762 870 - ------------------------------------------------------------------------------------------------------------------------------------ Cash and cash equivalents at end of period $ 676 $ 1,220 $ 1,297 $ 1,762 ==================================================================================================================================== Supplemental Disclosure of Non-Cash Investing and Financing Activities: Properties acquired through foreclosure of affiliated partnerships $ 381 $ - $ - $ - Forgiveness of notes payable 831 - - - Interest to be paid through issuance of additional notes 218 - - -
See accompanying notes to consolidated financial statements 32 TGX Corporation and Subsidiaries NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1994, 1993 and 1992 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Business and Reorganization Proceeding TGX Corporation (''TGX") (collectively with its subsidiaries, the "Company"), is a domestic independent energy company engaged in the production of oil and natural gas. The Company is also engaged in intrastate natural gas gathering and treating. As discussed in Note 2, on February 22,1990, TGX filed a voluntary petition for reorganization pursuant to Chapter 11 of the Bankruptcy Code. TGX's then wholly owned subsidiaries, LEDCO, TGX Finance Corporation, Diablo Farms, Inc., and Templeton Energy Income Corporation, did not file petitions for reorganization under the Bankruptcy Code nor did any of the limited or general partnerships for which TGX serves as general partner. On January 7, 1992, the Bankruptcy Court confirmed an Amended Plan of Reorganization (the "Plan") for TGX and on October 2,1992 an order of substantial consummation regarding the Plan became final and nonappealable. Accordingly, the Company implemented fresh start reporting as of October 2, 1992. The consolidated financial statements have been prepared on a going concern basis, which contemplates continuity of operations and realization of assets and liquidation of liabilities in the ordinary course of business. Principles of Consolidation The accompanying consolidated financial statements include the accounts of TGX and its subsidiaries. All significant intercompany accounts and transactions have been eliminated. The Company accounts for its investments in limited and general partnerships under the proportionate consolidation method. Under this method, the Company's financial statements include its pro-rata share of assets, liabilities, revenues, and expenses of the limited and general partnerships in which it owns beneficial interests. The Company's 35% investment in a natural gas treating plant (Note 5) is accounted for using the equity method. Oil and Natural Gas Properties In conjunction with the implementation of fresh start reporting, as described in Note 2, the Company also implemented the successful efforts method of accounting for oil and natural gas operations. Under the successful efforts method, capitalized cost relating to proved properties are amortized based on proved reserves using the unit-of-production method. In 1994, management determined that as a result of the Company's improving financial condition, including expected cash flow for 1995 and beyond, that it could fund development of its oil and gas reserves which had previously not been classified as proved undeveloped. Accordingly, in 1994 the Company treated these reserves as proved for purposes of accounting estimates and financial statement disclosure. As a result of utilizing total proved reserves in the calculation, depletion, depreciation and amortization for 1994 was reduced by $847,000. The cost of unsuccessful exploration wells is charged to operations. If an assessment indicates that an unproved property has been impaired, a loss is recognized by providing a valuation allowance. Net capitalized costs in excess of future net revenues, adjusted for tax effects, are charged to operations in the year during which such excess occurs. Generally, a gain or loss is recognized on the disposition of a property. Prior to the implementation of fresh start reporting, the Company followed the full-cost method of accounting for its oil and natural gas operations, and accordingly, it capitalized all costs incurred in connection with the acquisition, exploration and development of oil and natural gas properties, whether productive or nonproductive. These capitalized costs comprised the full- cost pool which was depreciated and depleted over the life of the estimated proved reserves using the unit-of-production method. Any capitalized costs in excess of the present value of proved oil and gas reserves were expensed in the year in which such excess was determined. The Company concluded that the successful efforts method was more appropriate than the full-cost method since it would result in a better matching of oil and natural gas revenues with the related exploration and production costs and expenses. 33 Other Property and Equipment Depreciation of other property and equipment is provided on the straight-line method over the estimated useful lives of the related assets, which range from 3 to 25 years. Revenue Recognition Revenue from the sale of crude oil is recognized upon the passage of title, net of royalties. Revenue from natural gas production is recognized using the sales method, net of royalties. Pursuant to the terms of various agreements, the Company, as a working interest owner, is responsible for marketing its share of natural gas production from certain properties. If the Company is unable or unwilling to market its share of natural gas production from a property, its under-produced status is subject to balancing with other working interest owners who have sold more than their proportionate share of natural gas production. On an aggregate net basis for certain natural gas properties, it appears that the Company is in an under-produced status and is currently recouping or attempting to settle its net under-produced status. Any balancing recoupments or settlements, which will typically be over a period of time, are not anticipated to be material to future operating results. Cost and Expense Reimbursements Pursuant to the provisions of the applicable agreements, the Company reduces its general and administrative expenses by reimbursements for certain administrative and operating costs paid or incurred in connection with the administration and operation of oil and natural gas properties and limited and general partnerships which are sponsored by the Company. Income Taxes In February 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 109 -"Accounting for Income Taxes" which requires an asset and liability approach for the financial accounting of income taxes based on the differences that can occur between the tax bases of assets or liabilities and their reported amounts in financial statements. In conjunction with the implementation of fresh start reporting, the Company also adopted this method of accounting for income taxes. Per Share Amounts Per share amounts are determined by dividing net income or loss applicable to Common Stock by the weighted average number of common shares outstanding during the year. In 1994, 1993 and 1992 the dilutive effect, if any, of the assumed conversion of preferred stock to common stock was considered for the computation of fully diluted income or loss per common share and such assumed conversion was not material to the computation. The assumed exercise of outstanding stock options was not included in the computation of per share amounts as their effect was not dilutive. Cash and Cash Equivalents Cash includes cash on-hand and cash in interest-bearing accounts with original maturities of 90 days or less. Reclassifications Certain amounts from prior years have been reclassified to conform to the current year presentation. 2. REORGANIZATION PROCEEDING On February 22, 1990, TGX filed a voluntary petition in the United States Bankruptcy Court for the Western District of Louisiana, Shreveport Division (the "Bankruptcy Court"), for reorganization pursuant to Chapter 11, Title 11 of the United States Code (the "Reorganization Proceeding"). During the balance of 1990, all of 1991 and a portion of 1992, TGX operated as debtor-in- possession, continuing in possession of its estate and the operation of its business and management of its property. On January 7, 1992, the Bankruptcy Court confirmed an amended Plan of Reorganization ("Plan") for TGX, and the confirmation order became effective on January 21,1992 (the "Effective Date"). On September 21,1992, the Bankruptcy Court determined that the Plan had been substantially 34 consummated, and the Bankruptcy Court's order of substantial consummation became final and nonappealable on October 2, 1992. As a result of the substantial consummation of the Plan and due to (i) the reallocation of the voting rights of equity interests owners and (ii) the reorganization value of TGX's assets being less than the total of all post- petition liabilities and allowed claims at October 2, 1992, the effects of the Reorganization Proceeding were accounted for in accordance with the fresh start reporting standards promulgated under the American Institute of Certified Public Accountants Statement of Position 90-7 "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code" ("SOP 90-7"). In conjunction with implementing fresh start reporting, a reorganization value ("RV") of the Company's assets and liabilities as of October 2, 1992 was determined by management in the following manner: The RV of proved oil and natural gas properties and other related assets was determined based on future net revenues discounted to present value utilizing a rate of 20%. For proved undeveloped properties, the RV was determined to be 50% of discounted future net revenues. For the purpose of calculating future net revenues of oil and natural gas properties, then current oil and natural gas prices were escalated at five percent per annum to certain maximum amounts and then current operating costs and expenses were escalated at four percent per annum for the economic life of the properties. The initial price for natural gas dedicated under the contract (the "Contract") with National Fuel Gas Distribution Corporation ("NFG"), which is currently a matter being litigated, was equal to 90% of the rolling twelve month average price for No. 6 fuel oil in the Buffalo, New York area (the "90% of No. 6 Fuel Oil Price"). The RV of oil and natural gas properties also included $2,905,000 attributable to the difference, plus interest, between the price that NFG paid since September 1984 and the 90% of No. 6 Fuel Oil Price. Current assets and liabilities were recorded at book value which approximates RV. Long-term liabilities were recorded at present values of amounts to be paid and the pre-consummation stockholders' deficit was adjusted to reflect the par value of pre-consummation equity interests. The recorded value of the Series A Senior Preferred Stock (the "Senior Preferred") to be issued pursuant to the Plan was determined based on the difference between the RV of the Company's assets less the sum of (i) the present value of liabilities plus (ii) the par value of pre-consummation equity interests. The accretion of the difference between the recorded value and the $10 per share redemption amount of the Senior Preferred will be recorded as a reduction of income applicable to common stockholders over a period of approximately 10 years. The RV was determined by management on the basis of its best judgment of what it considered to be the fair market value ("FMV") of the Company's assets and liabilities at the time of the valuation after reviewing relevant facts concerning the price at which similar assets were being sold between willing buyers and sellers. However, there can be no assurances that the RV and the FMV are comparable and the difference between the Company's calculated RV and the FMV may, in fact, be material. Pursuant to the provisions of the Plan, TGX provided for (i) the payment in full of its secured debt by the issuance of new notes pursuant to the terms of a restructured credit agreement, (ii) the conversion of substantially all of its unsecured debt into two different series of preferred stock, (iii) tax and priority and certain other specified classes of claims and interests arising from options for common stock being paid in cash, retained or otherwise provided for, and (iv) administrative claims being paid in cash or otherwise being satisfied. Three of the large administrative claimants (the "Opposing Administrative Claimants") agreed that in full satisfaction of the balance of their administrative claims they would receive (i) a payment of $300,000 (ii) 55,000 shares of Senior Preferred and (iii) the conveyance of approximately 29,400 acres of undeveloped land in Culberson and Hudspeth Counties, Texas. In satisfaction of their unpaid administrative claims, all other administrative claimants received cash and/or were entitled to receive promissory notes due December 31, 1994 which were secured by certain assets of the Company. Such notes were to be issued upon the execution of releases in favor of the Company and others. As set forth in Note 3 below, administrative claimants received, in 1994, $150,000 as partial repayment of their notes prior to September 30, 1994. Commencing in October 1994, the Company re-negotiated the terms of the notes with certain administrative claimants and paid $389,000 in cash, issued 141,518 shares of Senior Preferred and also issued its non-recourse note in the amount of $90,000 payable out of proceeds if any, 35 from the NFG Litigation described in Note 4 below, in full satisfaction of administrative notes with an aggregate of $1,220,000 in principal and interest due at the time of renegotiation. The Company has continued to negotiate the terms of the remaining outstanding administrative claims. TGX was a party to numerous executory contracts which, pursuant to the provisions of the Bankruptcy Code, could be assumed or rejected by TGX. If an executory contract was assumed by TGX, all defaults related to the executory contract were cured (generally, paid-in-full with cash). Currently, the aggregate balance of pre-petition obligations related to assumed executory contracts is approximately $317,000 which is related to undistributed net oil and gas revenues which is in a "suspended pay" status. If an executory contract was rejected by TGX, all claims related to the executory contract were satisfied pursuant to the terms of the Plan. As of the Effective Date, the preferred and common stockholders selected a new Board of Directors (the "New Board") comprised of eight individuals to serve until January 21, 1995 or until their successors were duly elected and qualified. The New Board consisted of five members selected by holders of claims to be satisfied with Senior Preferred (one of which cannot be an affiliate of any holder of the Senior Preferred), two members selected by holders of Series B Preferred Stock, 9% Cumulative Convertible Preferred Stock and the holders of Common Stock acting as one class, and the final member is the chief executive officer of TGX. Subsequent to the Effective Date, two members of the Board of Directors resigned and have not been replaced. Subsequent to January 21,1995, the eight members of the Board of Directors will be elected by all of the Preferred and Common Stockholders voting as one class with the exception that, pursuant to the terms of the Senior Preferred, since the Company has failed to pay six quarterly dividends, at the next Annual Meeting, the Board of Directors will be increased to ten and Senior Preferred Stockholders voting alone will be entitled to select two additional Directors. The remaining Directors will be elected by all stockholders voting as a class. Senior Preferred stockholders have 95% of the voting power of all of the stockholders of the Company. The Senior Preferred has a $10 per share redemption value and has a provision for a 10% annual compounded cash dividend, payable quarterly, provided however, that the payment of such dividend does not violate Delaware law or certain loan covenants. The Company has not paid any of the dividends since the Effective Date of the Plan and based on the current financial position of the Company, does not expect to make any such dividend payments in the near future. Subject to Delaware law, the Senior Preferred must be redeemed no later than January 21, 2002. 3. LONG-TERM DEBT AND NOTES PAYABLE As of December 31, 1994 and 1993, the components of long-term debt were: ------------------------------------------------ (Thousands) 1994 1993 ------------------------------------------------ Bank borrowings: Term loans (secured) $ - $ 19,209 Revolving credit (secured) 1,150 290 Non-recourse note 4,870 - ------------------------------------------------ 6,020 19,499 Less current maturities - (19,499) ------------------------------------------------ Long-term debt $ 6,020 $ - ================================================ On July 13, 1994, the Company entered into a series of agreements with Bank One, Texas N.A. ("Bank One") whereby the Company's then outstanding secured debt with the Bank of Montreal ("BMO") was restructured and all existing BMO events of default were resolved. Pursuant to the restructuring, Bank One established a borrowing-based facility of $2,350,000 under which the Company immediately borrowed $1,600,000 of which $1,452,000 was paid to BMO. The Bank One facility bears interest at Bank One's stated rate plus two percent and is secured by substantially all of the Company's oil and gas properties. The Bank One facility at December 31,1994 had a borrowing base of $2,070,000 which is reduced by $56,000 per month and is redetermined every six months or at Bank One's discretion. The loan is repayable over 36 months and matures July 13, 1997. The Bank One facility requires the maintenance of certain financial ratios including a working capital ratio, after excluding certain liabilities and other adjustments as allowed under the facility, of 1.2 to 1 and a tangible net worth, including Senior Preferred stock, of a minimum of $5 million, and other financial ratios. The Company was in compliance with all financial ratios and covenants at December 31, 1994, but can give no assurance that it will be able to continually meet the Bank One facility ratios and covenants. 36 Simultaneously with the securance of the Bank One facility, BMO released all of its liens on the Company's properties with the exception of its lien on the Company's currently pending litigation with NFG ("NFG Litigation"). See Note 4 below. Prior to restructuring its debt through receipt of the Bank One facility, the Company had been subject to the terms of an Amended and Restated Credit Agreement (the "Amended Credit Agreement') with BMO which was entered into in February 1992 and amended thereafter and which essentially continued and preserved the prior revolving credit agreement. Effective December 31,1992, the Company had been notified by BMO that an event of default had occurred under the Amended Credit Agreement, and as a result, BMO had the right to take certain actions under such Amended Credit Agreement including, but not limited to, the acceleration of all of the then outstanding BMO obligations. Pursuant to the terms of the Amended Credit Agreement, as of December 31, 1993, the Company had borrowings outstanding of $19,499,000 of which $9,316,000 bore interest at the BMO prime rate plus 1.5%, $10,000,000 bore interest at 13%, and $183,000 bore no interest. In January 1994, in conjunction with the Company's sale of certain assets to Belden & Blake Corporation ("BBC"), the Company made a debt service payment of approximately $13,367,000 which included principal payments totaling $10,670,000 to BMO. The Company also made subsequent BMO principal payments of $2,949,000 before July 13, 1994. As set forth above, on July 13, 1994, in connection with the series of agreements entered into between the Company and Bank One, the Company paid approximately $1,452,000 to BMO which included a principal payment of $1,424,000 and simultaneously therewith, BMO released all of its liens on the Company's properties with the exception of its lien on the Company's currently pending NFG Litigation. As part of the loan restructuring, BMO converted $4,652,000 (the "BMOF Principal") of its outstanding indebtedness, including legal transaction costs incurred by BMO, to a non-recourse note secured only by the NFG Litigation and any proceeds that might be received therefrom. BMO assigned its rights to the loan, security, and the Company's note to BMO's wholly owned subsidiary, BMO Financial, Inc. ("BMOF"). Pursuant to agreement, after repayment of the outstanding BMOF Principal, plus applicable interest, from NFG Litigation proceeds, if any, BMOF will, in certain instances, after the Company has received the same amount as was paid to BMOF, be entitled to receive up to 50% interest in certain additional litigation proceeds. If NFG Litigation proceeds are insufficient to repay the BMOF Principal, plus applicable interest, the Company will have no further obligation for such repayment. The BMOF note matures on December 31,1997, subject to each party having the right to extend the maturity date and bears interest at the rate of 10% per annum. However, until December 31, 1997, and for such further time as BMOF elects to extend the maturity date of such loan, no cash payment for such interest is required; instead, the Company will pay interest in kind through the issuance of additional notes to BMOF. As of December 31, 1994, total accrued interest pursuant to the BMOF note was $218,000 resulting in total BMOF debt of $4,870,000. Due to the complexities of the NFG Litigation and the significant uncertainties therewith, the ultimate amount of NFG Litigation proceeds cannot be reasonably estimated. During the Reorganization Proceeding, the Company incurred and claimants filed applications for approximately $7,131,000 in administrative fees and expenses relating to the reorganization ("Administrative Claims"). The Company objected to certain of the Administrative Claims and negotiated settlement amounts and terms of payment with certain holders of Administrative Claims. As a result, administrative claimants, other than the Opposing Administrative Claimants, upon execution of certain releases in favor of the Company and others, were entitled to receive promissory notes (the "Administrative Notes") due December 31,1994 in satisfaction of each of their unpaid administrative claim. Substantially all administrative claimants entitled to receive Administrative Notes perfected their claims by executing such releases. The Administrative Notes bear interest at a rate not to exceed 8% and are secured with certain collateral (the "Consummation Collateral"). If the proceeds related to the Consummation Collateral are not sufficient to satisfy the Company's obligations under the Administrative Notes the Company's excess operating funds, if any, will be applied toward the balances due. During the last quarter of 1994, the Company negotiated with substantially all of those persons holding Administrative Notes. As a result, Administrative Notes totaling approximately $990,000 in principal and $230,000 in accrued interest were renegotiated with the Company paying in the aggregate $389,000 in cash, issuing 141,518 shares of Senior Preferred Stock and further issuing its non-recourse note in the aggregate amount of $90,000 payable out of proceeds, if any, received by the Company from the NFG Litigation. As a result of Administrative Notes renegotiations, the Company secured forgiveness of $831,000 of such notes and accordingly reflected an extraordinary gain of that amount. Cash basis interest expense paid during 1994, 1993 and 1992 totaled approximately $3,364,000, $774,000, and $1,050,000 respectively. 37 4. COMMITMENTS AND CONTINGENCIES NFG Litigation Since November 30, 1984, TGX has been involved in litigation in the United States District Court for the Western District of New York ("New York Federal Court") (Civ. No. 84-1372-E) with NFG concerning the validity of a contract (the "Contract") pursuant to which TGX (as successor-in-interest to Paragon Resources, Inc. ("Paragon"), the original contracting party) sells certain natural gas production to NFG. The litigation addresses, among other things, the continued validity of the Contract, the price for natural gas sold, and certain take-or-pay claims. In December 1983, certain pricing provisions of the Contract were disapproved by the New York Public Service Commission ("PSC") and as a result, in January 1991, the New York Federal Court determined that the Contract was invalidated. However, on December 3, 1991, the Court of Appeals for the Second Circuit ("Court of Appeals") (Case No. 91-7127) reversed the New York Federal Court and held that the Contract remains in effect subject to the pricing provisions set forth therein. The Court of Appeals remanded the case to the New York Federal Court for further proceedings not inconsistent with the opinion of the Court of Appeals. During the Reorganization Proceeding, TGX filed an adversary proceeding (the "Turnover Proceeding") in the Bankruptcy Court to compel NFG to pay the amount due to TGX pursuant to the provisions of the Contract. Effective June 19,1992, TGX and NFG entered into a partial settlement agreement regarding the settlement of some, but not all, of their disputes. Pursuant to the provisions of the partial settlement agreement, in consideration of a payment of $2,940,000 (the "Payment") from NFG, which is reflected in Other Revenues for the period January 1 through October 1,1992, TGX (i) dismissed the Turnover Proceeding without prejudice (ii) released NFG (subject to certain limitations) from any and all liability and affirmative claims for relief alleged to arise from or based upon certain evidence presented by TGX in the Turnover Proceeding, and (iii) reserved its rights regarding the assumption or rejection of certain other relatively minor gas purchase agreements with NFG. The Payment will be credited against any amount due to TGX from NFG. In July 1992, the New York Federal Court denied a motion filed by NFG for partial summary judgment wherein NFG sought a finding that it had properly suspended performance under, and eventually terminated, the Contract. A subsequent rehearing upheld this conclusion, but determined that certain matters relating to this issue were questions of fact that cannot be resolved by summary judgment. In December 1992, NFG filed a motion with the PSC requesting a hearing to determine pricing issues related to the Contract. In 1993, the PSC determined that it would hold the requested hearing, and in November 1994, the Administrative Law Judge ("ALJ") appointed by the PSC issued a preliminary Recommended Decision stating that the PSC should find that, from December 20,1983 through November, 1992, the maximum contract price that would be just and reasonable within the meaning of the Public Service Law has been $3.714 per Mcf of gas. The ALJ also recommended that the Commission should determine only NFG's entitlement to cost recovery from its customers, and should not adjudicate the respective rights of TGX and NFG vis-a-vis one another. TGX, NFG and the staff of the PSC have filed exceptions to the ALJ's recommended rulings, but, the PSC had not ruled on the recommended decision or the filed exceptions prior to March 1, 1995. In January 1993, the New York Federal Court granted TGX's motion for partial summary judgment regarding the price to be paid under the Contract. Based on the New York Federal Court's order, TGX has concluded that from December 1983, until at least, January 1, 1993, the date Federal price controls were terminated, the Contract price is equal to the lower of (i) the applicable maximum lawful price for December 1983 and for each month thereafter as established by the Natural Gas Policy Act ("NGPA") subject to the escalations provided by the NGPA or (ii) the December 1983 permitted Contract price of approximately $4.41 per MCF. The Federal Court's decision might be interpreted such that the December 1983 permitted contract price would be $4.41 per Mcf during the winter months and $4.01 per Mcf during the summer months. Based on TGX's calculations, the gross difference between the price actually paid by NFG and the price required by the New York Federal Court's order (assuming a contract price of $4.41 for winter and $4.01 for summer per Mcf) is approximately $23,912,000 as of December 31,1994, including permitted statutory interest. The New York Federal Court's order did not determine the impact of the termination of the NGPA, the effect of any subsequent PSC order or NFG's defense, including the alleged repudiation by TGX of the NFG contract. As part of its sale of substantially all of its oil and gas properties in Ohio and New York to BBC, TGX assigned the Contract effective December 1, 1993. TGX's assignment of the contract did not include TGX's rights in its existing claims against NFG, any proceeds therefrom, and TGX's rights, claims or causes of action, even if they had not yet been asserted, that arose prior to the effective time of the assignment. 38 In November 1994, the New York Federal Court appointed a Magistrate to review and hear various aspects of the Federal Court Litigation, including certain motions, scheduling, and certain pre-trial discovery. In early 1995, in anticipation of the issuance of a decision by the PSC in March 1995, the Magistrate held that all discovery would be stayed pending a further meeting with the Magistrate in May 1995 to discuss the state of the case. New York Department of Environmental Conservation In January 1990, the New York State Department of Environmental Conservation, Division of Mineral Resources ("DEC") notified TGX that it considered TGX to be in violation of certain provisions of the environmental conservation laws of the State of New York concerning approximately 150 natural gas wells and production facilities located in Chautauqua and Erie Counties. To settle this dispute, TGX entered into a consent order (the "Agreed Order"), which among other things required TGX to provide a letter of credit in the amount of $300,000 which was to be utilized by the DEC if TGX did not comply with the Agreed Order. The letter of credit was provided by BMO but was secured by $300,000 in cash. Such security is released as the letter of credit is reduced or eliminated. In May 1994, the DEC agreed to reduce the letter of credit amount to $150,000 and a like amount of cash collateral was released. In February 1995, TGX's obligation to maintain the letter of credit was eliminated and the remaining cash collateral released. Other In August 1992, certain unleased mineral interest owners commenced a legal action against TGX, as operator of certain wells, in the 19th Judicial District Court for East Baton Rouge Parish, Louisiana (Case Number 383844, Division "A"). The complaint alleges that revenues in excess of the reasonable costs of drilling, completing, and operating certain wells have not been credited to the interests of the unleased mineral interest owners. This case is in the discovery stage and if settlement negotiations are not successful, TGX will vigorously defend itself in the litigation. In March 1994, a hearing was conducted in the Bankruptcy Court regarding the final allowance of pre-petition and administrative claims related to an overriding royalty interest previously conveyed by TGX. As a result of this hearing, the Bankruptcy Court established the method for computing these claim amounts. The parties stipulated that the finally allowed pre-petition claim amount was $600,000 which has been satisfied with the issuance of Senior Preferred. Previously, the Company had estimated this claim amount and therefore it had been included in the financial statements for prior years. Pursuant to the Bankruptcy Court's order, certain post-petition but prior to October 2, 1992 claims are to be treated as administrative claims. The administrative claim amount will be calculated by the claimant, subject to review and approval by the Company, and pursuant to the terms of the Plan. Any claims subsequent to October 2, 1992 are subject to the Bankruptcy Court's review, including ownership of the overriding royalty interest. From time to time, in the normal course of business, the Company is a party to various other litigation matters the outcome of which, to the extent not otherwise provided for, should not have a material adverse effect on the Company. Leases As of December 31, 1994, the Company's only lease commitment was for the remaining term of its office lease for 1995 and 1996 of $83,000 and $7,000, respectively. During 1994, the Company canceled its capitalized computer lease due to the out sourcing of certain financial operations. 5. INVESTMENT IN NATURAL GAS TREATING PLANT In conjunction with the acquisition of Amarex, Inc. in 1985, the Company acquired an interest in the Comite Field Plant Venture (the "Venture"), an Oklahoma general partnership formed in April 1982 for the purpose of constructing and operating a natural gas treating plant to serve the Comite Field in East Baton Rouge Parish, Louisiana. Natural gas produced from wells operated by the Company and one other operator is transported to the plant where contaminants are extracted to satisfy pipeline specifications. In addition, the plant also provides condensate handling 39 and saltwater disposal facilities. The Company receives cash distributions from the Venture for its share of net cash flow. A summary of the Venture's unaudited financial position as of December 31,1994,1993, and 1992 and the results of its operations for each of the three years in the period ended December 31, 1994, is: (Unaudited) =============================================================== (Thousands) 1994 1993 1992 --------------------------------------------------------------- SUMMARY BALANCE SHEETS Current assets $ 869 $ 438 $ 490 Net property and equipment 2,169 2,650 3,123 --------------------------------------------------------------- $ 3,038 $ 3,088 $ 3,613 =============================================================== Current liabilities $ 380 $ 76 $ 322 Long-term debt 150 200 - Partners' capital 2,508 2,812 3,291 --------------------------------------------------------------- $ 3,038 $ 3,088 $ 3,613 =============================================================== SUMMARY STATEMENTS OF EARNINGS Fees earned $ 2,327 $ 2,767 $ 2,579 Operating expenses 1,142 1,284 1,307 --------------------------------------------------------------- Operating income 1,185 1,483 1,272 Other income 11 7 4 --------------------------------------------------------------- Net income $ 1,196 $ 1,490 $ 1,276 =============================================================== 6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES As of December 31, 1994 and 1993, the primary components of accounts payable and accrued expenses were (in thousands): 1994 1993 ---- ---- Accounts payable $ 489 $ 664 Undistributed net oil and natural gas revenue 1,069 1,584 Accrued interest and fees 32 3,408 Accrued pre-petition liabilities 934 926 Miscellaneous accruals 828 974 ------- ------- $ 3,352 $ 7,556 ======= ======= 7. REDEEMABLE SENIOR PREFERRED STOCK The Company is authorized to issue 10,000,000 shares of Series A Redeemable Senior Preferred Stock ("Senior Preferred") with a par value of $1 per share. The Senior Preferred entitles its holders to receive a 10% annual compounded cash dividend, payable quarterly, provided however, that the payment of such dividend does not violate Delaware law or certain covenants in the Company's bank loan agreements. The Company has not paid any of the quarterly dividends required to date and based on the Company's current financial position does not expect to make any such dividend payments in the near future. The Senior Preferred have a liquidation preference of $10 per share and have priority over the liquidation preference afforded the holders of Series B Preferred Stock (the "Junior Preferred"), 9% Cumulative Convertible Preferred Stock (the "Old Preferred") and Common Stock. The Senior Preferred are scheduled to be redeemed on January 21,2002 ("Redemption Date"). On a monthly basis, the accretion of the difference between the recorded value and the redemption amount of the Senior Preferred is reflected as a reduction of income applicable to common stockholders. Since the Senior Preferred have both debt and equity characteristics it is not classified as a component of equity. Holders of Senior Preferred have 95% of the voting rights of the Company with the remaining 5% of voting rights being allocated collectively among the holders of the Junior Preferred, Old Preferred and Common Stock. Pursuant to the Plan, the Company provided for a total of 8,529,246 shares to be issued to holders of certain unsecured claims on the basis of one share of Senior Preferred for every $10 of certain finally allowed or otherwise agreed upon claim. During 1992, an additional 200,000 shares were issued to an executive officer pursuant to a management agreement. As of December 31, 1994, 1,498,534 Senior Preferred shares have actually been issued. 40 All remaining shares are anticipated to be issued during 1995 as a result of a compromise settlement with the Senior Subordinated Notes holder trustee in late 1994. In conjunction with fresh start reporting, the Senior Preferred was recorded at a value of $11,046,000 which is $76,246,000 less than its redemption value. The Company recorded in 1994 and 1993 $99,000 and $134,000, respectively, of stock compensation expense related to the 1992 management agreement. Stock compensation expense is amortized over the stock award forfeiture period of two years from grant date. For stock compensation expense recognition purposes the 1992 award was valued at $1.50 per share, based on an internal estimate of Company net assets as of October 2, 1992 (fresh start reporting). Since December 31,1991, the components of the number of shares of the Company's Senior Preferred and changes in associated values are as follows (in thousands): ----------------------------------------------------------------------- Number Recorded of shares Value ----------------------------------------------------------------------- Balance, December 31, 1991 - $ - Shares to be issued net of effect of fresh start reporting 8,729 11,046 Accrued and unpaid dividends - 5,440 Accretion on redemption value and dividends - 629 ----------------------------------------------------------------------- Balance, December 31, 1992 8,729 17,115 Accrued and unpaid dividends 9,869 Accretion on redemption value and dividends 2,895 Amortization of compensation shares pursuant to management agreement 134 ----------------------------------------------------------------------- Balance, December 31, 1993 8,729 30,013 Accrued and unpaid dividends 10,510 Accretion on redemption value and dividends 3,980 Amortization of compensation shares pursuant to management agreement 99 ----------------------------------------------------------------------- Balance, December, 1994 8,729 $ 44,602 ======================================================================= 8. STOCKHOLDERS' EQUITY (DEFICIT) Since December 31,1991, the components of the number of shares of the Company's stockholders' equity (deficit) and the changes therein are: ---------------------------------------------------------------------- Old Preferred Common Treasury (Thousands of shares) Stock Stock Stock ---------------------------------------------------------------------- Balance, December 31, 1991 300 28,977 (3,663) Dividends on Old Preferred Stock 77 - - Effect of fresh start reporting - (3,663) 3,663 ---------------------------------------------------------------------- Balance, December 31, 1992 377 25,314 - Dividends on Old Preferred Stock 27 - - ---------------------------------------------------------------------- Balance, December 31, 1993 404 25,314 - Dividends on Old Preferred Stock 27 - - ---------------------------------------------------------------------- Balance December 31, 1994 431 25,314 - ====================================================================== 41 Since December 31, 1991, the components of the Company's stockholders' equity (deficit), and the changes therein are:
- ------------------------------------------------------------------------------------------------------------------------------------ Old Additional Retained Preferred Common Paid-In Earnings Treasury (Thousands) Stock Stock Capital (Deficit) Stock - ------------------------------------------------------------------------------------------------------------------------------------ Balance, December 31, 1991 $ 300 $ 290 $ 89,409 $(147,088) $ (8,348) Post-petition dividends on Old Preferred, payable with additional shares of Preferred 70 - 633 (203) - Dividends on Senior Preferred - - - (6,075) - Discount on Senior Preferred dividends - - - 2,631 - Net loss - - - (1,269) - Effect of fresh start reporting - - (89,409) 152,004 8,348 - ------------------------------------------------------------------------------------------------------------------------------------ Balance, October 2, 1992 370 290 633 - - Post-petition dividends on Old Preferred, payable with additional shares of Old Preferred 7 - 60 (67) - Dividends on Senior Preferred, net - - - (2,238) - Accretion of Senior Preferred redemption value - - - (629) - Net loss - - - (250) - - ------------------------------------------------------------------------------------------------------------------------------------ Balance, December 31, 1992 377 290 693 (3,184) - Preferred dividends, payable with additional shares of Old Preferred 27 - 243 (270) - Dividends on Senior Preferred, net - - - (9,869) - Accretion of Senior Preferred redemption value - - - (2,895) - Net loss - - - (13,917) - - ------------------------------------------------------------------------------------------------------------------------------------ Balance, December 31, 1993 404 290 936 (30,135) - Preferred dividends, payable with additional shares of Old Preferred 27 - 243 (270) - Dividends on Senior Preferred, net - - - (10,510) - Accretion of Senior Preferred redemption value - - - (3,980) - Net loss - - - (716) - - ------------------------------------------------------------------------------------------------------------------------------------ Balance, December 31, 1994 $ 431 $ 290 $ 1,179 $ (45,611) - ====================================================================================================================================
Series B Preferred Stock The Company is authorized to issue Series B Preferred Stock (the "Junior Preferred") with a $1 par value and a liquidation preference of $10 per share, which may be redeemed by the Company in whole or in part at any time at a price per share equal to the liquidation preference amount per share, plus all accrued and unpaid dividends through the date of redemption. The Junior Preferred will be used to satisfy certain claims pursuant to the Plan that have been finally allowed. To date, no claims to be satisfied with the Junior Preferred have been allowed and the Company does not currently anticipate that any such claims will be allowed. Cumulative Convertible Preferred Stock The Company is authorized to issue 10,000,000 shares of 9% Cumulative Convertible Preferred Stock (the "Old Preferred"), of which 300,000 shares are outstanding. The Old Preferred have a $1 par value and a liquidation preference of $10 per share, convertible at any time at the rate of one Old Preferred share for four shares of the Company's Common Stock. In addition, 131,000 shares of Old Preferred will be issued for accrued dividends. Until the redemption value plus all accrued dividends attributable to Senior Preferred are paid in full, dividends related to the Old Preferred will be paid with additional shares of Old Preferred. 42 Common Stock The Company is authorized to issue 100,000,000 shares of Common Stock, with a $.01 par value, of which 25,313,533 were outstanding at December 31, 1994. All outstanding shares of Common Stock are fully paid and non-assessable. The holders of Common Stock are entitled to one vote per share upon all matters presented to them. Pursuant to the Plan, holders of Common Stock are entitled, collectively with holders of Junior Preferred and Old Preferred, to 5% of the total voting power of the Company. The holders of Common Stock are entitled to dividends in such amounts as may be declared from time to time out of any funds legally available for such purposes. However, no dividends are payable until all accrued dividends have been paid to the preferred stockholders. In the event of liquidation, dissolution or winding up of the affairs of the Company, whether voluntary or involuntary, after payment of debts and liquidation preferences on preferred stock, all remaining assets, if any, will be divided and distributed among the holders of Common Stock pro rata according to the number of shares owned by them. The Common Stock does not have preemptive rights and is not subject to redemption. Restricted Stock and Stock Options Plans Previously, the Company had adopted a key employee compensation package which consisted of a Restricted Stock Plan, a Non-Qualified Stock Option Plan, and an Incentive Stock Option Plan. Both the Non-Qualified Stock Option Plan and the Incentive Stock Option Plan were terminated in 1991 pursuant to the respective plan's provisions and while options previously issued are still valid, no new options under these plans can be issued. Shares of common stock under the Restricted Stock Plan were granted free of charge to the recipient in consideration for services rendered. Grants made under the plan are subject to forfeiture, based on a formula, in the event the recipient leaves the employment of the Company within three, four or five years after the date of grant. The market value of the Common Stock on the date of grant was charged to expense over a five-year period, regardless of whether or not the shares are ultimately earned by the employee. The Company has reserved 89,333 shares of Common Stock for issuance under the plan. In 1991 through 1994, no shares of common stock were issued to vested participants pursuant to the plan and no new grants will be issued under this plan. Non-qualified and incentive stock options were granted to selected key employees at an exercise price equal to the market price of the shares of common stock on the date of grant, and become exercisable over a five-year period. Information relating to stock options granted under both plans is as follows:
- -------------------------------------------------------------------------------- Non-Qualified Plan Incentive Plan ------------------- ------------------- Average Average Number Exercise Number Exercise of Price of Price Shares Per Share Shares Per Share - -------------------------------------------------------------------------------- Balance, December 31, 1991 11,400 $ 7.76 60,500 $ 1.55 Options canceled or forfeited - - (12,000) 2.17 - -------------------------------------------------------------------------------- Balance, December 31,1992 11,400 $ 7.76 48,500 $ 1.40 Options canceled or forfeited (11,400) 7.76 (4,000) 4.00 - -------------------------------------------------------------------------------- Balance, December 31, 1993 - - 44,500 $1.17 Options canceled or forfeited - - (40,000) 1.15 - -------------------------------------------------------------------------------- Balance, December 31,1994 - - 4,500 $ 1.33 ================================================================================ Options exercisable: December 31, 1992 11,400 $ 7.76 34,500 $ 1.55 December 31, 1993 - - 37,500 $ 1.22 December 31, 1994 - - 4,500 $ 1.33
9. INCOME TAXES On October 2,1992, the Company, concurrent with the implementation of fresh start reporting, adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("Statement 109"), which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax liabilities and assets 43 are determined based on the difference, if any, between the financial reporting and tax bases of assets and liabilities using enacted tax rates in effect for the year in which the differences are expected to reverse. Prior to the adoption of Statement 109, deferred income taxes were provided for timing differences arising from the recognition of revenues and expenses in different periods for financial and tax reporting purposes. Long-term deferred tax assets (liabilities) are comprised of the following for the years 1994,1993 and 1992, respectively. - -------------------------------------------------------------------------------- December 31, December 31, December 31, (Thousands) 1994 1993 1992 - -------------------------------------------------------------------------------- Deferred Tax Assets: Loss carry forwards $ 11,084 $ 9,712 $ 7,070 AMT credit carry forward and other 150 9 - Deferred Tax Liabilities: Oil & gas properties (2,303) - (2,009) ----------- ----------- ----------- Net deferred tax asset 8,931 9,721 5,061 Valuation allowance (8,931) (9,721) (5,061) - -------------------------------------------------------------------------------- $ - $ - $ - ================================================================================ Income tax expense differs from the amounts computed by applying the statutory federal rate as follows: - -------------------------------------------------------------------------------- Year Ended Year Ended Year Ended December 31, December 31, December 31, 1994 1993 1992 - -------------------------------------------------------------------------------- Income taxes computed at statutory federal rate 34.0% (34.0)% (34.0)% Net operating loss carryover not deductible (utilized) in current period (34.0) 34.0 34.0 Alternative minimum tax and other 1.1 - - - -------------------------------------------------------------------------------- 1.1% -% - % ================================================================================ Pursuant to the provisions of the Internal Revenue Code (the "Code"), a corporation which undergoes a "change of ownership" is generally subject to an annual limitation on the utilization of its loss carryovers. As a result of the Reorganization Proceeding, on the Effective Date a "change of ownership" for the Company occurred under the Code. Since the Reorganization Proceeding was conducted pursuant to the Bankruptcy Code, the Company was eligible for an exception (the "Bankruptcy Exception") to this general rule. In order to maintain the Bankruptcy Exception, the Company could not have another "change of ownership" within two years of the first change. If such a change did occur, the Company's entire pre-"change of ownership" loss carryovers would be eliminated. Due to the probability that a second "change of ownership" for tax reporting purposes could occur, the Company elected out of the Bankruptcy Exception regarding the utilization of its pre-"change of ownership" loss carryovers. Since the Company has elected not to apply the Bankruptcy Exception, the Company is limited in its utilization of the pre-"change of ownership" loss carryovers. Based on the value of the Company as of the Effective Date, the annual amount of the pre-"change of ownership" loss carryovers to be utilized is limited to $1,230,000 but loss carryovers not fully utilized in the year that they are available may be carried over and utilized in subsequent years, subject to their expiration provisions. As of December 31, 1994, the Company had pre- "change of ownership" net operating loss carryforwards of $2,417,000 which are available for use through 2006. These loss carryforwards may be increased by any built-in gain exclusion recognized during the five year period after the "change of ownership". The Company also had post-"change of ownership" net operating loss carryforwards of $7,701,000 that expire 2008 and are available without limitation. The Company has certain investment tax credits which are also subject to the "change of ownership" limitation. Due to the limitation and scheduled expiration, it is unlikely that the Company will realized any future benefit from such credits. The Company had depletion carryforwards, as of December 31, 1994, of $14,234,000 which are limited annually to 65% of taxable income. 44 10. RELATED PARTY TRANSACTIONS Pursuant to the provisions of the applicable agreements and in its capacity as general partner, the Company receives recurring supervisory and administrative fees, including reimbursement of certain general and administrative costs, from certain partnerships. Supervisory and administrative fees of $684,000, $852,000 and $958,000, were received during 1994, 1993, and 1992, respectively. Since certain affiliated partnerships have not had sufficient cash flows to repay their obligations, accounts and notes receivable from these affiliated partnerships in which TGX is a general partner have been written-off. Accordingly, the Company has been applying 100% of the net revenues of the respective partnerships to their obligations due to TGX and will continue to do so until the amounts due have been repaid or until the partnerships are liquidated. As a result of 1994 partnership liquidations, the Company obtained additional direct interests in related oil and natural gas properties having an estimated value of $381,000 and realized the recoupment of $751,000 in previous allowed for receivables and notes. Presented below are aggregate amounts due from partnerships and other affiliates: ---------------------------------------------------------------------- (Thousands) 1994 1993 ---------------------------------------------------------------------- Accounts receivable from affiliates (current) $ 504 $1,154 Accounts and notes receivable from affiliates (noncurrent) - 100 ---------------------------------------------------------------------- $ 504 $1,254 ====================================================================== Paragon and certain of its affiliates are the owners of approximately 14% of the Company's outstanding Common Stock. In the past, the Company has had substantial transactions with Paragon including the offering of interests and in the drilling of wells for partnerships. Included in the above 1994 and 1993 amounts due from its affiliates, net of allowance for possible uncollectibility, is $286,000 and $284,000, respectively, due from Paragon and certain of its affiliates. In February 1992, the Company commenced a legal action regarding the collection of the amount due to it from Paragon and certain of its affiliates. Due to the uncertainty regarding the status of this litigation, the Company established an allowance for all amounts due from Paragon and affiliates in 1994 and 1993 in excess of $286,000 and $284,000, respectively. The total allowance for affiliated receivables in 1994 and 1993 was $2,027,000 and $1,963,000, respectively. During 1992, the Company entered into an agreement with a member of its Board whereby the Company sold certain oil and gas properties to an affiliate of the Board member for $269,000. This sale was approved by the Board, with the involved Board member abstaining from both the discussion and vote. The Company had solicited bids for the properties and, through this transaction, the properties were sold to the highest bidder. 11. MAJOR CUSTOMERS The Company's revenues are derived principally from uncollateralized sales to customers in the oil and natural gas industry. The concentration of credit risk in a single industry affects the Company's overall exposure to credit risks since customers may be similarly affected by changes in economic and other conditions. Customers which accounted for greater than 10% of oil and gas sales are as follows: 1994 1993 1992 ----- ----- ----- Lion Oil Company 14% - - National Fuel Gas Distribution Corporation - 24% 33% Noram Energy Services Inc. 12% - - Princeton Natural Gas Company 15% - - 12. INFORMATION ON OIL AND GAS ACTIVITIES (UNAUDITED) Following are supplemental unaudited disclosures relating to the Company's oil and natural gas exploration and production activities. 45 Oil and Gas Related Costs and Operating Results The following schedules present capitalized costs and costs incurred, whether capitalized or expenses, and operating results for the periods then ended. - -------------------------------------------------------------------------------- October 2, January 1, through through December' 31, October 1, (Thousands) 1994 1993 1992 1992 - -------------------------------------------------------------------------------- Capitalized costs: Proved properties $ 10,407 $ 11,434 $ 39,414 $ 39,347 Accumulated depletion and depreciation (3,251) (2,281) (817) - - -------------------------------------------------------------------------------- $ 7,156 $ 9,153 $ 38,597 $ 39,347 ================================================================================ Costs incurred: Acquisition of properties: Unproved $ - $ - $ - $ - Proved - - - - Development(1) 404 179 67 154 - -------------------------------------------------------------------------------- $ 404 $ 179 $ 67 $ 154 ================================================================================ Operating results*: Revenues $ 4,802 $ 9,730 $ 2,641 $ 6,501 Costs and expenses: Production costs 3,188 3,935 1,003 2,965 Depletion and depreciation 1,099 2,607 817 3,215 - -------------------------------------------------------------------------------- 4,287 6,542 1,820 6,180 Operating earnings before income taxes 515 3,188 821 321 Income tax expense 17 - - - - -------------------------------------------------------------------------------- Operating earnings $ 498 $ 3,188 $ 821 $ 321 ================================================================================ * Excludes general and administrative and interest expense. (1) 1994 and 1993 activity represents primarily properties received in settlement of certain partnership notes and receivables. Proved Reserves The following table, which includes proved undeveloped reserves as extensions and discoveries in 1994 and for 1993 takes into consideration the sale of New York and Ohio properties by the Company to BBC on January 14, 1994, but effective December 1, 1993, presents estimates of proved oil and natural gas reserves, all of which are located in the United States. Proved reserves are estimated quantities of oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved- developed reserves are those which are expected to be recovered through existing wells with existing equipment and operating methods. Reserves are stated in thousands of barrels of oil and billions of cubic feet of natural gas.
---------------------------------------------------------------------------------------------------------------- 1994 1993 1992 ---- ---- ---- Oil(MBls) Gas(Bcf) Oil(MBls) Gas(Bcf) Oil(MBls) Gas(Bcf) ---------------------------------------------------------------------------------------------------------------- Proved reserves: Beginning of year 525 9.1 980 72.2 1,112 73.3 Sales of reserves in place (37) (.5) (111) (62.0) (139) (1.6) Extensions and discoveries 487 2.6 Revisions of previous estimates 18 1.4 (257) 2.6 89 4.0 Production (62) (2.2) (87) (3.7) (82) (3.5) ---------------------------------------------------------------------------------------------------------------- End of year 931 10.4 525 9.1 980 72.2 ================================================================================================================ Proved-developed reserves 444 7.8 525 9.1 980 72.2 ================================================================================================================
The above reserve estimates include for the first time in 1994, as extensions and discoveries, estimates of previously discovered proved undeveloped reserves. Due to the uncertainty in prior years of the Company's ability to finance their development, proved undeveloped reserves were not included in reported reserves. However, as a result of the Company's improving financial condition, it anticipates that sufficient funds will be available in 1994 and beyond to develop these reserves. 46 Geological and engineering estimates of proved oil and natural gas reserves are highly interpretive, inherently imprecise, and subject to ongoing revisions that may be substantial in amount. Although every reasonable effort is made to ensure that the reserve estimates reported represent the most accurate assessments possible, these estimates are by their nature generally less precise than other estimates presented in connection with financial statement disclosures. Standardized Measure of Discounted Future Net Cash Flows The following table presents the standardized measure of estimated discounted future net cash flows attributable to the Company's proved oil and gas reserves ("Standardized Measure"), and an analysis of the changes in these amounts and quantities for the periods indicated. For 1994, proved undeveloped reserves are included as extensions and discoveries, and 1993 excludes the New York and Ohio properties which were sold to BBC. The Standardized Measure was computed on the basis of (a) contractual prices, including escalations for natural gas, in effect at year end for oil and natural gas (b) the estimated market price for natural gas and the posted price for oil in effect at year end in the case of properties being commercially developed but not covered by existing contracts, (c) estimated deliverability, which not only considers the physical characteristics of the well or properly, but also the estimated future prices to be received by the Company and the amount and timing of future production estimated to be taken by its purchasers, (d) where applicable, the premise that future prices and takes will be in accordance with existing contractual terms which may require arbitration or litigation to ultimately assure compliance, (e) for 1992 natural gas reserves dedicated under the NFG Contract, the 90% of No. 6 Fuel Oil Price (see Note 4 for a description of litigation related to the Contract). Estimated future production and development costs are based on economic conditions at the respective year ends. Future income taxes, if any, are computed by applying statutory income tax rates to the difference between the future pre-tax cash flows and the tax basis of proved oil and gas properties, after considering investment tax credits and depletion carryforwards and net operating loss carryovers associated with these properties. Since the Standardized Measure was prepared using the prevailing economic conditions existing at each applicable year end, it is emphasized that such conditions continually change, as evidenced by the fluctuations in oil and natural gas prices during recent years. Accordingly, such information should not serve as a basis in making any judgment on the potential value of the Company's recoverable reserves, or in estimating future results of operations. ---------------------------------------------------------------------- (Thousands) 1994 1993 1992 ---------------------------------------------------------------------- Future net cash flows: Future revenues $ 29,092 $ 27,054 $214,888 ---------------------------------------------------------------------- Future production costs 10,631 10,369 80,798 Future development costs 3,647 607 940 ---------------------------------------------------------------------- 14,278 10,976 81,738 ---------------------------------------------------------------------- Future pre-tax cash flows 14,814 16,078 133,150 Future income taxes - - - ---------------------------------------------------------------------- $ 14,814 $ 16,078 $133,150 ====================================================================== Standardized Measure, discounted at 10%: Future pre-tax cash flows $ 8,807 $ 10,943 $ 46,429 Future net cash flows 8,807 10,943 46,429 ====================================================================== Changes in Standardized Measure: Standardized Measure, beginning of year $ 10,943 $ 46,429 $ 47,309 ====================================================================== Sale of reserves in place (1,042) (31,832) (1,968) Extensions and discoveries (1) 2,213 611 - Revisions of previous quantity estimates 1,072 461 2,787 Changes in future development costs (2,310) 185 181 Net changes in prices and production costs (2,858) (2,011) (133) Sales of oil and natural gas produced, net of production costs (1,614) (5,795) (5,174) Net change in income taxes - - - Accretion of discount 1,094 4,643 4,731 Changes in production rates and other, net 1,309 (1,748) (1,304) ---------------------------------------------------------------------- Net decrease (2,136) (35,486) (880) ---------------------------------------------------------------------- Standardized Measure, end of year $ 8,807 $ 10,943 $ 46,429 ====================================================================== (1) Reflects inclusion, in 1994, of proved undeveloped reserves excluded in prior years' reporting. 47 13. INTERIM FINANCIAL DATA (UNAUDITED) The unaudited interim results of operations for 1992, 1993, and 1994 adjusted for discontinued operations related to LEDCO, are summarized below (in thousands of dollars except per share amounts): July 1, October 2 through through 1992: March 31, June 30, October 1, December 31, - -------------------------------------------------------------------------------- Revenues $ 2,297 $ 3,669 $ 3,864 $ 2,993 Gross profit 994 1,209 1,376 1,595 Net income (loss) applicable to common stock (4,009) (1,998) 1,091 (3,184) Income (loss) per common share $ (.16) $ (.08) $ .05 $ (.13) ================================================================================ 1993: March 31, June 30, September 30, December 31, - -------------------------------------------------------------------------------- Revenues $ 2,404 $ 2,903 $ 2,544 $ 3,146 Gross profit 1,026 1,308 1,384 2,077 Net loss applicable to common stock (4,031) (3,583) (3,755) (15,582) Loss per common share $ (.16) $ (.14) $ (.15) $ (.61) ================================================================================ 1994: March 31, June 30, September 30, December 31, - -------------------------------------------------------------------------------- Revenues $ 1,487 $ 2,145 $ 1,463 $ 1,382 Gross profit 574 471 469 516 Extraordinary gain - - 128 703 Net loss applicable to common stock (4,051) (3,402) (4,638) (3,385) Loss per common share $ (.16) $ (.13) $ (0.19) $ (.13) ================================================================================ The third quarter of 1992 was restated to reflect the effect of implementing the effect of fresh start reporting. The net loss for the fourth quarter of 1993 includes a charge of $12.4 million related to the provision for loss on the sale of assets to BBC. 14. ONGOING BUSINESS OPERATIONS The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. The Company has a substantial accumulated deficit, and has suffered recurring operating losses as well as cash flow deficits that raise substantial doubts about its ability to continue as a going concern. The financial statements do not reflect any adjustments that might result from the outcome of this uncertainty. Management does believe, however, that with the substantial improvement in its debt structure, including its new revolving credit facility and the reduction in general and administrative expenses, it will generate the necessary cash flow not only to support its ongoing business operations but also to carry out oil and gas property development activities in accordance with its business plans. 15. PRIOR PERIOD ADJUSTMENTS In July 1994, the Company restructured and converted its BMO debt of $4,652,000 to a non-recourse note secured only by proceeds, if any, which might have been received from the NFG Litigation. This restructuring and conversion was accounted for as an exchange transaction presented as an extinguishment of debt in accordance with Emerging Issues Task Force Consensus No. 86-18 and resulted in the recognition of an extraordinary gain, net of transaction costs of $492,000, of $4,160,000 in the third quarter of 1994. In connection with responding to comments from the Securities and Exchange Commission in connection with a 1996 filing, the Company accepted the Securities and Exchange Commission's determination that generally accepted accounting principles require the Company to account for the restructuring and conversion of debt as a troubled debt restructuring in accordance with Statement of Financial Accounting Standards No. 15. As a result of this change, the financial statements for September 30, 1994 through the current period reported have been restated to restore the liability for the non-recourse BMO debt, including accrued interest, and to reverse the extraordinary gain recognized in 1994. This 48 restatement did not impact cash flow during the period September 30, 1994 through the current period reported. The Company did, however, upon resolution of the NFG Litigation in April 1996, reflect a net gain from litigation settlement of $7,100,000 and an extraordinary debt extinguishment gain of $1,868,000, and made a final debt payment to BMO of $3,600,000. A summary of the impact for 1994 is shown below (in thousands, except per share data). December 31, 1994 ---------------------- Reported Restated -------- --------- BALANCE SHEET Total current liabilities $ 3,928 $ 3,765 Long term debt 1,150 6,020 Accumulated deficit (40,904) (45,611) Total stockholders' deficit (39,004) (43,711) Year Ended December 31, 1994 ----------------------- Reported Restated ----------------------- STATEMENT OF OPERATIONS General and administrative expense $ 1,747 $ 2,239 Interest expense 948 1,166 Income tax expense 180 17 Extraordinary gain 4,991 831 Net loss applicable to common stock (10,769) (15,476) Net loss per share of common stock (0.42) (0.61) ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. In October 1992, the Company filed a Form 8-K regarding the change of its independent accountants from BDO Seidman to Price Waterhouse. Subsequently, BDO Seidman furnished a letter stating that it agreed with the statements contained in the Form 8-K. During 1994, there were no disagreements with the Company's independent accountants regarding accounting or financial disclosure matters. 49 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT. Board of Directors The Company's restated Certificate of Incorporation provides for a Board consisting of eight members elected for three year terms beginning January 21, 1992 and ending on January 21, 1995 or when their successors are duly elected and qualified. On the effective date of the Plan, five such directors (the "Senior Preferred Directors") were elected by holders of the Senior Preferred and two (the "Common Stock Directors") were elected by holders of the Common Stock, Old Preferred and Junior Preferred voting as a class. The remaining director is the chief executive officer of the Company. During 1993, two directors resigned, one Senior Preferred Director and the other a Common Stock Director. To date no replacements have been elected. Of the Senior Preferred Directors, two were elected on an unrestricted basis, one was subject to the requirement that such director not be an affiliate of any holder of Senior Preferred, and two were designated by Steinhardt. The Common Stock Directors are required not to have been directors of TGX at the time it filed for bankruptcy or be affiliated with any former TGX director. After the expiration of the initial three year term, the term of all directors are for one year, and all restrictions and requirements for selection of the Board are removed. As of January 21, 1995, therefore, all eight directors are elected by all of the stockholders voting in accordance with the Certificate of Incorporation of the Company. Senior Preferred Stockholders maintain 95% of the voting power of all stockholders, and, therefore, can elect all directors of the Company. However, pursuant to the terms of the Senior Preferred Stock designation, if TGX fails to pay six quarterly dividends then the Board of Directors is increased by two members to ten and such additional two members are to be elected solely by the Senior Preferred Stockholders. TGX has failed to pay such dividends and, therefore, pursuant to the Certificate of Incorporation, at the next annual meeting of stockholders, the Senior Preferred Stockholders voting alone are entitled to elect two members to the Board of Directors. The Company cannot determine when the next annual meeting of stockholders will be held and, therefore, can make no determination as to when such additional board members will be elected. The Board met on six occasions in 1994 and each current director attended at least 75% of such meetings. The members of the Board are:
Served as Position, Prinicipal Occupation, Director Business Experience and the Name Age Since Directorships Held ---- --- --------- -------------------------------- LARRY H. CARPENTER 47 1992 Chairman of the Board, President and Chief Executive Officer of the Company since November 1992. From March 1992 he served as a consultant to the Company until his election as President. Prior thereto he was a senior executive with Texas Oil & Gas Corp. from 1977 through September 1990 and thereafter was engaged as an independent oil and gas consultant. MARK LIDDELL 40 1992 President of DLB Oil and Gas, Inc, a privately owned independent oil and gas company located in Oklahoma City, Oklahoma and previously served as Vice President of DLB Energy Corporation. Mr. Liddell also has a law degree and has been a practicing attorney. JOHN W. MASON 69 1992 President, Burnett Oil Company, Fort Worth, Texas, a privately owned independent oil and gas company. KAREN RYUGO 35 1992 Vice-President of Concurrency Management Corporation, a management company, and a Principal in Wexford Capital Corporation, an investment management company, both based in New York. From 1988 until December 1994, a Senior Research Analyst for Steinhardt Management Company, Inc. Prior to 1988, she served as an analyst at Stockbridge Partners and as a research assistant at Montgomery Securities.
50
R.J. SCHUMACHER 66 1992 President and Chief Executive Officer of Texland Petroleum, Inc. a privately owned independent oil and gas company. From June 1989 through March 1994, Mr. Schumacher also served as Chairman and Chief Executive Officer of Pride Refining, Inc., Fort Worth, Texas, the general partner of Pride Companies, L.P., a master limited partnership traded on the New York Stock Exchange. Mr. Schumacher also serves as a director of Aztec Manufacturing Company, a publicly traded company. JEFFREY E. SUSSKIND 41 1992 Principal of Strome, Susskind Investment Management, L.P., an investment management company in Santa Monica, California. Mr. Susskind previously was an investment manager with Kayne, Anderson & Co.
Certain officers, directors and stockholders were required to timely file with the Securities and Exchange Commission reports reflecting their ownership of the Company's securities and any such change in owners. All persons required to file reports have represented to the Company that they timely filed all required reports and no further reports are required to be filed. Committees The current Committees of the Board of Directors consist of the Audit Committee, the Compensation Committee and the Executive Committee. All non- officer directors are members of the Audit, Compensation and Executive Committees. In 1994, the Audit Committee met on one occasion, the Executive Committee did not meet, and the Compensation Committee met on two occasions. EXECUTIVE OFFICERS OF THE COMPANY Presented below are the names, ages and positions held during the past five years of the Company's executive officers as of March 28, 1995. Pursuant to the By-Laws of the Company, officer serves at the pleasure of the Board of Directors and may be removed, with or without cause, at any time. Name Age Position ---- ---- -------- LARRY H. CARPENTER 47 See information as set forth under "Board of Directors." MICHAEL A. GERLICH 40 Mr. Gerlich was elected Vice President and Chief Financial Officer of the Company in December, 1994. From January 1993 until joining TGX, he owned and managed Chalk Hill Resources, Inc., an independent oil and gas investing and financial consulting company. Prior thereto, he was Executive Vice President from January 1989 to December 1992 and Vice- President of Finance from May 1982 to December 1988 for Trinity Resources, Inc., an independent public oil and gas company. 51 ITEM 11. EXECUTIVE COMPENSATION. The following table sets forth the cash compensation paid to the Chief Executive Officer and each of the most highly paid executive officers of the Company for each of the last three years whose cash compensation for 1994 exceeded $100,000. For 1994, other annual compensation for Mr. Carpenter includes for reimbursement of house expenses and for reimbursement of automobile expenses.
SUMMARY COMPENSATION TABLE (1) LONG TERM COMPENSATION ANNUAL COMPENSATION AWARDS ------------------- ------ Name and Other Principal Annual Restricted Stock Options/ All Other Position Year Salary($) Bonus($) Compensation($) Awards($) SARs(#) Compensation ($) - --------- ---- -------- -------- ---------------- ---------------- -------- ---------------- LARRY H. 1994 $175,000 $100,000(3) $26,062(3) N/A -0- -0- CARPENTER 1993 $175,000 (3) $49,062(3) N/A N/A -0- PRESIDENT/ CEO 1992 $160,667(2) N/A $19,913(3) 200,000 (4) N/A -0-
1. The table above lists the compensation of the CEO the only employee who received in excess of $100,000 in total compensation for 1994. 2. Includes amounts paid to Mr. Carpenter as a consultant to the Company prior to his election as President and Chief Executive Officer of the Company in November, 1992. 3. Excludes perquisites and other benefits, unless the aggregate amount of such does not exceed the lesser of either $50,000 or 10% of the total annual salary and bonus reported for the named executive officer. For Mr. Carpenter, it includes housing, automobile and moving expense allowances from the period of time when Mr. Carpenter became a consultant to the Company, as well as such expenses after Mr. Carpenter was elected President of the Company. See "Employment Agreements". 4. Includes the award of 200,000 shares of Series A Preferred Stock which was forfeitable, in part, if Mr. Carpenter ceased to be an employee of the Company prior to March 1995. As of December 31,1994, there was no trading in the Series A Senior Preferred Stock and, therefore, the Company was not able to determine a market value for such stock. For stock compensation purposes, the Company valued these shares at $1.50 per share, based on an internal estimate of Company net assets as of October 2, 1992 (fresh start reporting). Of such award, 133,333 shares ceased to be subjected to forfeiture as of December 31,1994 and the remaining 66,667 shares ceased being subject to forfeiture on March 31, 1995. Employment Agreements Larry H. Carpenter, Chairman of the Board, President and Chief Executive Officer of the Company, entered into an employment agreement (the "Employment Agreement") with the Company in March 1992. Pursuant to the Employment Agreement, for the period through November 1992, Mr. Carpenter acted as a consultant to the Company and had an option to become a full-time employee, President and member of the Board of Directors. In November 1992, Mr. Carpenter exercised such option and, at that time, was elected President of the Company and, pursuant to the Articles of Incorporation, became a member of the Board of Directors. Pursuant to the Employment Agreement, for a period of three years ending March 30, 1995, Mr. Carpenter received compensation equal to $175,000 per annum, plus discretionary bonuses as determined by the Board of Directors. For 1993, the Board of Directors did not grant a discretionary bonus. However, in February 1994, the Board of Directors granted a bonus of $100,000 to Mr. Carpenter in connection with his efforts in consummating the sale of the Company's New York and Ohio properties. In addition, Mr. Carpenter received 200,000 shares of the Company's Series A Senior Preferred Stock which vested over the term of the Employment Agreement. The Employment Agreement also provided Mr. Carpenter with certain living expense allowances, as well as benefits relating to moving expense, health and life insurance, club membership and use of an automobile. In December 1991, the Company entered into an employment agreement with Mr. Joe W. Cluck formerly Vice President and Chief Financial Officer of the Company. The employment agreement provided that he be employed by TGX as Vice President and Chief Financial Officer at a monthly salary of $9,175. Mr. Cluck's agreement could be 52 terminated at any time and entitles him to six months severance pay upon termination of such agreement. In June, 1994, Mr. Cluck resigned from the Company and received his severance payment. Employees Stock Options and Restricted Stock Plans The Company had adopted two stock option plans: a Non-Qualified Stock Option Plan and an Incentive Stock Option Plan, each of which are incentive plans administered by the Board of Directors. Both of these plans were terminated in 1991, and while options previously issued are still valid, no new options can be issued. During 1994, no options were granted nor exercised pursuant to these plans. Compensation of Directors Each non-employee member of the Board received a fee of $1,500 per month through June 1994 and $833 thereafter plus a meeting fee of $500 per day through June 1994 and $1,000 per day thereafter, subject to forfeiture on a six-month prospective basis if a director attends less than 75% of the meetings, and reimbursement for reasonable travel expenses incurred in conjunction with meetings, with air fare not to exceed the rate for a full-fare coach seat. Indemnification of Officers and Directors The Company's Certificate of Incorporation provides that the Company shall indemnify the officers and directors to the fullest extent allowed by Delaware Law. In addition, the Company has entered into indemnification agreements with certain Directors and officers ("Indemnification Agreement") to provide certain additional protection in the event actions are filed against them in their capacities as directors and officers. The Company proposes to enter into an Indemnification Trust Agreement which establishes a trust fund (the "Fund"), administered by a trustee, available to pay indemnification claims made by the directors and officers to the extent the Company has not paid such claims. To date the Company has not established such Fund. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT As of March 28, 1995, the Company had no "parent" as that term is defined in regulations promulgated under the Securities Exchange Act of 1934, as amended. Security Ownership of Management The following table sets forth, as of March 28, 1995, the amount of the Company's Common Stock or Series A Senior Preferred Stock beneficially owned by each of its directors, each executive officer named in the Summary Compensation Table, and all directors and executive officers as a group, based upon information obtained from such persons.
Name of Amount and Nature of Individual or Group Beneficial Ownership - --------------------------------------------------------------------------------------- Options Percent Sole Voting and Exercisable of Investment Power Within 60 Days Class /1 // - --------------------------------------------------------------------------------------- Larry H. Carpenter/2// 200,000 Series A -0- 2.3% Mark Liddell -0- -0- - John W. Mason 22,366 Series A -0- - Karen Ryugo -0- -0- - R. J. Schumacher 59,462 Common -0- - Jeffrey E. Susskind -0- -0- - All executive officers 222,366 Series A and directors as a 59,462 Common -0- - group (7 persons) - ---------------------------------------------------------------------------------------
1/ Unless otherwise indicated, the holders have sole voting and investment powers. Unless otherwise stated, the percentage is less than one percent. 53 2/ Mr. Carpenter's shares are subject to forfeiture pursuant to the terms of his employment agreement. See "Employment Agreement". As of March 28,1995, all shares have been vested and are no longer subject to forfeiture. Security Ownership of Certain Beneficial Owners The following table sets forth certain information regarding each person known by the Company owning or entitled to own as the beneficial owner, more than 5% of the Company's outstanding Common Stock, Senior Preferred or Old Preferred Stock as of March 28, 1995.
Amount Beneficially Percent Name and Address of Beneficial Owner Class Owned of Class - ----------------------------------------------------------------------------------------------- Liberty National Bank and Trust Company Common 3,136,986(1) 12.4% of Oklahoma City, Escrow Agent UA, November 18, 1985, Templeton Energy, Inc./Temex Energy, Inc. and Escrow Agent for the benefit of certain claimants of Amarex, Inc. P.O. Box 25848 Oklahoma City, Oklahoma 73125 Paragon Resources, Inc. Common 3,459,521(2) 13.7% 401 Market Street, Suite 701 Shreveport, Louisiana 71101 1987 Humphrey Trust Common 3,456,252(3) 13.7% Carl J. Udouj, Trustee 520 South 14th Forth Smith, Arkansas 72901 Gaylon D. Simmons and Old Gloria Annette Turner Simmons Preferred 300.000 100.0% 905 East Main Street Jonesboro, Louisiana 71251 Steinhardt Partners, L.P. Senior and certain affiliates Preferred 1,692,796(4)(5) 19.4% 605 Third Avenue New York, NY 10158 The AIF-Lion Group c/o Apollo Advisors, L.P. Two Manhattanville Road Senior Purchase, N.Y. 10577 Preferred 1,823,000(6) 21.0% - -----------------------------------------------------------------------------------------------
(1) In connection with its acquisition of Amarex, Inc. which was consummated on December 5, 1985, the Company issued 11,475,000 shares of Common Stock into escrow with Liberty National Bank and Trust Company of Oklahoma City as escrow agent. Such shares are held by the escrow agent for the benefit of various classes of creditors of Amarex and its affiliates entitled to receive the shares under a Plan of Reorganization confirmed in Amarex's bankruptcy proceeding, and the shares have been and will continue to be distributed by the escrow agent from time to time as the various creditors' claims are adjudicated and allowed by the Bankruptcy Court. As of March 28,1995, 3,136,986 shares remained in escrow. Pursuant to the agreement governing the administration of the escrow account, the escrow agent has agreed to cause the escrowed shares to be voted at any annual or special stockholders' meeting in accordance with the instructions of the Company. 54 (2) Includes 3,456,252 shares owned of record and beneficially by Paragon Resources, Inc. ("Paragon") and an aggregate 3,269 shares owned of record or beneficially by certain affiliates of Paragon. With respect to the 3,456,252 shares owned by Paragon, Paragon may be deemed to share the power of voting and disposition with Majestic Energy Corporation ("Majestic"), which owns approximately 95% of the voting securities of Paragon. All of the capital stock of Majestic is owned by the 1987 Humphrey Trust established by W. M. Templeton for the benefit of J. C. Templeton's grandchildren (the "Humphrey Trust"). (3) Includes the 3,456,252 shares owned of record by Paragon with respect to all of which the Humphrey Trust may be deemed to be the beneficial owner by reason of its voting control of Majestic. (4) Pursuant to the terms of the Plan, certain holders of the Company's outstanding Senior Subordinated Notes are entitled to receive shares of the Company's Senior Preferred Stock. Such shares were to be issued following the order of substantial consummation by the Bankruptcy Court, which became effective in October 1992. See Item 1. "Business -Reorganization Proceeding". As a result of a fee dispute with the Indenture Trustee for holders of the Senior Subordinated Notes ("Trustee"), those shares were not issued to the beneficial holders as of December 31, 1994. However in late 1994, the dispute with the Trustee was settled and the Senior Preferred Stock shares were distributed in 1995. (5) Pursuant to the Plan, Steinhardt is entitled to receive 1,692,796 shares, or 19.4% of the to be outstanding shares of the Senior Preferred. See "Business-Reorganization Proceeding." (6) Such information has been supplied to the Company pursuant to a Schedule 13D filed with the Securities and Exchange Commission on December 31,1994, by AIF II, L.P., a Delaware limited partnership and Lion Advisors, L.P., a Delaware limited partnership (collectively the "Reporting Persons"). Such Reporting Persons may together constitute a "group" within the meaning of Rule 13d-5 under the Securities Exchange Act of 1934, as amended. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. The Company had substantial transactions with Paragon Resources, Inc. ("Paragon") a Delaware corporation which is engaged in the oil and natural gas business for its own account and for the account of drilling programs it has sponsored and which it may sponsor in the future. Paragon and its affiliates are the owners of approximately 14% of the Company's outstanding Common Stock. Mr. W. M. Templeton, a former Director of the Company, is an officer of Paragon and Majestic which owns 95% of the common stock of Paragon. In addition, 100% of the common stock of Majestic is owned by the Humphrey Trust, an Arkansas trust established by W. M. Templeton. Given these relationships, there is a potential conflict of interest between the Company and Paragon in connection with the operations of oil and natural gas properties and other matters. In the past, the Company's transactions with Paragon and its affiliates included the offering of interests in and drilling of wells, the sponsorship of the sales of interests in limited partnerships, and furnishing administrative services by both parties. Prior to the formation of the Company, Paragon's principal business was sponsoring limited partnerships engaged in the exploration for oil and natural gas. As part of Paragon's contribution to the formation of the Company, Paragon transferred substantially all of its personnel to the Company. Further, Paragon agreed to sell substantially all of its undeveloped oil and natural gas leasehold acreage to the Company at Paragon's investment cost in such acreage and Paragon agreed that the Company could be a co-sponsor in the sales of limited partnership interests which Paragon intended to sponsor solely for its own account. As a result of such co-sponsorship, the Company and Paragon were co-general partners of two public limited partnership drilling programs organized in 1981 and dissolved in 1994. Also, as part of the formation of the Company, the parties agreed that the Company would manage certain Paragon properties for a fee and would provide certain administrative services to Paragon and its affiliates. Amounts billed by the Company, net of company revenue offsets, to Paragon and its affiliates during 1994 totaled $151,000 for joint interest operations and other costs. As of December 31, 1994, the Company's records indicate that Paragon and certain of its affiliates owed the Company in excess of $2,313,000 for uncollected billings. An allowance for possible uncollectibility has been established for the amount in excess of $286,000. 55 Litigation Against Former Directors and Officers of Paragon In 1992, the Company commenced several actions in the Bankruptcy Court against Paragon, J. C. Templeton (former President, Chief Executive Office and Director), W. M. Templelon (the son of J. C. Templeton, who was also a former director), and a number of other former directors of the Company for violations of their fiduciary obligations, gross negligence, mismanagement and usurpation of corporate opportunities. In October, 1992, the action against two of the former directors of the Company was dismissed. Motions to dismiss were filed by the other directors but, prior to the time such motions could be heard, a motion was made to remove the case from the jurisdiction of the Bankruptcy Court. In 1993, the Federal District Court sitting in Alexandria, Louisiana, agreed to the removal of the jurisdiction of the Bankruptcy Court in these cases and, determined that all further proceedings would be heard before such Court. In April 1992, certain former directors brought a separate action in the Delaware Chancery Court alleging that (i) the Company's claims were barred by the statute of limitations, (ii) the Company's Articles and By-Laws exonerated these former directors, and (iii) the former directors were entitled to indemnification and advancement of legal fees by the Company. The Company intends to vigorously defend against the claims made in the Delaware action. 56 PART IV. ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (A) Index to Financial Statements 1. Financial Statements: The following financial statements of the Company are included in Part II, Item 8. (a) Reports of Independent Accountants (i) Price Waterhouse LLP (b) Financial Statements of TGX Corporation (the Registrant) and Subsidiaries (i) Consolidated Balance Sheet as of December 31, 1994 and 1993 (ii) Consolidated Statement of Operations for the years ended December 31, 1994 and 1993 and the two periods January 1, 1992 through October 1, 1992 and October 2, 1992 through December 31, 1992. (iii)Consolidated Statement of Cash Flows for the years ended December 31, 1994 and 1993 and the two periods January 1, 1992 through October 1, 1992 and October 2, 1992 through December 31, 1992. (iv) Notes to Consolidated Financial Statements 2. Financial Statement Schedules: None required. 3. Exhibits: Exhibit 2.1 Amended Plan of Reorganization and Disclosure Statement as revised and filed by the Company, as debtor-in-possession, on January 7, 1992. (Incorporated by reference to Exhibit 2.1 of the Registrant's Current Report on Form 8-K dated February 4, 1992, File No. 1-10201.) Exhibit 2.2 Order Confirming Amended Plan of Reorganization dated January 7, 1992. (Incorporated by reference to Exhibit 2.2 Of the Registrant's Current Report on Form 8-K dated February 4, 1992, File No. 1-10201. ) Exhibit 2.4 Stock Sale and Purchase Agreement by and between LEDCO Acquisition Company, Inc. and the Company dated as of December 31, 1991. (Incorporated by reference to Exhibit 2.4 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No.0-10201). Exhibit 2.5 Stock Purchase and Sale Agreement between Gaylon D. Simmons and Gloria Annette Turner Simmons and Templeton Energy, Inc. dated October 13, 1986 (Incorporated by reference to Exhibit 2.1 of the Registrant's Current Report on Form 8-K dated December 1, 1986, File No. 0-10201). Exhibit 3.1 Restated Certificate of Incorporation of the Company. (Incorporated by reference to Exhibit 3.1 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-10201). Exhibit 3.2 Amended and Restated By-Laws of the Company. (Incorporated by reference to Exhibit 3.2 Registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-10201). 57 Exhibit 3.3 Rights Agreement dated as of October 4, 1988 between the Company and American Stock Transfer Trust Company (Incorporated by reference to Exhibit C.1 of the Registrant's Current Report on Form 8-K dated October 11, 1988). Exhibit 4.1 Specimen Certificate representing shares of Common Stock (Incorporated by reference to Exhibit 4.1 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1985, File No. 0-10201). Exhibit 4.2 Specimen Certificate representing shares of Old Preferred Stock (Incorporated by reference to Exhibit 4.2 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1986, File No. 0-10201) . Exhibit 4.3 Specimen Certificate representing shares of Senior Preferred Stock. (Incorporated by reference to Exhibit 4.3 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-10201). Exhibit 10.1 Amended and Restated Credit Agreement effective as of February 1,1992 between the Company and the Bank of Montreal and the First Amendment thereto. (Incorporated by reference to Exhibit 10.1 of the Registrant's Annual Reporting Form 10-K for the year ended December 31, 1991, File No. 0-10201). Exhibit 10.2 Amended and Restated Security Agreement effective as of February 1, 1992 between the Company and the Bank of Montreal. (Incorporated by reference to Exhibit 10.2 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-10201). Exhibit 10.3 Amended and Restated Security Agreement (Partnerships) effective as of February 1, 1992 between the Company and the Bank of Montreal. (Incorporated by reference to Exhibit 10.3 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-10201). Exhibit 10.4 Amendment and Restated Stock Pledge Agreement effective as of February 1,1992 between the Company and the Bank of Montreal. (Incorporated by reference to Exhibit 10.4 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-10201). Exhibit 10.5 Amended and Restated Pledge of Secured Notes effective as of February 1, 1992 between the Company and the Bank of Montreal. (Incorporated by reference to Exhibit 10.5 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-10201). Exhibit 10.6 Promissory Note (Term Loan A) in the amount of $15,600,000 effective as of February 1, 1992 executed by the Company to the order of the Bank of Montreal. (Incorporated by reference to Exhibit 10.6 of the Registrant's Annual Reporting Form 10-K for the year ended December 31,1991, File No. 0-10201). Exhibit 10.7 Promissory Note (Term Loan B) in the amount of $10,000,000 effective as of February 1, 1992 executed by the Company to the order of the Bank of Montreal. (Incorporated by reference to Exhibit 10.7 of the Registrant's Annual Reporting Form 10-K for the year ended December 31, 1991, File No. 0-10201). Exhibit 10.8 Promissory Note (Term Loan C) in the amount of $1,250,000 effective as of February 1, 1992, executed by the Company to the order of the Bank of Montreal. (Incorporated by reference to Exhibit 10.8 of the Registrant's Annual Reporting Form 10-K for the year ended December 31, 1991, File No. 0-10201). Exhibit 10.9 Promissory Note (Revolving Credit Note) in the amount of $500,000 effective as of February 1,1992, executed by the Company to the order of the Bank of Montreal. (Incorporated by reference to Exhibit 10.9 of the Registrant's Annual Reporting Form 10-K for the year ended December 31, 1991, File No. 0- 10201). 58 Exhibit 10.10 Restricted Stock Award Plan (Incorporated by reference to Exhibit 13.51 of the Registrant's Registration Statement No. 2- 70911 on Form S-1 effective March 4, 1981). Exhibit 10.11 Non-Qualified Stock Option Plan (Incorporated by reference to Exhibit 13.50 of the Registrant's Registration Statement No. 2- 70911 on Form S-1 effective March 4, 1981). Exhibit 10.12 Incentive Stock Option Plan (Incorporated by reference to Exhibit A of the Registrant's 1981 Proxy Statement dated April 26, 1982). Exhibit 10.13 Employment Agreement dated December 23, 1991 between the Company and Ronald E. Grappe. (Incorporated by reference to Exhibit 10.13 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 010201). Exhibit 10.14 Employment Agreement dated December 23,1991 between the Company and Joe W. Cluck. (Incorporated by reference to Exhibit 10.14 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0-10201). Exhibit 10.15 Form of Indemnification Agreement to be entered into by and among the Company and each officer and director. (Incorporated by reference to Exhibit 10.15 of the Registrant's Annual Report on Form 10-K for the year ended December 31,1991, File No. 0- 10201). Exhibit 10.16 Form of Indemnification Trust Agreement. (Incorporated by reference to Exhibit 10.16 of the Registrant's Annual Report on Form 10-K for the year ended December 31, 1991, File No. 0- 10201). Exhibit 10.17 Promissory Note (Term Loan D) in the amount of $194,750 effective October 1,1992, executed by the Company to the order of Bank of Montreal. (Incorporated by reference to Exhibit A of Form 8-K dated October 2, 1992, File No. 0-10201). Exhibit 10.18 Personal Service and Employment Agreement Dated March 30,1992 between the Company and Larry H. Carpenter. (Incorporated by reference to Exhibit 10.18 of Form 10-K for the year ended December 31, 1992, File No. 0-10201). Exhibit 10.19 Purchase and Sale Agreement between TGX Corporation and Belden and Blake Corporation dated as of December 17, 1993. (Incorporated by reference to Exhibit C of Form 8-K dated January 14, 1994, File No. 0-10201). Exhibit 10.20 United Forbearance Agreement between TGX Corporation and Bank of Montreal dated as of January 10,1994. (Incorporated by reference to Exhibit C of Form 8-K dated January 14, 1994, File No. 0-1-10201). Exhibit 10.21 Second Amended and Restated Credit Agreement between the Company and BMO Financial, Inc. dated as of July 13,1994. (Incorporated by reference to Exhibit 10.1 of the Registrant's Form 8-K dated July 13, 1994). Exhibit 10.22 Amended and Restated Credit Agreement between the Company and Bank One, Texas, N.A. dated as of July 13, 1994. (Incorporated by reference to Exhibit 10.4 of the Registrant's report on Form 8-K dated July 13, 1994). Exhibit 18 Letter regarding Change in Accounting Principles. (Incorporated by reference to Exhibit 18 of Form 10-K for the year ended December 31,1992, File No. 0-10201). (b) Reports on Form 8-K for the quarter ended December 31, 1994: None. 59 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 "hereunto duly authorized. TGX Corporation (Registrant) Signature Title Date --------- ----- ---- By: /s/ MICHAEL A. GERLICH Vice President and ---------------------- Chief Financial Officer February 25, 1997 Michael A. Gerlich Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. Signature Title Date --------- ----- ---- By: /s/ MICHAEL A. GERLICH Vice President and ---------------------- Chief Financial Officer February 25, 1997 Michael A. Gerlich By: /s/ JEFFREY E. SUSSKIND Director February 25, 1997 ----------------------- Jeffrey E. Susskind By: /s/ DAVID H. SCHEIBER Director February 25, 1997 --------------------- David H. Scheiber 60 EX-27 2 FINANCIAL DATA SCHEDULE
5 1,000 YEAR DEC-31-1994 JAN-01-1994 DEC-31-1994 676 0 4,110 2,400 0 2,446 10,564 (3,307) 10,676 3,765 0 44,602 431 290 (44,432) 10,676 4,802 6,477 3,188 3,188 3,653 0 1,166 (1,530) 17 (1,547) 0 831 0 (15,476) (0.61) (0.61)
-----END PRIVACY-ENHANCED MESSAGE-----