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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB/A
X ANNUAL REPORT PURSUANT TO SECTION l3 OR l5(d) OF THE SECURITIES
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EXCHANGE ACT OF l934 (FEE REQUIRED)
For the fiscal year ended December 31, l995
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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
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TGX CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 72-0890264
(State or other jurisdiction of (I.R.S. Employer -
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
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SECURITIES REGISTERED PURSUANT TO SECTION l2(b) OF THE ACT: NONE
SECURITIES REGISTERED PURSUANT TO SECTION l2(g) OF THE ACT:
Name of each Exchange
Title of each class on which registered
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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 _____
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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-KSB/A or any amendment to
this Form 10-KSB/A: X
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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 ______
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The aggregate market value of the voting stock held by non-affiliates as of
March 21, 1996 was approximately $24,956.
As of March 21, 1996 there were 24,956,033 shares of Common Stock
outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
None
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INDEX
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ITEM PAGE NUMBER
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PART I.
ITEM 1. BUSINESS................................................ 1
ITEM 2. PROPERTIES..............................................20
ITEM 3. LEGAL PROCEEDINGS .....................................20
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY
HOLDERS...............................................21
PART II.
ITEM 5. MARKET FOR THE REGISTRANT'S SECURITIES AND
RELATED STOCKHOLDERS MATTERS..........................22
ITEM 6. SELECTED FINANCIAL DATA.................................24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS.........25
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.............32
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE...................60
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT......60
ITEM 11. EXECUTIVE COMPENSATION..................................63
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT........................................65
PART IV.
ITEM 13. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K...................................68
SIGNATURES..............................................72
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PART I.
ITEM l. BUSINESS
THE COMPANY
General
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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
713/872-0500). TGX (collectively with its subsidiaries, the "Company") is a
domestic independent energy company engaged in the production of oil and natural
gas and 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 until the liquidation or dissolution of such partnerships in 1994.
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.
Forward-looking statements in this report are made pursuant to the safe
harbor provisions of the Private Securities Litigation Reform Act of 1995.
Investors are cautioned that all forward-looking statements involve risks and
uncertainty, including without limitation, the costs of exploring and
developing new oil and natural gas reserves, the price for which such reserves
can be sold, the
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Company's attempts to reduce overhead and eliminate non-core assets,
environmental concerns affecting the drilling of oil and natural gas wells, the
possibility of a corporate restructuring, the ongoing costs and results of
litigation concerning NFG, as well as general market conditions, competition
and pricing. Please refer to the Company's Securities and Exchange Commission
filings, copies of which are available from the Company without charge, for
further information.
Business Strategy
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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 and restructuring its debt. During 1993 and 1994, a
substantial portion of management's efforts were utilized in implementing the
components of this business plan. Beginning in 1995, the Company turned its
focus to increasing its oil and gas revenues through a limited number of
acquisitions and the drilling of a small number of oil and gas exploration and
development wells.
In early 1993 the Company relocated and consolidated its offices in
Houston, Texas, thereby reducing expenses and began a program of downsizing
and possibly outsourcing 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 a program to liquidate and
dissolve substantially all the 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.
In furtherance 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 was completed in 1995, and sold
approximately 31 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 1995, the Company's oil and gas activities focused on lower risk
workover operations, drilling development wells and acquiring producing oil and
gas properties. During this period, the Company participated in ten workovers
at a net cost to the Company of $274,000 and participated in drilling seven new
wells at a net cost of $372,000. Of the wells drilled, four were deemed
successful at a net cost of $303,000. Also, in 1995, the Company acquired
additional interests in certain of its operated producing properties and five
new producing wells at a total net acquisition cost of $771,000. As a result of
these activities and upward revision of previous estimates, the Company, in
1995, increased its total proved reserves by approximately 1,878,000 equivalent
Mcf of gas (one barrel of oil equals six Mcf of gas) from year-end 1994,
representing a 12% increase in equivalent year end Mcf reserves.
In addition to the ongoing oil and gas production operations, a key factor
in the Company's future will be the proceedings in the longstanding 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
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be reached, the Company is currently 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 1996, the Company will be looking to further reduce its overhead,
eliminate additional non-core assets, and maximize the return on the retained
assets. 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 growth can be attained through
workover, drilling, acquisition or a combination, within the limits of the
Company's financial resources. Thus, based on the Company's 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
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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 LEDCO. 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. 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 LEDCO debt was also
eliminated.
In early 1993, the Company was notified that Events of Default had occurred
under the Amended Credit Agreement which were not cured 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.
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 and matures on July 13, 1997. The borrowing
base is redetermined at a minimum of every six months or at Bank One's
discretion and is reduced through monthly reductions of $50,000. The Bank One
facility requires the maintenance of certain financial ratios including a
working capital ratio of 1 to 1, as defined, and a tangible net worth of a
minimum of $5,000,000 and other ratios. At December 31, 1995, the borrowing
base was $2,500,000, and the Company had
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borrowings outstanding of $500,000, and the Company was in compliance with all
financial ratios and covenants.
Simultaneously with the securance of the Bank One facility and payment of
the Required Payment, BMO released all of its liens on the TGX's properties with
the exception of its lien on the NFG Litigation. As part of the loan
restructuring, BMO converted $4,652,000 ("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 has assigned
its rights to the loan, security and note, to BMO's wholly owned subsidiary, BMO
Financial, Inc. ("BMOF"). Pursuant to the July 13, 1994 agreement, after
repayment of the outstanding BMOF Principal, plus 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
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 loan, 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, 1995, total accrued interest pursuant to the BMOF
note was $683,000 resulting in a total year-end BMOF debt of $5,335,000.
On December 31, 1995, TGX and BMOF executed a First Amendment to the
Second Amended and Restated Credit Agreement ("BMOF Agreement"). Pursuant to
the BMOF Agreement, TGX and BMOF are to share equally any NFG Litigation
proceeds up to $8 million. BMOF is to receive 100% of any proceeds in excess of
$8 million until the total received by BMOF equals the BMOF Principal plus any
accrued interest. Thereafter, the Company will receive proceeds until the total
it has received equals the amount received by BMOF, and any additional NFG
Litigation proceeds will be shared equally by TGX and BMOF.
The NFG Litigation was settled on April 12, 1996, and, after payment to
BMOF of $3.6 million, the Company recognized an extraordinary gain for debt
forgiveness of $1,831,000, net of income taxes of $37,000, resulting from the
forgiveness of the remaining BMOF Principal, plus accrued interest, paid in
kind through the issuance of additional BMOF notes, of $816,000.
See Note 3, 14, and 15 and of the Notes to Consolidated Financial Statements.
Administrative Claims
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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 late
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1994 and early 1995, the Company renegotiated the terms of substantially all of
the Administrative Notes. As a result of negotiations and forfeitures,
Administrative Notes totaling approximately $1,126,000 in principal and $253,000
in accrued interest charges were renegotiated with the Company making cash
payments of $455,000, issuing 151,518 shares of the Company's Series A Senior
Preferred Stock (the "Senior Preferred") and a $90,000 principal amount non-
recourse note payable out of TGX's share of proceeds, if any, to be received
from the NFG Litigation. As a result of the Administrative Note renegotiations
and administrative claim forfeitures, the Company reflected an extraordinary
net gain in 1995 and 1994 of $93,000 and $831,000, respectively, and all such
notes and claims were deemed settled as of year end 1995.
NFG Litigation
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The NFG Contract was executed in 1974 between Paragon Resources, Inc.
("Paragon") and Iroquois Gas Corporation, predecessors of TGX and NFG, as
seller and buyer, respectively. In 1983, the New York State Public Service
Commission (the "PSC"), under whose jurisdiction NFG's intrastate gas purchases
fall, expressed dissatisfaction with the NFG Contract for among other reasons
the inclusion of a "three-pipeline escalator" ("3-PE") in its pricing provision.
The price formula was based on the average price charged NFG by its three
interstate pipeline suppliers. Pursuant to the 3-PE, the contract price
increased annually by the greater of (1) the increase in the three pipeline
average or (2) $0.02 per Mcf. The PSC, in its Opinion No. 83-26 ("Opinion 83-
26"), found 3-PE clauses to be unacceptable and "disapproved" contracts
containing such clauses.
A dispute arose between NFG and TGX as to whether the NFG Contract remained
in force after Opinion 83-26 and, if it did, what price the NFG Contract
prescribed starting in December, 1983 when Opinion 83-26 was issued. In
November 1984, NFG commenced an action in the United States District Court for
the Western District of New York (Civ. No. 84-1372E) (the "District Court")
seeking a declaration from the District Court of the rights and obligations of
the parties under the NFG Contract after Opinion 83-26. TGX counterclaimed for
damages claiming that NFG had breached the terms of the NFG Contract. The NFG
Litigation addresses, among other things, the validity of the NFG Contract,
the price for gas sold, and certain other claims relating to NFG's obligation
to take or pay for, even if not taken, gas dedicated to the NFG Contract. The
PSC intervened as a plaintiff in the District Court action. In March 1989, a
separate action for breach of contract was commenced by TGX against NFG in New
York's Supreme Court, County of Chautauqua (Index No. G-13357). This case was
stayed in 1989 on the grounds that the issues in this case are the same as those
in the District Court action.
Both NFG and the PSC took the position before the District Court that the
effect of Opinion 83-26 was to cancel the NFG Contract in its entirety. In
January 1991, the District Court declared that because Opinion 83-26 had
abrogated an essential term of the NFG Contract, it had voided the entire NFG
Contract.
In December 1991, the Court of Appeals for the Second Circuit (the "Second
Circuit") reversed the judgment of the District Court. The Second Circuit held
that the PSC had authority to review the NFG Contract under New York Public
Service Law but then addressed the issue of whether Opinion 83-26 impacted
solely upon the price term of the NFG Contract or whether it operated to cancel
the entire NFG Contract. The Second Circuit held that only the price term had
been rejected by the PSC but that such rejection did not void the entire NFG
Contract, which clearly envisioned potential governmental rulings like Opinion
83-26. Therefore, the Second Circuit permitted TGX to continue to deliver gas
under the NFG Contract in the aftermath of Opinion 83-26 at a price consistent
with that Opinion. This left the issue of the appropriate price under the NFG
Contract once the 3-PE escalator was canceled.
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In attempting to determine the appropriate NFG Contract price, the Second
Circuit held that TGX and NFG through their course of conduct had elected to
sell gas in accordance with the Natural Gas Policy Act ("NGPA"), 15 USC (S)3301
et seq., a federal statute that became effective in 1978, subjecting the NFG
Contract to federal regulation. The NGPA set maximum prices for various
categories of intrastate gas, which the producer could charge unless some lower
price were applicable pursuant to pre-NGPA contract. Based upon this holding,
when the Second Circuit remanded the case to the District Court for further
proceedings consistent with its decision, TGX took the position that it was
entitled to recover NGPA prices.
NFG interprets the Second Circuit decision differently. It has taken the
position that the PSC imposed a ceiling on all future gas purchases under the
NFG Contract based on the price of No. 6 fuel oil and that the Second Circuit
endorsed this ceiling. Although the PSC has not yet ruled on this issue, in a
brief to the District Court, the PSC has stated that 90 percent of No. 6 fuel
oil was "the standard to which the Commission looked in 1983 to review the
contract".
In the District Court, after the Second Circuit's remand, TGX has taken
the position that No. 6 fuel oil was a "ceiling" set by the PSC only in the
sense that the PSC in 1975 approved a type of price escalation clause in future
gas purchase agreements that contained a ceiling based on 90% of the 12-month
rolling average price of No. 6 fuel oil in National Fuel's service territory
(the "FPC escalator"). TGX further argues that the ceiling was never imposed by
the PSC on the NFG Contract or on any contracts that contained a 3-PE; it was
limited to contracts that contained the FPC escalator; the PSC refused to
impose a price cap based on the price of No. 6 fuel oil in Opinion 83-26; and
although the PSC could have set a maximum price for gas that was lower than that
provided in the NGPA, it never did so. TGX takes the position that if, and
only if, New York State had enacted a state maximum price for gas would the
parties be bound thereby.
At the time of Opinion 83-26, prices measured under the 3-PE, the NGPA,
the No. 6 oil prices, and prices NFG paid for other local production were all
in a range within or near $4 to $5 per Mcf, where they converged much more
closely than today. By 1992, other local producer's prices and the oil price
fell to the $2 range, the NGPA limits climbed to the $6 and $7 ranges, and the
3-PE price surpassed $8.
Although NFG has taken the position that there was a PSC ceiling, it has
also argued that TGX is not entitled to receive any amount in excess of the
amount TGX has already received. Such prices paid by NFG were based on many
different theories including prices based upon other long-term contracts, spot
prices, weighted average cost of gas, etc.
On remand from the Second Circuit, in January 1993, the District Court
granted TGX's motion for partial summary judgment regarding the price to be paid
under the NFG Contract. Based on the District Court's order, TGX has concluded
that from December 1983, until at least January 1, 1993, the date price
controls under the NGPA were terminated, the price under the NFG Contract is
equal to the lower of (i) the applicable maximum lawful price for December 1983
and for each month thereafter as established by the NGPA, subject to the
escalations provided by the NGPA, or (ii) the December 1983 permitted price
under the NFG Contract of approximately $4.41 per Mcf. The District 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. The District Court did not address the impact, if any, of
the termination of the NGPA.
In response to NFG's request for clarification, the District Court stated
in July 1993 that its January ruling "did not determine the just and reasonable
price for the gas pursuant to [New York Public Service Law} (S)1104(4), set a
contract price for the duration of the contract, resolve any
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defenses presented by NFG, determine whether such obligation continues until
the present time or rule on any deregulation issues."
NFG has interpreted this subsequent decision as denying that a price had
been set. NFG further takes the position that ultimately only the PSC has
jurisdiction to approve any price payable under the NFG Contract. TGX has taken
the position that the clarifying decision contained a reaffirmation of the prior
decision when it stated that:
This Court's Memorandum and Order dated January 4, 1993 determined
that an obligation on NFG's part to pay for gas purchased pursuant to
the [NFG Contract] at the applicable NGPA ceiling price arose out of
the conduct of the parties after the NGPA became effective and that
the PSC Order issued December 20, 1983 did not relieve NFG of such
obligation.
In December 1992, NFG filed a motion with the PSC requesting a hearing to
determine pricing issues related to the NFG Contract. Pursuant to this request,
the PSC ordered that a proceeding take place. After the submission of
substantial evidence and briefs, the Administrative Law Judge ("ALJ") assigned
by the PSC to hear this matter determined in a Recommended Decision issued in
November 1994 that the PSC should find that from December 20, 1983 through
November 1992 (the period of time at issue in the proceeding), the maximum
contract price that would be just and reasonable within the meaning of the
Public Service Law was $3.714 per Mcf of gas, which represents the weighted
average of the two applicable NGPA categorized maximum prices for December 1983.
In this proceeding, the PSC staff took the position that the only reasonable
price would be the market price at the time of each sale of gas.
The ALJ's Recommended Decision along with the briefs of the parties were
submitted to the PSC for its review. Despite the fact that the PSC had ordered
the proceeding at NFG's request, in Opinion No. 95-5, issued in May 1995 (the
"PSC's 1995 Decision"), the PSC decided that the matter was not ripe for its
review because, in its view, there was currently no contract price in the
contract for the PSC to review. The PSC declined to endorse the $3.714 price in
the ALJ's Recommended Decision or any other price. The PSC determined that
NFG's requested hearing and the dealings after 1983 between NFG and TGX did not
constitute the type of filing appropriate for PSC review. The PSC stated that
it would not determine whether a price to be paid under the NFG Contract was
appropriate until such time that such price was finally agreed to by the parties
or determined by the District Court. The District Court would also determine
the continued validity of the NFG Contract.
The PSC left open the possibility that it might review the NFG Contract
after the completion of the District Court litigation. Thus, even if TGX
succeeds in the District Court action, it is possible that the PSC will attempt
to disapprove the contract price set by the District Court. This is an issue
that has not yet been addressed by the District Court.
In September 1994, TGX amended and supplemented its counterclaims in the
District Court action to assert additional claims against NFG for breach and
repudiation of the NFG Contract and for punitive damages based upon NFG's bad
faith course of conduct towards TGX.
NFG has raised various defenses against TGX's counterclaim in the District
Court action including claims that TGX itself repudiated and breached the
contract by its conduct; a claim that the assignment of the contract from
Paragon to TGX was not valid; procedural and jurisdictional defenses; defenses
based upon the Public Service Law; a claim that TGX failed to fix a price in
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good faith after the issuance of Opinion 83-26; and a claim for setoffs for
unspecified damages to NFG's facilities.
The Magistrate Judge assigned to monitor pre-trial discovery in the
District Court action has issued a scheduling order pursuant to which the
parties have been engaged in costly documentary discovery into the allegations
raised by the pleadings in the litigation. Although the current scheduling
order anticipates that discovery will be completed by September 1996, it is not
possible to predict when this litigation will come to an end given the possible
appeals and collateral PSC proceedings that may take place, nor is it possible
to predict the likely outcome of the litigation.
Subsequent to the PSC's 1995 Decision, NFG in 1995, brought a special
proceeding in the New York State Supreme Court, Albany County, seeking a
judgment annulling, as effected by an error of law, so much of the PSC's 1995
Decision as dismissed NFG's request for declaratory ruling that TGX's wholesale
charges for certain gas sold or delivered to NFG in the aftermath of Opinion 83-
26 were consistent with the Public Service Law (S)110(4) "just and reasonable
charge" standard. TGX intervened in this proceeding to protect its interests.
This special proceeding was dismissed by NFG in January, 1996 based upon the
PSC's agreement to represent that its articulated reasons for dismissing NFG's
petition should be understood as constituting an exercise of the PSC's
discretion under (S)204 of the State Administrative Procedure Act to decline to
entertain NFG's request for a declaratory ruling.
During its 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 NFG Contract. Effective
June 19, 1992, TGX and NFG entered into a partial settlement agreement, and,
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 which may be adjudged
due TGX from NFG.
On April 12, 1996, a final settlement of the NFG Litigation was reached.
In return for a lump-sum payment to TGX of $7.2 million, of which TGX will
retain approximately $3.5 million after a debt retirement payment of $3.6
million and a $.1 million payment to another party entitled to participate in
the proceeds, a full release of all claims between the parties was executed.
See Notes 3, 14 and 15 of the Notes to Consolidated Financial Statements.
As part of its sale of substantially all of its oil and gas properties in
Ohio and New York to BBC in January 1994, TGX assigned the NFG Contract to BBC
effective December 1, 1993. TGX's assignment of the NFG 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.
As a result of the matters described herein, TGX is not in a position to
determine when, if ever, a final resolution of the dispute concerning the NFG
Contract will be reached or the effect on TGX's financial position and results
of operation of any such resolution.
8
<PAGE>
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.
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 interests 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 value of 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 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 at the time 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 implemented 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 revenue with the
related exploration and production cost and expense. See Note 1 to Notes to
Consolidated Financial Statements.
9
<PAGE>
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 required to be the chief
executive officer of the Company. See "Item 10. Directors and Executive
Officers of the Registrant". Subsequent to January 1995 the Company amended
its by-laws to provide for a Board of five members. Currently the Board
consists of three members who will serve until their successors are duly elected
and qualified. When new directors are elected, the Plan provides that
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, to whatever number of directors is provided for in the Company's by-
laws, 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".
10
<PAGE>
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 shares of
Senior Preferred authorized is 10,000,000.
Senior Preferred
- ----------------
The Plan provided 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 was 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").
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.
11
<PAGE>
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 24,956,033 shares were outstanding as of March 21, 1996. 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.
12
<PAGE>
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. However, the current NYMEX natural gas future
contract price for the delivery month of April 1996 is $1.975/MMBTU as compared
to $1.46/MMBTU for the same period in 1995. This increase is primarily the
result of an unusually cold winter for 1995 and corresponding declines in gas
storage. It is impossible to know if the current favorable prices will remain
beyond the 1996 heating season. Also, the NYMEX natural gas futures price is
only an indicator of price trends and such price may not be indicative of prices
ultimately realized at the wellhead. As of March 1, 1996, the per barrel posted
price for West Texas Intermediate oil production ("WTI"), which serves as the
benchmark for domestic oil prices, was $18.00 as compared to $17.00 for the same
date in 1995. Though oil prices are currently higher than the prior year, the
price continues to fluctuate significantly. Price uncertainty in the oil and
natural gas industry and economic and political conditions continue to
adversely affect the industry. These conditions, added to other factors
particular to TGX, have adversely affected the business of the Company over
recent years and may continue to do so.
Oil and Gas Exploration and Production
- --------------------------------------
The Company's principal post bankruptcy activity, prior to 1995, was the
production of oil and natural gas. In 1995, the Company began a modest
program of oil and natural gas exploration and development drilling and property
acquisition activities as allowed by its financial condition. The Company
continues to maintain a staff of professional and support personnel required to
manage its existing properties, including one engineer, and four marketing and
land personnel. In addition, the Company engages 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
13
<PAGE>
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, 1996, utilizing year end product
prices and costs held constant, the Company's proved oil and natural gas
reserve volumes, in thousand of barrels of oil ("MBbls") and billion of cubic
feet of gas ("Bcf"), and associated estimated future net revenues,
undiscounted and discounted at 10% ("PV 10"), are as follows (dollars in
thousands):
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------
1995 1994 1993
------------------------ ------------------------ --------------------
Oil(Mbbl) Gas(Bcf) Oil(Mbbl) Gas(Bcf) Oil(Mbbl) Gas(Bcf)
--------- ------------- --------- ------------- --------- --------
- --------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Proved developed 465 9.7 444 7.8 525 9.1
Proved undeveloped 479 2.5 487 2.6 - -
- --------------------------------------------------------------------------------------------------------------
Total proved reserves 944 12.2 931 10.4 525 9.1
==============================================================================================================
1995 1994 1993
------------------------ ------------------------ -----------------------
Undiscounted PV 10 Undiscounted PV-10 Undiscounted PV-10
------------ -------- ------------ --------- ------------ --------
Proved developed $13,831 $ 8,816 $ 9,571 $6,594 $16,078 $10,943
Proved undeveloped 7,054 2,988 5,243 2,213 -- --
- ---------------------------------------------------------------------------------------------------------
Total proved reserves $20,885 $11,804 $14,814 $8,807 $16,078 $10,943
=========================================================================================================
</TABLE>
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 disclosure. The addition of the proved undeveloped reserves
was reflected as 1994 extensions and discoveries. The 1995 report disclosures
continue to include proved undeveloped reserves. Estimated future development
costs associated with proved developed non-producing and proved undeveloped
reserves for 1995 and 1994 total $3.8 and $3.6 million, respectively.
Production of those reserves is dependent upon the Company's ability to fund
such future development costs, which are scheduled to be incurred over numerous
years. The 1993 reserve disclosure continues 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
14
<PAGE>
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 for the periods indicated. Reserves are
stated in thousands of barrels of oil and billions of cubic feet of natural gas.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------
1995 1994 1993
------------ ----------------- -----------------
Oil Gas Oil Gas Oil Gas
- --------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves:
Beginning of year 931 10.4 525 9.1 980 72.2
Sales of reserves-in-place (2) -- (37) (.5) (111) (62.0)
Purchases of reserves-in-place 22 1.2 -- -- -- --
Extensions and discoveries 1 0.1 487 2.6 -- --
Revisions of previous estimates 55 2.2 18 1.4 (257) 2.6
Production (1) (63) (1.7) (62) (2.2) (87) (3.7)
- --------------------------------------------------------------------------------------------------------
End of year 944 12.2 931 10.4 525 9.1
========================================================================================================
Proved-developed reserves 465 9.7 444 7.8 525 9.1
========================================================================================================
</TABLE>
(1) 1995 and 1994 includes .220 and .590 Bcf, balancing collections,
respectively, of gas volumes related to gas balancing collections.
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 disclosure. The addition of the proved undeveloped reserves
is reflected as 1994 extensions and discoveries. The 1995 report disclosures
continue to include proved undeveloped reserves. The 1993 reserve disclosure
continues to be reported utilizing only proved developed reserves.
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.
15
<PAGE>
Oil and Gas Production
- ----------------------
Information pertaining to the Company's oil and natural gas production is
set forth in the table below :
<TABLE>
<CAPTION>
Year Ended December 31,
1995 1994 1993
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
Oil sales volume (MBbls) 63 62 87
Average price per barrel $ 17.20 $ 15.24 $ 17.10
Natural gas sales volume (Bcf) (1) 1.701 2.241 3.712
Average price per Mcf $ 1.49 $ 1.72 $ 2.22
Equivalent Mcf (6:1) 2.078 2.613 4.234
Lease operating expense per equivalent Mcf $ 0.92 $ 1.06 $ 0.93
Net oil and natural gas revenues (in thousands):
Sales revenues $ 3,611 $ 4,802 $ 9,730
Lease operating expenses (1,905) (2,772) (3,935)
- ---------------------------------------------------------------------------------------
Net oil and natural gas revenues $ 1,706 $ 2,030 $ 5,795
=======================================================================================
</TABLE>
(1) 1995 and 1994 includes .220 and .590 Bcf, respectively, of gas volumes and
$213,000 and $634,000, respectively, of natural gas revenues related to gas
balancing collections.
Drilling Activity
- -----------------
In 1995 as a result of the Company's improving financial condition, the
Company participated in one (net .07) successful and one (net .16) unsuccessful
exploration well and three (net.47) successful and two (net .30) unsuccessful
development wells. The Company had a 50% success ratio regarding exploration
well activity and a 60% success ratio regarding development drilling activity.
Company net drilling costs for 1995 totaled $372,000 of which $69,000 was
expensed as unsuccessful exploration cost. The Company also acquired five (net
1.55) additional wells and interest in existing operated wells at a net cost of
$771,000 and implemented workover operations on ten (net 3.69) operated wells at
a net cost of $274,000. Drilling, acquisition and workover activity for 1995
resulted in a weighted average finding cost per equivalent barrel of oil of
$3.32. In 1994, the Company participated only in the recompletion attempt of one
unsuccessful exploration well (net .55). During 1993, the Company participated
in no significant drilling or workover operations.
16
<PAGE>
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 as of December 31, 1995.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------------
Undeveloped developed Productive
Acreage Acreage Wells/(1)/
------- ------- ----------
Gross/(2)/ Net/(3)/ Gross/(2)/ Net/(3)/ Gross/(2)/ Net/(3)/
--------- -------- ---------- -------- ---------- --------
<S> <C> <C> <C> <C> <C> <C>
Arkansas 50 31 2,760 977 41 15
Louisiana 1,048 533 5,726 1,294 11 2
Oklahoma 4,731 633 36,657 3,797 61 6
Texas 9,835 1,102 24 4
Other states 1,800 675 12 4
- ------------------------------------------------------------------------------------------------------------
Total 5,829 1,197 56,778 7,845 149 31
============================================================================================================
</TABLE>
/(1)/ Productive wells are wells capable of producing oil or natural gas.
/(2)/ Gross represents the total number of acres or wells in which the Company
owns a working interest.
/(3)/ Net represents the Company's proportionate working interest resulting
from its ownership in the gross
acres or wells.
The following table provides, as of December 31 for each year presented
excluding Sold Properties for 1993 and 1994, and managed partnership wells
liquidated in 1995, additional information pertaining to the productive wells
in which the Company owns a working interest.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------
Gross /(1)/ Net /(2)/
--------------- -----------------
- ------------------------------------------------------------------------------------------------------------
Oil Gas Total Oil Gas Total
- ------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1993 72 93 165 18 14 32
1994 58 89 147 17 13 30
1995 56 93 149 17 14 31
- ------------------------------------------------------------------------------------------------------------
</TABLE>
/(1)/ Gross wells are the total number of wells in which the Company owns a
working interest.
/(2)/ Net represents the Company's proportionate interest resulting from its
working interest ownership in each gross well.
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 account and beneficially through the Amarex Partnerships. The Company
liquidated 17 and 8 partnerships during 1994 and 1995, respectively, 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 receivables was
17
<PAGE>
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. As a result of
partnership liquidation efforts, the Company at December 31, 1995 was not
managing general partner for any partnerships.
Natural Gas Treating Plant
- --------------------------
Through a joint venture, the Company owns a 35% 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 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. In addition, the joint venture charges
the Company for gas treating and such charges are included in operating
expenses. 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 have 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. A trend has emerged recently among major
natural gas marketing companies toward consolidations and mergers, both amongst
themselves as well as in the form of strategic alliances with large producers or
end-users. These consolidations have the effect of putting control of the
majority of the supply and the market in hands of a few industry participants.
The longer term ramifications of this trend are difficult to foresee, but will
likely have an impact on the way natural gas is bought and sold in the future
and this impact could be potentially more significant to the smaller independent
producers such as the Company.
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 alternative 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 in 1993, the
Company no longer makes any significant natural gas sales to NFG.
18
<PAGE>
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 attempts to obtain and maintain
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.
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 had historically been regulated by
the Federal Energy Regulatory Commission ("FERC") under the authority of the
Natural Gas Policy Act of 1978 ("NGPA"), which established price controls for
various classifications of gas. However, as a result of the Wellhead Decontrol
Act of 1989, all NGPA price controls were terminated as of January 1, 1993.
Except for any effect that such termination may effect the price provisions
being contested is the NFG Litigation, 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.
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
19
<PAGE>
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 and Management.
Employees
- ---------
As of December 31, 1995, the Company employed 14 persons, none of whom are
represented by a labor union or collective bargaining agent. Also at December
31, 1995, the Company had engaged five persons on a temporary contract basis to
perform certain engineering and 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.
ITEM 2. PROPERTIES
For information concerning the Company's properties, see "Item 1.
Business-Business Segment Information".
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 reduced 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.
On May 31, 1995, the Company entered into a Settlement Agreement among
itself, Paragon Resources, Inc., J.C. Templeton, W.M. Templeton and a number of
other former directors of the Company, trusts on behalf of members of the
Templeton family and other entities pursuant to which all lawsuits between and
among the parties were dismissed with prejudice. In consideration
20
<PAGE>
therefor, the Company received $325,000, an assignment of certain oil and gas
leases, and receipt of past due joint operating expenses payable by certain of
the defendants. The Company released lis pendens against certain of the
defendant's properties and conveyed to the defendants an interest in certain
properties to which they were entitled. The parties to the litigation also
conveyed to the Company any Common Stock or Preferred Stock which they held.
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 had not been properly credited
to the interests of the unleased mineral interest owners. In July 1995, in a
separate action, certain royalty owners in the same wells commenced a legal
action alleging that TGX and other working interest owners improperly profited
under the terms of a Gas Gathering and Transportation Agreement dated December
12, 1983. Both cases are 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 prepetition and administrative claims related to an
overriding royalty interest previously conveyed by TGX. During that hearing, the
parties stipulated that the finally allowed amount of claimant's prepetition
claim would be $600,000. That prepetition claim has been fully satisfied by the
issuance of Senior Preferred. The Company had previously estimated that
prepetition claim in that amount, and therefore it had been reflected in prior
years' financial statements. Subsequent to the March 1994 hearing, and after
post-hearing motions from both TGX and the claimant, the Bankruptcy Court
entered an order on September 7, 1994 which determined that the claimant would
be granted an allowed administrative expense claim for unpaid overriding
royalties arising post-petition but prior to October 4, 1992 in the amount of
$244,000. That administrative claim, when finally allowed, is to be treated by
the issuance of an Administrative Note under the terms of the Plan and is to be
payable under the terms of the Plan. The Bankruptcy Court further ruled that it
would not exercise any jurisdiction over claims for alleged unpaid overriding
royalties arising subsequent to October 4, 1992. TGX believes that the
Bankruptcy Court erred in its determination of unpaid overriding royalties, and
has appealed the Bankruptcy Court's ruling to the United States District Court
for the Western District of Louisiana. That appeal has been fully briefed, but
no decision has been rendered.
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 1995, no matters were submitted to a vote of
the security holders.
21
<PAGE>
PART II.
ITEM 5. MARKET FOR THE REGISTRANT'S 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 listed on the NASD's "bulletin board".
As of March 21, 1996, there were approximately 3,989 holders of record of
the Company's Common Stock, and 1,563 holders of record of the Senior Preferred.
The following table sets forth bid prices reported by the National Quotations
Bureau, Inc., for the Company's Common Stock. Trading of the Company's Common
Stock is very sporadic. There is no market for the Senior Preferred Stock. All
quotations represent bid prices between dealers without retail markup or
markdown or commission and do not reflect actual transactions.
Quarter Ended High Low
- --------------- ----- ------
1995:
- -----
March 31 $ .03 $.001
June 30 .005 .005
September 30 .01 .01
December 31 .01 .002
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
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, 1995, the redemption value and accrued dividends related to the
Senior Preferred were $88,514,000 and $40,421,000, 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 $88,514,000 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 does not anticipate paying, any cash
dividends to its Preferred or Common Stockholders. The Company is prohibited
from paying dividends on its
22
<PAGE>
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 21, 1996, the closing bid and asked price per share of the Common
Stock, as reported by the National Quotations Bureau, Inc., was $.001. Trading
of the Company's Common Stock is very sporadic.
The Senior Preferred has not been traded, and therefore, the Company cannot
determine the market value, if any, therefor.
23
<PAGE>
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.
<TABLE>
<CAPTION>
Reorganized Company /(1)/
---------------------------
(Thousands except per share data) Year Ended December 31,
-----------------------------------------
1995 /(2)/ 1994/ (2)/ 1993
------------ ------------ ---------
RESULTS OF OPERATIONS: (Restated)
<S> <C> <C> <C>
From oil and natural gas operations:
Revenues $ 4,597 $ 6,498 $ 10,997
Gross profit 1,706 2,030 5,795
Net loss applicable to common stock (17,693) (15,476) (26,951)
Per common share (0.71) (0.61) (1.06)
Average common shares outstanding 25,105 25,314 25,314
Capital expenditures 1,128 27 394
FINANCIAL POSITION AT END OF PERIOD
Working capital (deficit) $ (1,771) $ (1,319) $ (9,209)
Property and equipment, net 7,411 7,257 9,404
Total assets 9,791 10,676 30,065
Long-term debt 5,835 6,020 --
Redeemable Senior Preferred Stock 61,737 44,602 30,013
Stockholders' equity (deficit) (61,134) (43,711) (28,505)
COMMON STOCK:
Shares outstanding at end of period 24,956 25,314 25,314
Cash dividends paid -- -- --
- -----------------------------------------
</TABLE>
(1) As used herein, "Reorganized Company" means the operations of the Company
subsequent to October 2, 1992, the effective date of the order regarding
substantial consummation of the Plan. 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) Period results restated as discussed in Note 15 of the Notes to the
Consolidated Financial Statements included elsewhere herein.
24
<PAGE>
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
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.
Forward-looking statements in this report are made pursuant to the safe
harbor provisions of the Private Securities Litigation Reform Act of 1995.
Investors are cautioned that all forward-looking statements involve risks and
uncertainty, including without limitation, the costs of exploring and developing
new oil and natural gas reserves, the price for which such reserves can be sold,
the Company's attempts to reduce overhead and eliminate non-core assets,
environmental concerns effecting the drilling of oil and natural gas wells, the
possibility of a corporate restructuring, the ongoing costs and results of
litigation concerning NFG, as well as general market conditions, competition and
pricing. Please refer to the Company's Securities and Exchange Commission
filings, copies of which are available from the Com pany without charge, for
further information.
Amounts in this discussion and analysis have been restated as disclosed in
Note 15 of the Notes to Consolidated Financial Statements.
RESULTS OF OPERATIONS
---------------------
A comparison of significant operating income components for 1995 as
compared to 1994 is (amounts in thousands):
<TABLE>
<CAPTION>
1995 1994 Change
-------- -------- --------
<S> <C> <C> <C>
Oil and natural gas revenues $ 3,611 $ 4,802 (25%)
Gas gathering and equity in treating revenues 694 727 (4%)
Gain on property sales, net, and other revenues 292 969 (70%)
Operating and exploration expenses (1,974) (3,188) (38%)
Depletion, depreciation and amortization (973) (1,414) (31%)
General and administrative expenses (1,476) (2,239) (34%)
------- -------
Operating income (loss) $ 174 $ (343) (151%)
======= ======= =====
</TABLE>
Operating results for 1995 and 1994 were significantly impacted by
management's continuing efforts regarding cost reductions and revenue collection
accelerations. As a result, operating income (loss) for 1995 and 1994 benefitted
from collection of previously allowed for receivables of $425,000 and $751,000,
respectively, and gas balancing revenues, net of operating expenses and
production taxes, of $213,000 and $634,000, respectively. Operating results for
25
<PAGE>
1995 also included a pre-petition franchise tax settlement benefit, including
interest, of $251,000. Excluding receivable recoupments, gas balancing net
revenues and tax settlement benefit, operating results for 1995 and 1994 would
have been losses of $715,000 and $1,728,000, respectively.
Revenues
- --------
Consolidated revenues for 1995 declined by 29% or $1,901,000 to $4,597,000
as compared to $6,498,000 for 1994. The decrease in consolidated revenues was
primarily the result of lower gas revenues and a decrease in gains on property
sales and other revenues. Oil and natural gas sale revenues for 1995 decreased
by $1,191,000 due to a decline in gas sales of $1,332,000, which was partially
offset by an increase in oil sales of $141,000. Property sales and other
revenues declined by $677,000.
The natural gas sales revenue decline of $1,332,000 is primarily the result
of lower sales volumes due to an anticipated decline in gas balancing
collections and a significant decline in the sales price received per Mcf.
Natural gas sales volume for 1995, including volumes associated with gas
balancing, declined by 24%, resulting in lower revenues of $930,000. Of the
volume decrease in gas revenues, 68% or $589,000 was directly the result of
lower gas balancing revenue collections. 1995 and 1994 natural gas sales include
gas balancing revenues of $220,000 and $809,000, respectively, representing
production volumes, net to the Company, of 220,000 and 590,000 Mcf. The Company
records gas balancing revenues on the net sales method as opposed to the
entitlement method and thus revenues are recorded when received or operations
merit accrual. The decrease in 1995 gas balancing revenues and volumes was
anticipated due to the Company's collection efforts, which primarily commenced
in 1994, being now significantly completed. The decline in gas sales volumes for
1995 was further impacted by the recognition of a lower interest in one well in
Arkansas resulting from conveyance of an interest due to litigation settlement
and volumetric gas balancing regarding a Company operated well in Louisiana. The
lower well interest and Louisiana balancing settlement decreased 1995 sales
volumes by approximately 175,000 Mcf. Excluding gas balancing volumes and impact
of the lower interest in the Arkansas well, gas sales volumes for 1995 were
relatively flat to 1994. For 1995, the natural gas price received, including gas
balancing collections, averaged $1.49 per Mcf as compared to 1994's average of
$1.72 per Mcf. The 13% decline in Mcf price received resulted in a decrease in
1995 revenues of $402,000. Excluding gas balancing collection revenues, the
average price received per Mcf for 1995 and 1994 was $1.56 and $1.85,
respectively.
The revenue decline resulting from natural gas was partially offset by
higher oil revenues of $141,000. The average oil price for 1995 was $17.20 as
compared to $15.24 for 1994, a 13% increase. The increase in oil price resulted
in $123,000 of additional 1995 oil revenues while a 2% increase in oil sales
volumes contributed $18,000 of additional revenues.
26
<PAGE>
A summary of oil and natural gas sale volumes and revenues for the respective
years is:
Summary of Oil Volumes and Revenues
- --------------------------------------------------------------------
1995 1994 Change
- --------------------------------------------------------------------
Oil revenues (in thousands) $ 1,081 $ 940 15%
Oil sales volume (barrels) 62,900 61,700 2%
Oil average price per barrel $ 17.19 $ 15.24 13%
- --------------------------------------------------------------------
Summary of Natural Gas Volumes and Revenues
- --------------------------------------------------------------------
1995 1994 Change
- --------------------------------------------------------------------
Natural gas revenues (in thousands) $2,530 $3,862 (34%)
Natural gas sales volume (Bcf) 1.701 2.241 (24%)
Natural gas average sales price per Mcf $ 1.49 $ 1.72 (13%)
- --------------------------------------------------------------------
On an equivalent unit basis (one barrel of oil equals six Mcf of natural
gas on a heating value basis), natural gas for 1995 represented 82% of the
Company's oil and natural gas sales volumes and 70% of total oil and natural gas
revenues. Based on the January 1, 1996 independent reserve report, gas
production will continue to be the dominant production product and will
represent approximately 80% of the Company's future oil and natural gas
production volumes on an equivalent unit basis.
Natural gas gathering and treating revenues decreased by 4% or $33,000 to
$694,000 in 1995 as compared to $727,000 in 1994. This decrease is primarily
attributable to continued field production declines.
During 1994, the Company sold both nonstrategic producing wells and
undeveloped acreage for a total of $2,174,000, resulting in a net gain of
$766,000. This compares to 1995's sale of nonstrategic producing wells and other
assets for $168,000, resulting in a net gain of $68,000. The producing wells
sold in 1994, for $1,424,000, represented the Company's interest in certain
partnerships, sold primarily effective February 1, 1994, and yielded the entire
1994 gain of $766,000. The Company in 1994 also sold nonstrategic undeveloped
acreage in the New York area for $750,000 which represented net book value. The
1994 sales were the result of the Company's continuing effort to liquidate
various private and public partnerships for which it was managing general
partner and nonstrategic assets. With the liquidation of the remaining eight
public partnerships in 1995, such partnership liquidation effort is deemed
completed, but the Company will continue to evaluate the merit of sales of
nonstrategic and marginally profitable assets.
Other net revenues increased by 10% or $21,000 to $224,000 in 1995 as
compared to $203,000 in 1994. Other revenues for 1995 consisted of interest
income of $163,000 related to a pre-petition franchise tax settlement with the
remaining balance being comprised primarily of bankruptcy preference claim
settlements. Other revenues for 1994 consisted of interest income of $22,000
with the remaining balance representing various one-time suspense and bankruptcy
preference claim settlements. No additional settlements regarding preference
claims are anticipated in 1996.
27
<PAGE>
Costs and Expenses
- ------------------
Consolidated costs and expenses decreased by $2,998,000 or 37% to
$5,030,000 for 1995 as compared to $8,028,000 for 1994. This decrease was due to
declines in all expense categories, with significant decreases in operating and
exploration costs and general and administrative and interest expenses.
Operating expenses for 1995 decreased $867,000 or 31% to $1,905,000 as
compared to $2,772,000 for 1994. Included in operating expenses for 1995 and
1994 is $141,000, respectively, of production taxes and $274,000 and $167,000,
respectively, of workover costs. Workover costs represent discretionary non-
recurring well production activities that are implemented to enhance or increase
production. A significant portion of these costs are related to the Company's
major field in Arkansas and resulted in increases in production. Additional
workovers are scheduled for 1996. Operating expenses in 1994 included $174,000
of transportation costs related to a portion of the $809,000 of gas balancing
revenues recorded during the year and the reclassification of approximately
$260,000 of general and umbrella liability insurance costs to operating
expenses. Normal operating costs on an equivalent Mcf basis, after excluding
production taxes, workover costs and 1994 gas balancing transportation and
insurance adjustments, are $0.69 and $0.78 for 1995 and 1994, respectively.
Pursuant to successful efforts reporting, unsuccessful exploration costs
are expensed as opposed to capitalized. For 1995 such costs represented activity
on three gross wells at a net cost to the Company of $69,000. Exploration costs
for 1994 of $416,000 related primarily to the unsuccessful attempts regarding
the Starkey No. 1 located in Comite Field, East Baton Rouge Parish.
Depreciation, depletion and amortization ("DD&A") decreased by $441,000 or
31% due to lower sales volumes and a lower DD&A rate per equivalent Mcf sold.
During 1994, management determined that as a result of the Company's improving
financial condition, including expected cash flow for 1995 and beyond and its
borrowing capacity, 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 undeveloped for purposes of
accounting estimates and financial statement disclosure. As a result of
utilizing total proved reserves in the DD&A calculation, depletion, depreciation
and amortization for 1995 and 1994 was reduced by $708,000 and $847,000,
respectively. The weighted average DD&A rate for 1995, on an equivalent Mcf
basis, was $.48 as compared to 1994's rate of $.50.
General and administrative expenses in 1995 decreased $763,000 or 34% to
$1,476,000 from $2,239,000 in 1994. This decrease was primarily the result of
lower franchise taxes and staff and related costs and non-deferrable legal costs
related to the 1994 debt restructuring with BMO. Cost declines in these area
were partially offset by lower net partnership expense reimbursements and
unusually high 1994 receivable allowance recoupments.
The decline in franchise taxes was primarily due to the 1995 settlement of
a pre-petition franchise tax claim resulting in reduction of previously accrued
costs of approximately $166,000. The Company also realized general and
administrative savings in the area of staff costs due to staff reductions
related to property sales and outsourcing of certain accounting and
administrative functions. Net staff cost savings, after adjusting for
outsourcing expenses, for 1995 totaled approximately $358,000. Lower expenses of
approximately $208,000 were also realized in 1995 in the area of professional
fees.
The Company, in 1995, received as a settlement of litigation a combination
of cash and properties totaling approximately $425,000. The $325,000 of cash and
$100,000 of estimated fair market value of properties was deemed a recoupment of
previously allowed for receivables and thus was credited against general and
administrative expenses. In 1994, as a result of the liquidation
28
<PAGE>
of various partnerships for which the Company was managing general partner, the
Company collected certain note and receivable amounts which had been fully
allowed for as doubtful accounts 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 in 1994. As a result of these
major one-time collections, 1994 general and administrative costs reflects a
benefit, in excess of 1995 recoupments, of $291,000.
General and administrative expense reductions for 1995 were partially
offset by a decrease in managed partnership reimbursements. Partnership expense
reimbursements for 1995 and 1994 totaled $424,000 and $684,000, respectively,
with corresponding Company proportionate partnership expense of $25,000 and
$144,000, respectively. The net decrease in partnership reimbursements of
$141,000 was the result of the planned liquidation of all managed partnerships
which was completed in late 1995.
In July 1994, the Company restructured its remaining debt of $4,652,000
with BMO whereby BMO converted the remaining indebtedness to a non-recourse note
secured only by the NFG Litigation proceeds, if any, received therefrom. The
legal costs of $492,000 associated with this restructuring were deemed non-
deferrable and expensed in 1994.
General and administrative costs, excluding partnership reimbursement
declines due to liquidation of such, receivable recoupments and franchise tax
settlement gains, actually declined during 1995 by approximately $572,000.
Interest expense decreased $580,000 or 49% in 1995 to $607,000 from
$1,187,000 in 1994. This decrease is primarily attributable to lower average
debt outstanding and lower interest rates. During 1995, maximum bank borrowings
outstanding, excluding BMOF debt, were $1,150,000 resulting in a year end
balance of $500,000. During 1994, BMO borrowings outstanding peaked at
$19,499,000 resulting in a year end balance of $5,335,000. As a result of the
debt restructuring on July 13, 1994, the Company's per annum interest rate was
reduced from a high of 13% in 1994 to a floating bank rate plus two percent
which resulted in a weighted average rate of approximately 10.7% for 1995 while
the rate on the BMOF non-recourse note was 10%. Also, included in 1995 and 1994
interest expense is $36,000 and $15,000, respectively, of amortization of credit
facility establishment costs. These credit facility establishment fees are being
amortized over the initial term of the facility.
Debt forgiveness for 1995 and 1994 resulted in the recognition of an
extraordinary gain of $93,000 and $831,000, respectively. The 1995 and 1994
gains were derived from Administrative Note settlements and claim forfeitures.
(See "Administrative Claims").
FINANCIAL CONDITION
- -------------------
In 1995, the Company's total capital expenditures were $1,128,000.
Capitalized costs for 1995 consisted of proved property acquisition cost of
$771,000, drilling cost of $303,000 and other miscellaneous asset cost of
$54,000. The Company also incurred workover and dry-hole exploration costs of
$274,000 and $69,000, respectively.
At December 31, 1995, the Company's working capital deficit was $1,771,000
which included $518,000 related to various pre-petition obligations. The current
deficit represents an increase in deficit of $452,000 from the prior year. Based
on current borrowing availability and projected 1996 activity, capital resources
are deemed sufficient for current operating needs.
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. The Bank One credit facility's
borrowings outstanding as of December 31, 1995 totaled $500,000 with a borrowing
base of $2,500,000. The borrowing base is reduced monthly by $50,000. Due to
29
<PAGE>
the excess of borrowing base over year end borrowings outstanding and the
current monthly facility reduction rate, no current maturities for debt are
reflected. The borrowing base is redetermined on a semi-annual basis or at any
time at Bank One's election. 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 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, 1995 was in compliance
with the current ratio and other financial ratios and covenants of the credit
facility. 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
1996. The Bank One credit facility was initially repayable over 36 months and
all borrowings outstanding are due on July 13, 1997. The Company also had
$5,335,000, including paid in kind interest of $683,000, of BMOF nonrecourse
debt, which is secured only by NFG Litigation proceeds, if any, received
therefrom, outstanding at December 31, 1995.
The Series A Redeemable Senior Preferred Stock ("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 the 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 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 and accordingly, it is not classified as a component of
stockholders' equity. At December 31, 1995, the Senior Preferred redemption
value plus accrued dividends for the Senior Preferred were $88,514,000 and
$40,421,000, respectively. These amounts 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, 1995, the Stockholders' deficit was $61,134,000. 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 1995, the Company's cash provided by operating activities was
$1,554,000 and included benefits derived from receivable allowance recoupment of
$425,000, state tax settlements, including interest, of $251,000 and a decrease
in prior year federal tax accrual of $163,000. Included in cash provided by
operating activities is cash received of $588,000 from the Company's 35% equity
investment in the Comite Field Plant Venture.
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. At the December 31, 1995, the borrowing
base under the credit facility was $2,500,000, and the Company had borrowings
outstanding of $500,000 and letter of credit commitments of $25,000. Based on
the borrowing base and borrowings and commitments, the Company at year end had
availability under the facility of $1,975,000. Amounts borrowed under the line
of credit are due July 13, 1997. The December 31, 1995 BMOF debt of $5,335,000,
including interest of $683,000,
30
<PAGE>
represented a non-recourse note, secured only by proceeds, if any, which might
be received from the NFG Litigation.
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 $213,000, net of
expenses, as a result of such negotiations during 1995. 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. Any balancing recoupments or
settlements, which will typically be over a period of time, are not anticipated
to be material to operating results.
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 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. Pursuant to an amended agreement, TGX and BMOF will share
equally any NFG Litigation proceeds up to $8 million. BMOF shall then receive
100% of any proceeds in excess of $8 million until the total received by BMOF
equals the New BMOF Loans of $4,652,000, plus any accrued interest. Thereafter,
the Company will receive proceeds until the total it has received equals the
amount received by BMOF. Any additional NFG Litigation proceeds will be shared
equally by TGX and BMOF. A New York Federal Court held under an order which
appears to set the NFG contract price. Based on the Company's calculation, 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 per
Mcf for winter and $4.01 for summer) is approximately $25,410,000 as of December
31, 1995, including statutory interest. (See Note 14 of the Notes to
Consolidated Financial Statements.)
The Company anticipates that continued development drilling and workovers
will maintain or increase current production volumes. In addition, the Company
is continually evaluating opportunities for acquisition of producing properties
and currently intends to pursue future production volume and reserve base growth
through acquisitions. The current cash balance, projected cash flows from
existing properties and borrowings available under the Company's current line of
credit and expected future credit facility increases are considered adequate to
fund future capital growth plans. Effective implementation of the Company's
development and acquisition plans is expected to meet the Company's long-term
oper ation and liquidity requirements.
During 1996, the Company will continue to review its investment
opportunities, consistent with its available capital, to determine if asset
enhancement can be best obtained through either development of existing proved
developed non-producing reserves, drilling and/or acquisition.
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 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.
31
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Company's consolidated financial statements as of December 31, 1995 and
1994 and for the years then ended and the report of Price Waterhouse LLP,
independent accountants, follow.
32
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
---------------------------------
CONSOLIDATED FINANCIAL STATEMENTS
---------------------------------
To the Board of Directors
and Stockholders of TGX Corporation
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statement of operations and of cash flows present fairly, in all
material respects, the financial position of TGX Corporation and its
subsidiaries (the Company) at December 31, 1995 and 1994, and the results of
their operations and their cash flows for the years then ended 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 15, the Company has restated its 1995 and 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.
Our original report on the accompanying consolidated financial statements
included an explanatory paragraph stating that there was substantial doubt about
the Company's ability to continue as a going concern. As a result of the
proceeds received from a litigation settlement and the effect of the settlement
on ongoing business operations as discussed in Note 14, substantial doubt about
the Company's ability to continue as a going concern has been alleviated.
PRICE WATERHOUSE LLP
Houston, Texas
March 28, 1996, except as to
Note 14 which is as of April 22, 1996
and Note 15 which is as of
January 3, 1997.
33
<PAGE>
TGX Corporation and Subsidiaries
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------------------------
(Restated - Note 15)
December 31,
(Thousands of dollars, except for share data) 1995 1994
- -------------------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents $ 384 $ 676
Accounts receivable, net of allowance for doubtful accounts
of $320 and $373, respectively 1,141 1,206
Accounts receivable from affiliates - Note 10 6 504
Other current assets 51 60
- -------------------------------------------------------------------------------------------------------
Total current assets 1,582 2,446
- -------------------------------------------------------------------------------------------------------
Property and equipment:
Oil and natural gas properties 11,340 10,407
Other property and equipment 203 157
Accumulated depletion, depreciation and amortization (4,132) (3,307)
- -------------------------------------------------------------------------------------------------------
Property and equipment, net 7,411 7,257
- -------------------------------------------------------------------------------------------------------
Investment in Comite Field Plant Venture - Note 5 739 878
Other assets 59 95
- -------------------------------------------------------------------------------------------------------
Total other assets 798 973
- -------------------------------------------------------------------------------------------------------
TOTAL ASSETS $ 9,791 $ 10,676
=======================================================================================================
LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities:
Accounts payable and accrued liabilities - Note 6 $ 3,353 $ 3,352
Accounts payable to affiliates -- 242
Notes payable -- 171
- -------------------------------------------------------------------------------------------------------
Total current liabilities 3,353 3,765
- -------------------------------------------------------------------------------------------------------
Long-term debt - Note 3 5,835 6,020
- -------------------------------------------------------------------------------------------------------
Total liabilities 9,188 9,785
- -------------------------------------------------------------------------------------------------------
Commitments and contingencies - Note 4
Redeemable Senior Preferred Stock, 8,851,360
issued; redemption value $88,514 (1995) and $87,295 (1994) - Note 7 61,737 44,602
- -------------------------------------------------------------------------------------------------------
Stockholder's deficit: - Note 8
9% Cumulative Convertible Preferred Stock, 300,000 shares
issued plus 158,000 (1995) and 131,000 (1994) shares to be issued for
dividends 458 431
Common stock, 28,976,791 shares issued; 24,956,033 (1995) and
25,313,533 (1994) shares outstanding 290 290
Additional paid-in capital 1,422 1,179
Accumulated deficit (63,304) (45,611)
- -------------------------------------------------------------------------------------------------------
Total stockholders' deficit (61,134) (43,711)
- -------------------------------------------------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' DEFICIT $ 9,791 $ 10,676
=======================================================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
34
<PAGE>
TGX Corporation and Subsidiaries
CONSOLIDATED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
(Restated - Note 15)
Year Ended
December 31,
(Thousands of dollars, except for per share data) 1995 1994
- ---------------------------------------------------------------------------
<S> <C> <C>
REVENUES
Oil and natural gas sales $ 3,611 $ 4,802
Natural gas gathering 245 309
Equity earnings in Comite Field Plant Venture 449 418
Gain on property sales 68 766
Other, net 224 203
- ---------------------------------------------------------------------------
4,597 6,498
- ---------------------------------------------------------------------------
COSTS AND EXPENSES
Operating expenses 1,905 2,772
Depletion, depreciation and amortization 973 1,414
Exploration costs 69 416
General and administrative expenses 1,476 2,239
Interest 607 1,187
- ---------------------------------------------------------------------------
5,030 8,028
- ---------------------------------------------------------------------------
LOSS BEFORE INCOME TAXES AND
EXTRAORDINARY GAIN (433) (1,530)
Income tax expense - Note 9 -- 17
- ---------------------------------------------------------------------------
LOSS BEFORE EXTRAORDINARY GAIN
(433) (1,547)
Extraordinary gain - Note 3 93 831
- ---------------------------------------------------------------------------
NET LOSS (340) (716)
Preferred stock dividends (12,308) (10,780)
Accretion of Senior Preferred redemption value (5,045) (3,980)
- ---------------------------------------------------------------------------
NET LOSS APPLICABLE TO COMMON STOCK $(17,693) $(15,476)
===========================================================================
PER SHARE OF COMMON STOCK AMOUNTS:
Before extraordinary gain $(0.71) $(0.64)
Extraordinary gain - 0.03
- ---------------------------------------------------------------------------
NET LOSS $(0.71) $(0.61)
===========================================================================
AVERAGE COMMON SHARES OUTSTANDING 25,105 25,314
===========================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
35
<PAGE>
TGX Corporation and Subsidiaries
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------
(Restated - Note 15)
Year Ended
December 31,
(Thousands of dollars) 1995 1994
- ---------------------------------------------------------------------------------------------
<S> <C> <C>
Cash flows from operating activities:
Net loss $ (340) $ (716)
Adjustments to reconcile net loss to cash provided by operating
activities:
Depletion, depreciation and amortization 973 1,414
Amortization of debt transaction costs and stock compensation 79 114
Distributions in excess of equity earnings 139 106
Non-cash recovery of affiliate receivable - (381)
Recovery of accounts receivable loss provisions - 751
Interest to be paid through issuance of additional notes 465 218
Extraordinary gain (93) (831)
Changes in operating assets and liabilities:
Decrease in accounts receivable 65 492
Decrease in accounts due from/to affiliates, net 256 40
Decrease in other current assets 9 15,216
Decrease in accounts payable and accrued expenses 1 (4,204)
- ---------------------------------------------------------------------------------------------
Net cash provided by operating activities 1,554 12,219
- ---------------------------------------------------------------------------------------------
Cash flows from investing activities:
Capital expenditures (1,128) (27)
Proceeds from disposal of assets 68 1,406
Increase in other assets -- (146)
- ---------------------------------------------------------------------------------------------
Net cash provided by (used in) investing activities (1,060) 1,233
- ---------------------------------------------------------------------------------------------
Cash flows from financing activities:
Principal payments of long-term debt and notes payable (1,601) (16,301)
Advances pursuant to revolving credit facility 850 1,975
Debt transaction costs and other (35) 230
Decrease in affiliate accounts receivable -- 100
- ---------------------------------------------------------------------------------------------
Net cash used in financing activities (786) (13,996)
- ---------------------------------------------------------------------------------------------
Net decrease in cash and cash equivalents (292) (544)
Cash and cash equivalents at beginning of period 676 1,220
- ---------------------------------------------------------------------------------------------
Cash and cash equivalents at end of period $ 384 $ 676
=============================================================================================
Supplemental Disclosure of Non-Cash Investing
and Financing Activities:
Properties acquired through foreclosure on
affiliated partnerships $ -- $ 381
Forgiveness of bank debt and other notes payable $ 93 $ 831
Interest to be paid through issuance of additional notes $ 465 $ 218
</TABLE>
See accompanying notes to consolidated financial statements
36
<PAGE>
TGX Corporation and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 1995 and 1994
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 served 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. See Note 14
below.
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. At year end 1995, all
Company sponsored partnerships had been liquidated. The Company's 35% investment
in a natural gas treating plant 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 costs relating to proved properties are amortized using the
unit-of-production method based on estimated proved reserves. 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 disclosure. As a result of utilizing total proved reserves in the
calculation, depletion, depreciation and amortization for 1995 and 1994 was
reduced by $708,000 and $847,000, respectively. 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. The Company purchased certain producing properties for $771,000
in 1995 with
37
<PAGE>
primarily an effective date of December 1, 1995. This acquisition has been
accounted for on a purchase basis and all post effective date revenues and
expenses for such acquisition were included in 1995 results. Had the properties
purchased been recorded at the beginning of the reported periods, the impact on
operating results would not have been material.
In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 121, "Accounting for the Impairment
of Long Lived Assets and for Long Lived Assets to be Disposed Of." The Company
adopted SFAS No. 121 in the fourth quarter of 1995. Under the provisions of the
new statement, if the net book value of an individual asset is greater than its
undiscounted future net cash flows, then the excess of the net book value over
the fair value is recognized as an impairment of the asset. The adoption of
SFAS No. 121 had no effect on the Company's 1995 financial statements.
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 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
certain of its costs and expenses by reimbursements for certain administrative
and operating costs paid or incurred in connection with the administration and
operation of certain oil and natural gas properties and limited and general
partnerships which are sponsored by the Company. During late 1995 all Company
sponsored partnerships were liquidated.
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 1995, and 1994 the dillutive 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 dillutive.
Cash and Cash Equivalents
- -------------------------
Cash includes cash on-hand and cash in interest bearing accounts with
original maturities of 90 days or less.
38
<PAGE>
Accounting Estimates
- --------------------
The preparation of the Company's financial statements in conformity with
generally accepted accounting principles requires the company to make certain
estimates and assumptions that affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities and the
periods in which certain items of revenue and expense are included. Actual
results may differ from such estimates.
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
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".
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.
39
<PAGE>
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
the aggregate $150,000 in 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 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. In early 1995, administrative notes with an aggregate of
$204,000 in principal and interest were settled by the payment of $111,000 and
issuance of 10,000 shares of Senior Preferred.
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 and represents 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 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 required to be the chief
executive officer of the Company. Subsequent to January 1995 the Company
amended its by-laws to provide for a Board of five members. Currently the Board
consists of three members who will serve until their successors are duly elected
and qualified. When new
40
<PAGE>
directors are elected, the Plan provides that 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, to whatever number
of directors is provided for in the Company's by-laws, two additional directors
are to be elected solely by the Senior Preferred Stockholders until the Company
has made up its dividend arrearages.
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, 1995 and 1994, the components of long-term debt were:
- -------------------------------------------------------
(In thousands) 1995 1994
- -------------------------------------------------------
Bank borrowings:
Revolving credit facility (secured) $ 500 $1,150
Non-recourse note 5,335 4,870
Less current maturities - -
- -------------------------------------------------------
Long-term debt $5,835 $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 for 1995 the
actual interest rate including the two percent, ranged from 10.5% to 11%. The
Bank One facility is secured by substantially all of the Company's oil and gas
properties. The Bank One facility at December 31, 1995 had a borrowing base of
$2,500,000 and is redetermined every six months or at Bank One's discretion.
Under the current facility, the borrowing base is reduced through monthly
reductions of $50,000 and the loan matures on July 13, 1997. Due to the excess
of borrowing base over year end borrowings outstanding and the current monthly
facility reduction rate, no current maturities for debt are reflected. 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 to 1 and a tangible net worth,
including Senior Preferred stock, of a minimum of $5,000,000, and other
financial ratios.
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 establishment 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
41
<PAGE>
Amended Credit Agreement including, but not limited to, the acceleration of
all of the then outstanding BMO obligations.
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 $14.3 million to BMO. As set forth above, in July 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 and simultaneously
therewith, BMO released all of its liens on the Company's properties with the
exception of its lien on the Company's NFG Litigation. As part of the loan
restructuring, BMO converted $4,652,000 (the "BMOF Principal") of its
outstanding indebtedness to a non-recourse note secured only by the NFG
Litigation and any proceeds that might be received therefrom. BMO has assigned
its rights to the loan, security, and the Company's note to BMO's wholly owned
subsidiary, BMO Financial, Inc. ("BMOF"). As of December 31, 1994, total
accrued interest pursuant to the BMOF note was $218,000, payable through the
issuance of additional notes, resulting in a total year-end BMOF debt of
$4,870,000. On December 31, 1995, the Company and BMOF executed the first
amendment to the credit agreement. Pursuant to the amended agreement, TGX and
BMOF will share equally any NFG Litigation proceeds up to $8 million. BMOF shall
receive 100% of any proceeds in excess of $8 million until the total received
by BMOF equals the BMOF Principal plus any accrued interest. Thereafter, TGX
will receive all funds until the proceeds it has recovered equals the proceeds
received by BMOF. Any additional NFG Litigation proceeds available shall be
shared equally by TGX and BMOF. If NFG Litigation proceeds are insufficient to
repay the BMOF loan, 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, 1995, total accrued interest pursuant to the BMOF note was
$683,000, payable through the issuance of additional notes, resulting in total
year-end BMOF debt of $5,335,000. Due to the complexities of the NFG Litigation
and the significant uncertainties therewith, the ultimate amount of NFG
Litigation proceeds cannot be reasonably estimated. (See Note 14 below.)
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 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, were to be applied toward the balances due. During
late 1994 and early 1995, the Company negotiated settlement with substantially
all of the Administrative Note holders. As a result of negotiated settlements
and forfeitures, Administrative Notes and Administrative Claims totaling
approximately $1,126,000 in principal and $253,000 in accrued interest were
renegotiated or forfeited with the Company making cash payments in the aggregate
of $455,000, issuing 151,518 shares of Senior Preferred Stock and further
issuing its non-recourse note in the aggregate amount of $90,000 payable out of
proceeds received by the Company from the NFG Litigation, if any, and all such
notes and claims were deemed settled as of year end 1995. The Company reflected
an extraordinary net gain in 1995 and 1994 of $93,000 and $831,000,
respectively, in conjunction with these settlements.
42
<PAGE>
Cash paid for interest during 1995 and 1994 totaled approximately $64,000
and $3,364,000, respectively.
4. COMMITMENTS AND CONTINGENCIES
NFG Litigation
- --------------
In 1974, predecessors of TGX as seller and NFG as buyer entered into a gas
purchase and sale contract (the "NFG Contract") which, in 1983, the New York
State Public Service Commission (the "PSC") determined, in its Opinion No. 83-
26 ("Opinion 83-26"), that the pricing provision was unacceptable.
A dispute arose between NFG and TGX as to whether the NFG Contract remained
in force after Opinion 83-26, and, if it did, what price the NFG Contract
prescribed starting in December, 1983. In November, 1984, NFG commenced an
action in the United States District Court for the Western District of New York
(Civ. No. 84-1372E) (the "District Court") seeking a declaration of the rights
and obligations of the parties under the NFG Contract after Opinion 83-26. TGX
counterclaimed for damages claiming that NFG had breached the terms of the NFG
Contract. The PSC intervened as a plaintiff in the District Court action. In
January, 1991, the District Court declared that because Opinion 83-26 had
abrogated an essential term of the NFG Contract, it had voided the entire NFG
Contract.
In December, 1991, the Federal Court of Appeals for the Second Circuit (the
"Second Circuit") reversed the judgment of the District Court and held that the
NFG Contract had not been voided. The Second Circuit permitted TGX to continue
to deliver gas under the NFG Contract, but left open the issue of the
appropriate price under the NFG Contract.
The Second Circuit remanded the case to the District Court for further
proceedings consistent with its decision, TGX took the position that it was
entitled to recover Natural Gas Policy Act ("NGPA") prices. NFG has taken the
position that the PSC imposed a ceiling on all future gas purchases under the
NFG Contract based on the price of No.6 fuel oil.
On remand from the Second Circuit, in January 1993, the District Court
granted TGX's motion for partial summary judgment regarding the price to be paid
under the NFG Contract. Based on the District Court's order, TGX has concluded
that from December 1983, until at least January 1, 1993, the date price
controls under the NGPA were terminated, the price under the NFG Contract is
equal to the lower of (i) the applicable maximum lawful price for December 1983
and for each month thereafter as established by the NGPA, subject to the
escalations provided by the NGPA, or (ii) the December 1983 permitted price
under the NFG Contract of approximately $4.41 per Mcf. The District 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. The District Court did not address the impact, if any, of
the termination of the NGPA.
In response to NFG's request for clarification, the District Court stated in
July 1993 that its January ruling "did not determine the just and reasonable
price for the gas pursuant to [New York Public Service Law] (S)110(4), set a
contract price for the duration of the contract, resolve any defenses presented
by NFG, determine whether such obligation continues until the present time, or
rule on any deregulation issues."
In December 1992, NFG filed a motion with the PSC requesting a hearing to
determine pricing issues related to the NFG Contract. Pursuant to this request,
the PSC ordered that a proceeding take place. After the submission of
substantial evidence and briefs, the Administrative Law Judge
43
<PAGE>
("ALJ") assigned by the PSC to hear this matter determined in a Recommended
Decision issued in November, 1994 that the PSC should find that from December
20, 1983 through November, 1992 (the period of time at issue in the
proceeding), the maximum contract price that would be just and reasonable
within the meaning of the Public Service Law was $3.714 per Mcf of gas, which
represents the weighted average of the two applicable NGPA categorized maximum
prices for December 1983.
The ALJ's Recommended Decision along with briefs of the parties were
submitted to the PSC for its review. Despite the fact that the PSC had ordered
the proceeding at NFG's request, in Opinion No. 95-5, issued in May, 1995
(the "PSC's 1995 Decision"], the PSC decided that the matter was not ripe for
its review because, in its view, there was currently no contract price in the
NFG Contract for the PSC to review. The PSC declined to endorse the $3.714
price in the ALJ's Recommended Decision or any other price. The PSC determined
that NFG's requested hearing and the dealings after 1983 between NFG and TGX did
not constitute the type of filing appropriate for PSC review. The PSC stated
that it would not determine whether a price to be paid under the NFG Contract
was appropriate until such time was such price was finally agreed to by the
parties or determined by the District Court. The District Court would also
determine the continued validity of the NFG Contract. The PSC left open the
possibility that it might review the NFG Contract after the completion of the
District Court litigation.
In September, 1994, TGX amended and supplemented its counterclaims in the
District Court action to assert additional claims against NFG for breach and
repudiation of the NFG Contract and for punitive damages based upon NFG's bad
faith course of conduct towards TGX. NFG has raised various defenses against
TGX's counterclaim, including claims that TGX itself repudiated and breached
the NFG Contract by its conduct; a claim that the assignment of the NFG
Contract to TGX was not valid; procedural and jurisdictional defenses;
defenses based upon the Public Service Law; a claim that TGX failed to fix a
price in good faith after the issuance of Opinion 83-26; and a claim for
setoffs for unspecified damages to NFG's facilities.
The Magistrate Judge assigned to monitor pre-trial discovery in the District
Court action has issued a scheduling order pursuant to which the parties have
been engaged in costly documentary discovery into the allegations raised by the
pleadings in the District Court litigation. Although the current scheduling
order anticipates that discovery will be complete by September, 1996, it is
not possible to predict when this litigation will come to an end given the
possible appeals and collateral PSC proceedings that may take place, nor is it
possible to predict the likely outcome of the litigation.
Subsequent to the PSC's 1995 Decision, NFG in 1995 brought a special
proceeding in the New York State Supreme Court, Albany County, seeking a
judgment annulling, as effected by an error of law, much of the PSC's 1995
Decision. TGX intervened in this proceeding to protect its interests. This
special proceeding was dismissed by NFG in January, 1996 based upon the PSC's
agreement to represent that its articulated reasons for dismissing NFG's
petition should be understood as constituting an exercise of the PSC's
discretion under (S)204 of the State Administrative Procedure Act to decline to
entertain NFG's request for a declaratory ruling.
During its Reorganization Proceeding, TGX filed an adversary proceeding (the
"Turnover Proceeding") in Bankruptcy Court to compel NFG to pay the amount due
to TGX pursuant to the provisions of the NFG Contract. Effective June 19,
1992, TGX and NFG entered into a partial settlement agreement, and, 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
44
<PAGE>
NFG. The Payment will be credited against any additional amount which may be
adjudged due TGX from NFG.
As part of its sale of substantially all of its oil and gas properties in
Ohio and New York to BBC in January 1994, TGX assigned the NFG Contract
effective December 1, 1993. TGX's assignment of the NFG 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.
(See Note 14 below.)
As a result of the matters described herein, TGX is not in a position to
determine when, if ever, a final resolution of the dispute concerning the NFG
Contract will be reached or the effect on TGX's financial position and results
of operation of any such resolution.
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. In July 1995, certain
royalty owners in the same wells commenced a seperate legal action alleging that
TGX and other working interest owners improperly profited under the terms of a
Gas Gathering and Transportation Agreement dated December 12, 1983. Both cases
are 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 prepetition and administrative claims related to an
overriding royalty interest previously conveyed by TGX. During that hearing,
the parties stipulated that the finally allowed amount of the claimant's
prepetition claim would be $600,000. That prepetition claim has been fully
satisfied by the issuance of Senior Preferred. The Company had previously
estimated that prepetition claim in that amount, and therefore it had been
reflected in prior years' financial statements. Subsequent to the March, 1994
hearing, and after post-hearing motions from both TGX and the Claimant, the
Bankruptcy Court entered an order on September 7, 1994 which determined that
the claimant would be granted an allowed administrative expense claim for unpaid
overriding royalties arising post-petition but prior to October 4, 1992 in the
amount of $244,000. That administrative claim, when finally allowed, is to be
treated by the issuance of an Administrative Note under the terms of the Plan,
and is to be payable under the terms of the Plan. The Bankruptcy Court further
ruled that it would not exercise any jurisdiction over claims for alleged unpaid
overriding royalties arising subsequent to October 4, 1992. TGX believes that
the Bankruptcy Court erred in its determination of unpaid overriding royalties,
and has appealed the Bankruptcy Court's ruling to the United States District
Court for the Western District of Louisiana. That appeal has been fully
briefed, but no decision has been rendered.
On May 31, 1995, the Company entered into a Settlement Agreement among
itself, Paragon Resources, Inc., J. C. Templeton, W. M. Templeton and a number
of other former directors of the Company, trusts on behalf of members of the
Templeton family and other entities pursuant to which all lawsuits between and
among the parties were dismissed with prejudice. In consideration therefore,
the Company received $325,000, an assignment of certain oil and gas leases, and
receipt of past due joint operating expenses payable by certain of the
defendants. The Company released lispendens against certain of the defendants'
properties and conveyed to the defendants an interest in certain properties to
which they were entitled. The parties to the litigation also conveyed to the
Company any Common Stock or Preferred Stock which they held.
45
<PAGE>
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, 1995, the Company's only lease commitment was for the
remaining term of its office lease for 1996 of $7,000.
Other
- -----
As of December 31, 1995, the Company had letters of credit outstanding of
$25,000 under the Bank One credit facility which reduced the Company's
availability under the facility. See Note 3 above.
5. INVESTMENT IN NATURAL GAS TREATING PLANT
In conjunction with the acquisition of Amarex, Inc. in 1985, the Company
acquired Amarex's 35% 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 and saltwater disposal facilities. The
Company receives cash distributions from the Venture for its share of net cash
flow. In addition, the Venture charges the Company for gas treating and such
charges are included in operating expenses.
46
<PAGE>
A summary of the Venture's unaudited financial position as of December 31,
1995 and 1994, and the results of its operations for the years then ended is:
<TABLE>
<CAPTION>
===============================================================================
(In thousands) (unaudited) 1995 1994
- -------------------------------------------------------------------------------
<S> <C> <C>
SUMMARY BALANCE SHEETS
Current assets $ 667 $ 869
Net property and equipment 1,701 2,169
- -------------------------------------------------------------------------------
$2,368 $3,038
===============================================================================
Current liabilities $ 155 $ 380
Long-term debt 100 150
Partners' capital 2,113 2,508
- -------------------------------------------------------------------------------
$2,368 $3,038
===============================================================================
SUMMARY STATEMENTS OF EARNINGS
Fees earned $2,448 $2,327
Operating expenses 1,131 1,142
- -------------------------------------------------------------------------------
Operating income 1,317 1,185
Other income 8 11
- -------------------------------------------------------------------------------
Net income $1,325 $1,196
===============================================================================
</TABLE>
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
As of December 31, 1995 and 1994, the primary components of accounts
payable and accrued expenses were (in thousands):
<TABLE>
<CAPTION>
1995 1994
- -------------------------------------------------------------------------------
<S> <C> <C>
Accounts payable $ 555 $ 489
Undistributed net oil and natural gas revenue 1,152 1,069
Accrued interest and fees - 32
Accrued pre-petition liabilities 518 934
Accrued operating and tax expenses 312 252
Operation advances 159 -
Miscellaneous accruals 657 576
- -------------------------------------------------------------------------------
$3,353 $3,352
===============================================================================
</TABLE>
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
47
<PAGE>
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. In conjunction with fresh
start reporting, in 1992, the Senior Preferred was recorded at a value of
$11,046,000 which is $76,246,000 less than redemption value. In 1995, an
additional 250,000 shares were issued to certain executive officers and 128,110
canceled in conjunction with settlement of certain pre-petition obligations,
post-petition asset sale and litigation settlement. The Company recorded in 1995
and 1994 $52,000 and $99,000, respectively, of stock compensation expense
related to the 1992 and 1995 management agreement and executive officer stock
issuances. 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). The 1995 awards were valued based on a reported 1995 Senior
Preferred trade at $0.20 per share.
Since December 31, 1993, the components of the number of shares of the
Company's Senior Preferred and changes in associated values are as follows (in
thousands):
<TABLE>
<CAPTION>
Number Recorded
of shares Value
- -------------------------------------------------------------------------------
<S> <C> <C>
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 31, 1994 8,729 44,602
Accrued and unpaid dividends - 12,038
Accretion on redemption value and dividends - 5,045
Amortization of compensation shares pursuant to
management agreement - 35
Shares issued pursuant to management
option agreements 250 17
Shares canceled (128) -
- -------------------------------------------------------------------------------
Balance, December 31, 1995 8,851 $61,737
- -------------------------------------------------------------------------------
</TABLE>
48
<PAGE>
8. STOCKHOLDERS' EQUITY (DEFICIT)
Since December 31, 1993, the components of the number of shares of the
Company's stockholders' equity (deficit) and the changes therein are:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
Old
Preferred Common Treasury
(Thousands of shares) Stock Stock Stock
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Balance, December 31, 1993 404 25,314 3,663
Dividends on Old Preferred Stock 27 - -
- -------------------------------------------------------------------------------
Balance December 31, 1994 431 25,314 3,663
Dividends on Old Preferred Stock 27 - -
Shares surrendered - (358) 358
- -------------------------------------------------------------------------------
Balance December 31, 1995 458 24,956 4,021
===============================================================================
</TABLE>
As a result of the Senior Preferred Stock liquidation and dividend
preference, no value was ascribed to common stock held in treasury.
Since December 31, 1993, the components of the Company's stockholders' equity
(deficit), and the changes therein are:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
Old Additional Retained
Preferred Common Paid-In Earnings
(In thousands) Stock Stock Capital (Deficit)
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
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 - - - (10,510)
Accretion of Senior Preferred
redemption value - - - (3,980)
Net loss - - - (716)
- -------------------------------------------------------------------------------
Balance, December 31, 1994 431 290 1,179 (45,611)
Preferred dividends, payable with
additional shares of Old Preferred 27 - 243 (270)
Dividends on Senior Preferred - - - (12,038)
Accretion of Senior Preferred
redemption value - - - (5,045)
Net loss - - - (340)
- -------------------------------------------------------------------------------
Balance, December 31, 1995 $458 $290 $1,422 $(63,304)
===============================================================================
</TABLE>
49
<PAGE>
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, 158,000
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.
Common Stock
- ------------
The Company is authorized to issue 100,000,000 shares of Common Stock, with
a $.01 par value, of which 24,956,033 were outstanding at December 31, 1995.
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 Option 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
50
<PAGE>
under the Plan. From 1991 through 1995, 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:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------
Non-Qualified Plan Incentive Plan
------------------- -------------------
Average Average
Number Exercise Number Exercise
of Price of Price
Shares Per Share Shares Per Share
- ------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Balance, December 31, 1993 - - 44,500 $ 1.17
Options cancelled or forfeited - - (40,000) 1.15
- ------------------------------------------------------------------------------
Balance, December 31, 1994 and 1995 - - 4,500 $ 1.33
==============================================================================
Options exercisable:
December 31, 1994 and 1995 - - 4,500 $ 1.33
</TABLE>
9. INCOME TAXES
The Company follows 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 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.
In conjunction with the recognition of tax gains on property sales, the
Company estimated and accrued state income taxes in 1994 of $17,000.
Long-term deferred tax assets (liabilities) are comprised of the following:
<TABLE>
<CAPTION>
(In thousands) 1995 1994
- ------------------------------------------------------------------------------
<S> <C> <C>
Deferred Tax Assets:
Loss carryforwards $11,062 $11,084
Alternative minimum tax credit carryforward and other 6 150
Deferred Tax Liabilities:
Oil and gas properties (2,571) (2,303)
- -------------------------------------------------------------------------------
Net deferred tax asset 8,497 8,931
Valuation allowance (8,497) (8,931)
- -------------------------------------------------------------------------------
$ - $ -
</TABLE>
51
<PAGE>
Income tax expense differs from the amounts computed by applying the
statutory federal rate as follows:
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------
Year Ended December 31,
1995 1994
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C>
Income taxes computed at statutory federal rate 34.0% 34.0%
Net operating loss carryover not deductible (utilized) in current period (34.0) (34.0)
Alternative minimum tax and other - 1.1
- ----------------------------------------------------------------------------------------------------------
- % 1.1%
==========================================================================================================
</TABLE>
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, 1995, the Company had pre-
"change of ownership" net operating loss carryforwards of $3,648,000 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 in 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 realize any future benefit
from such credits. The Company had depletion carryforwards, as of December 31,
1995, of $14,238,000 which are limited annually to 65% taxable income.
52
<PAGE>
10. RELATED PARTY TRANSACTIONS
Pursuant to the provisions of the applicable agreements and in its capacity
as general partner, the Company received recurring supervisory and
administrative fees, including reimbursement of certain general and
administrative costs, from certain partnerships. Supervisory and administrative
fees of $424,000 and $684,000 were received during 1995 and 1994,
respectively. All partnerships for which the Company acted as general partner
were liquidated in late 1995 thus negating any future administrative fees and
reimbursement.
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 applied 100% of the net revenues of the respective
partnerships to their obligations due to TGX until the partnerships were
liquidated in 1994. 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. As of December 31, 1995 and 1994,
the Company had currently due from partnerships and affiliates $6,000 and
$504,000, respectively.
Paragon and certain of its affiliates were owners of approximately 14% of the
Company's outstanding Common Stock in 1994. In the past, the Company had
substantial transactions with Paragon including the offering of interests and in
the drilling of wells for partnerships. In February 1992, the Company commenced
a legal action regarding the collection of amounts 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 excess of $286,000. The allowance for affiliated
receivables in 1994 was $2,027,000. In 1995, the litigation against Paragon
and certain of its affiliates was settled. As a result of the litigation
settlement, the Company recognized an allowance recoupment of $425,000 and
offset the remaining allowance against the oustanding receivables.
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:
<TABLE>
<CAPTION>
1995 1994
---- ----
<S> <C> <C>
Lion Oil Company 22% 14%
Noram Energy Services Inc. - 12%
Princeton Natural Gas Company 28% 15%
Energy Source, Inc. 12% -
Enron Gas Marketing 14% -
</TABLE>
53
<PAGE>
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.
Oil and Gas Related Costs and Operating Results
- -----------------------------------------------
The following schedules present capitalized costs and costs incurred,
whether capitalized or expensed, and operating results for the periods then
ended.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------
(In thousands 1995 1994
- --------------------------------------------------------------------------
<S> <C> <C>
Capitalized costs:
Proved properties $11,340 $10,407
Accumulated depletion and depreciation (4,062) (3,251)
- --------------------------------------------------------------------------
$ 7,278 $ 7,156
==========================================================================
Costs incurred:
Acquisition of properties:
Unproved $ 18 $ -
Proved 718 -
Development (1) 338 404
- --------------------------------------------------------------------------
$ 1,074 $ 404
==========================================================================
Operating results (2):
Revenues $ 3,611 $ 4,802
- --------------------------------------------------------------------------
Costs and expenses:
Production and exploration costs 1,974 3,188
Depletion and depreciation 951 1,099
- --------------------------------------------------------------------------
2,925 4,287
- --------------------------------------------------------------------------
Operating earnings before income taxes 686 515
Income tax expense - 17
- --------------------------------------------------------------------------
Operating earnings $ 686 $ 498
- --------------------------------------------------------------------------
</TABLE>
(1) 1994 activity represents primarily properties received in settlement of
certain partnership notes and receivables.
(2) Excludes general and administrative and interest expense.
54
<PAGE>
Proved Reserves
- ---------------
The following schedule presents estimates of proved oil and natural gas
reserves attributable to the Company, 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.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------
1995 1994
---- ----
Oil Gas Oil Gas
- ----------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Proved reserves:
Beginning of year 931 10.4 525 9.1
Sales of reserves in place (2) - (37) (.5)
Purchases of reserves-in-place 22 1.2 - -
Extensions and discoveries 1 0.1 487 2.6
Revisions of previous estimates 55 2.2 18 1.4
Production (1) (63) (1.7) (62) (2.2)
- ----------------------------------------------------------------------------
End of year 944 12.2 931 10.4
============================================================================
Proved-developed reserves 465 9.7 444 7.8
============================================================================
</TABLE>
(1) 1995 and 1994 includes .220 and .590 Bcf, respectively, of gas balancing
volumes related to gas collections.
As a result of TGX's debt restructuring and anticipated cash flow, TGX
included proved undeveloped reserves for the first time, in preparing its 1994
report disclosures. The addition of the proved undeveloped reserves was
reflected as 1994 extensions and discoveries. The 1995 report disclosure
continues to include proved undeveloped reserves.
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.
55
<PAGE>
Standardized Measure of Discounted Future Net Cash Flows
- --------------------------------------------------------
The following schedules present 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 were included as extensions and discoveries. 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 property, 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 and, (d) where applicable,
the premise that future prices and deliveries will be in accordance with
existing contractual terms which may require arbitration or litigation to
ultimately assure compliance. Estimated future production and development costs
are based on economic conditions at the respective year ends. Estimated future
development costs associated with proved developed non-producing and proved
undeveloped reserves for 1995 and 1994 total $3.8 and $3.6 million,
respectively. Production of those reserves is dependent upon the Company's
ability to fund such future development costs, which are scheduled to be
incurred over numerous years. 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.
56
<PAGE>
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.
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------
(In thousands) 1995 1994
- ------------------------------------------------------------------------------------------
<S> <C> <C>
Future net cash flows:
Future revenues $39,205 $29,092
- ------------------------------------------------------------------------------------------
Future production costs 14,476 10,631
Future development costs 3,844 3,647
- ------------------------------------------------------------------------------------------
18,320 14,278
- ------------------------------------------------------------------------------------------
Future pre-tax cash flows 20,885 14,814
Future income taxes - -
- ------------------------------------------------------------------------------------------
$20,885 $14,814
==========================================================================================
Standardized Measure, discounted at 10%:
Future pre-tax cash flows $11,804 $ 8,807
Future net cash flows $11,804 $ 8,807
==========================================================================================
Changes in Standardized Measure:
Standardized Measure, beginning of year $ 8,807 $10,943
- ------------------------------------------------------------------------------------------
Sale of reserves-in-place (16) (1,042)
Purchases of reserves-in-place 1,174 -
Extensions and discoveries 188 2,213/(1)/
Revisions of previous quantity estimates 1,835 862
Changes in future development costs (247) (2,310)
Net changes in prices and production costs 959 (3,715)
Sales of oil and natural gas produced, net of
production costs (1,706) (2,030)
Accretion of discount 881 1,094
Changes in production rates and other, net (71) 2,792
- ------------------------------------------------------------------------------------------
Net increase (decrease) 2,997 (2,136)
- ------------------------------------------------------------------------------------------
Standardized Measure, end of year $11,804 $ 8,807
==========================================================================================
</TABLE>
(1) Reflects primarily the inclusion of proved undeveloped reserves which had
been excluded in prior year's reporting.
57
<PAGE>
13. INTERIM FINANCIAL DATA (UNAUDITED)
The unaudited interim results of operations, are summarized below (in
thousands of dollars except per share amounts):
<TABLE>
<CAPTION>
March 31, June 30, September 30, December 31,
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1995:
Revenues $ 1,264 $ 956 $ 1,241 $ 1,136
Gross profit 529 144 327 706
Extraordinary gain (loss) 118 (25) - -
Net loss applicable to
common stock (4,415) (4,741) (4,603) (3,934)
Loss per common share $ (0.17) $ (0.19) $ (0.18) $ (0.16)
===========================================================================================================================
1994:
Revenues $ 1,487 $ 2,145 $ 1,463 $ 1,403
Gross profit 574 471 469 516
Extraordinary gain - - 128 703
Net income (loss) applicable
to common stock (4,051) (3,402) (4,638) (3,385)
Loss per common share $ (0 .16) $ (0 .13) $ (0.18) $ (0 .13)
===========================================================================================================================
</TABLE>
14. SUBSEQUENT EVENT
As of March 28, 1996, the accompanying consolidated financial statements
had been prepared assuming the Company would continue as a going concern.
However, the Company has a substantial accumulated deficit and had a significant
working capital deficit that raised substantial doubts about its ability to
continue as a going concern. The financial statements did not reflect any
adjustments that might result from the outcome of this uncertainty. Further, the
Company planned to continue to reduce its overhead and eliminate additional non-
core assets. The Company also planned to review growth opportunities, consistent
with its available capital, to determine if asset growth could be attained
through workover, drilling, acquisition or a combination thereof, within the
limits of the Company's financial resources.
On April 12, 1996, TGX entered into a Settlement Agreement with NFG and the
Public Service Commission of the State of New York. Pursuant to the Settlement
Agreement, TGX received on April 19, 1996 $7,200,000 from NFG and all parties to
the Settlement Agreement have dismissed all claims and counterclaims against
each other. Pursuant to amended credit agreements with BMOF (See Note 3), 50% of
the settlement proceeds were paid to BMOF in cancellation and full payment of
the non-recourse secured note of $5,468,000, including interest of $816,000. TGX
recorded an extraordinary gain for debt forgiveness of $1,831,000, net of income
taxes of $37,000, in conjunction with the BMOF final payment. Pursuant to a BMOF
agreement, BMOF is to reimburse TGX for 50% of all taxes and royalties, which
are not expected to be significant, that may be due from such proceeds. As a
result of the NFG proceeds and payment of $100,000 to another party entitled to
participate in the proceeds, TGX recorded a net litigation settlement gain of
$7,100,000. TGX retained $3,500,000 of settlement proceeds after BMOF and other
payments and a portion of such proceeds was used to retire all of TGX's then
outstanding bank debt of $900,000 on April 22, 1996.
58
<PAGE>
As of April 22, 1996 the Company had positive working capital and had no
outstanding borrowings under its bank line of credit. In addition, TGX is
undertaking steps to restructure its capital through a planned issuance of a new
class of common stock in exchange for the Senior Preferred Stock. Management
believes that its positive working capital and current credit facility, and
anticipated improving operating activity will provide the necessary cash flow to
support its ongoing business plans.
15. 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
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 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 BMOF of $3,600,000. A summary of the impact for the periods presented
is shown below (in thousands, except per share data).
<TABLE>
<CAPTION>
December 31, 1995 December 31, 1994
------------------ ------------------
BALANCE SHEET Reported Restated Reported Restated
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Total current liabilities $ 3,353 $ 3,353 $ 3,928 $ 3,765
Long-term debt 500 5,835 1,150 6,020
Accumulated deficit (57,969) (63,304) (40,904) (45,611)
Total stockholders' deficit (55,799) (61,134) (39,004) (43,711)
STATEMENT OF OPERATIONS
General and administrative expense $ 1,476 $ 1,476 $ 1,747 $ 2,239
Interest expense 142 607 969 1,187
Income tax expense (benefit) (163) - 180 17
Extraordinary gain, net of taxes 93 93 4,991 831
Net loss applicable to common stock (17,065) (17,693) (10,769) (15,476)
Net loss per share of common stock (0.68) (0.71) (0.42) (0.61)
</TABLE>
59
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
During 1995, there were no disagreements with the Company's independent
accountants regarding accounting or financial disclosure matters.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Board of Directors
- ------------------
The Company's restated Certificate of Incorporation provided for a Board
consisting of eight members elected for three year terms 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. 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 were required not to have
been directors of TGX at the time it filed for bankruptcy or be affiliated with
any former TGX director. Since January 21, 1995, the term of all directors is
for one year, and all restrictions and requirements for selection of the Board
have been removed.
Commencing July 10, 1995, the Company's by-laws were amended to provide for
a Board of Directors consisting of five persons. Since such date, two members of
the board have resigned and no new members have been elected. All directors are
to be 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 such stockholders, as
a class, can elect all directors of the Company. Moreover, pursuant to the terms
of the Senior Preferred Stock, if TGX fails to pay six quarterly dividends then
the Board of Directors shall be increased by two members and such additional two
members shall 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 an additional two members to the
Board of Directors.
The members of the Board are:
Served as Position, Principal Occupation,
Director Business Experience and the
Name Age Since Directorships Held
---- --- --------- -------------------------------
LARRY H. CARPENTER 48 1992 Chairman of the Board, President
and Chief 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
Corporation, from 1977 through
September 1990, and thereafter was
engaged as an independent oil and gas
consultant.
60
<PAGE>
DAVID H. SCHEIBER 38 1995 Manager of Cana Capital, LLC, an
investment banking and services
company located in Laguna Niguel,
California. From September 1991 to
August 1992, Mr. Scheiber was
affiliated with Monitor Company, Inc.,
a management consulting firm
headquartered in Boston,
Massachusetts, as manager of their
bankruptcy practice. From April 1989
to February 1991, Mr. Scheiber served
as Senior Vice President and Director
of Private Placements at Far West
Savings and Loan Association of
California. Far West Savings and Loan
Association was placed into
conservatorship in January 1991 and
receivership in February 1991 by the
Resolution Trust Corporation.
JEFFREY E. SUSSKIND 42 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.
The Board met on six occasions in 1995 and each current director attended at
least 75% of such meetings. 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.
61
<PAGE>
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 and Executive Committees. In 1995,
the Audit Committee and the Compensation Committe each met on one occasion, and
the Executive Committee did not meet.
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 21, 1996. Pursuant to
the by-laws of the Company, each 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 48 See information as set forth under "Board of
Directors."
MICHAEL A. GERLICH 41 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.
62
<PAGE>
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 two years whose cash compensation for 1995 exceeded
$100,000. For 1994, other annual compensation for Mr. Carpenter includes
reimbursement of house and automobile expenses.
SUMMARY COMPENSATION TABLE (1)
<TABLE>
<CAPTION>
LONG TERM
---------
COMPENSATION
------------
ANNUAL COMPENSATION AWARDS
------------------------------------- ------
Name and
Principal Other Annual Restricted Stock
Position Year Salary($) Bonus($) Compensation($) Awards($)
- ----------- --- --------- -------- ---------------- ---------
<S> <C> <C> <C> <C> <C>
Larry H. Carpenter 1995 $ 209,000 $ 125,000 (4) -0- 200,000 (5)
President/CEO 1994 $ 175,000 $ 100,000 $26,062 (3) - (6)
Michael A. Gerlich 1995 $ 107,000 (2) $ 10,000 (4) -0- 30,000 (7)
Vice-President/CFO
=========================================================================================================================
</TABLE>
(1) The table above lists only the compensation of the CEO for 1994, as he was
the only employee who received in excess of $100,000 in total compensation
for that period.
(2) Includes amounts paid as a consultant to officer.
(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) Of the bonus amount shown for Mr. Carpenter, $75,000 was granted in regards
to 1994 accomplishments and paid in 1995. The remaining $50,000 is for 1995
accomplishments and was paid in January 1996. All of Mr. Gerlich's bonus
was granted and paid in January 1996.
(5) Includes the award of 200,000 shares of Series A Preferred Stock which is
forfeitable, in part, if Mr. Carpenter ceases to be an employee of the
Company prior to April, 1997. Of such award 100,000 shares cease to be
subject to forfeiture on April 1, 1996 and the remaining 100,000 shares
cease being subject to forfeiture on April 1, 1997. As of December 31,
1995, there was limited trading in the Series A Senior Preferred Stock and,
therefore, the Company has utilized the price reflected in Schedule 13-D
filed on May 8, 1995 of $0.20 for stock compensation recognition purposes.
(6) Includes the 1992 award of 200,000 shares of Series A Preferred Stock which
ceased being subject to forfeiture on March 31, 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
$150 per share, based on an internal estimate of Company net assets as of
October 2, 1992 (fresh start reporting).
63
<PAGE>
(7) Includes the award of 30,000 shares of Series A Preferred Stock which are
forfeitable, in part, if Mr. Gerlich ceases to be an employee of the
Company prior to September 27, 1997. Of such award, 15,000 shares cease to
be subject to forfeiture on September 27, 1996 and the remaining shares
cease to be subject to forfeiture on September 27, 1997. As of December 31,
1995, there was limited trading in the Series A. Senior Preferred Stock
and, therefore, the Company has utilized the price reflected in Schedule
13-D filed on May 8, 1995 of $0.20 for stock compensation recognition
purposes.
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 Certificate 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 in 1992
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. On April 1, 1995, Mr. Carpenter and the Company
entered into an Employment Agreement covering a period of two years ending March
31, 1997 ("New Employment Agreement"). The term of the New Employment Agreement
shall be automatically extended one additional year unless notice is given 60
days before March 31, 1997 by the Company or Mr. Carpenter requesting the term
not be extended. Mr. Carpenter is to receive compensation of $225,000 per annum,
plus discretionary bonuses as determined by the Board of Directors. In 1995 the
Board of Directors granted a bonus of $75,000 related to 1994 results and an
additional bonus of $50,000 in 1996 related to 1995 results. In addition, Mr.
Carpenter received 200,000 shares of the Company's Series A Preferred Stock
which vests over the initial term of the New Employment Agreement. The New
Employment Agreement also provides Mr. Carpenter, at Company expense, benefits
of health and life insurance.
Employee Stock Option 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.
Compensation of Directors
- -------------------------
Each non-employee member of the Board receives a retainer fee of $833 per
month plus a meeting fee of $1,000 per day and $250 for each telephone meeting.
The monthly retainer fee is subject to forfeiture on a six-month prospective
basis if a director attends less than 75% of the meetings. Each member of the
Board also receives reimbursement for reasonable travel expenses incurred in
conjunction with meetings, with air fares not to exceed the rate for a full-fare
coach seat.
64
<PAGE>
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.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
As of March 21, 1996, 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 21, 1996, 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.
<TABLE>
<CAPTION>
Amount and Nature of
Beneficial Ownership
------------------------------------------------------------------------------------------
Options Percent
Name of Sole Voting and Exercisable of
Individual or Group Investment Power Within 60 Days Class/(1)/
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Larry H. Carpenter/(2)/ 300,000 Series A -0- 3.4%
David H. Scheiber -0- -0- -
Jeffrey E. Susskind 1,692,796 Series A -0- 19.1%
Michael A. Gerlich 30,000 Series A -0- -
All executive officers and directors as a
group (7 persons) 2,022,796 Series A -0- 22.8%
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Unless otherwise indicated, the holders have sole voting and otherwise
stated, the investment powers. Unless percentage is less than one percent.
(2) Of Mr. Carpenter's shares 200,000 are subject to forfeiture employment
agreement. pursuant to the terms of his See "Employment Agreement".
65
<PAGE>
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 21, 1996.
<TABLE>
<CAPTION>
Amount
Beneficially Percent
Name and Address of Beneficial owner Class Owned of Class
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Liberty National Bank and Trust Company Common 3,136,986 /(1)/ 12.6%
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
Gaylon D. Simmons and Senior
Gloria Annette Turner Simmons Preferred 569,561 6.4%
905 East Main Street Old
Jonesboro, Louisiana 71251 Preferred 300,000 100%
Jeffrey and Janis Susskind
FBO The Susskind Family Trust
100 Wilshire Blvd., 15th Floor Senior
Santa Monica, California 90401 Preferred 1,692,796 19.1%
The AIF-Lion Group
c/o Apollo Advisors, L.P.
Two Manhattanville Road Senior
Purchase, NY 10577 Preferred 1,823,000 /(2)/ 20.6%
- ----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) In connection with its 1985, the Company issued National Bank and Trust
Company acquisition of Amarex, Inc. 11,475,000 shares of Common of Oklahoma
City as escrow agent. which was consummated on Stock into escrow with
Liberty Such shares are held December 5, 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 21, 1996, 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.
(2) Such information has been the Securities and Exchange limited partnership
and Lion supplied to the Company Commission on December 31, Advisors, L.P.,
a Delaware pursuant to a Schedule 13D 1994, by AIF II, L.P., a Delaware
limited partnership filed with Delaware (collectively the
66
<PAGE>
"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.
67
<PAGE>
PART IV.
ITEM 13. 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) Report 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, 1995 and 1994
(ii) Consolidated Statement of Operations for the years ended
December 31, 1995 and 1994.
(iii) Consolidated Statement of Cash Flows for the years ended
December 31, 1995 and 1994.
(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 Registrants' 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).
68
<PAGE>
Exhibit 3.1 Restated Certificate of Incorporation of the Company.
(Incorporated by reference to Exhibit 3.1 of the
Registrants' 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 of the
Registrants' Annual Report on Form 10-K for the year
ended December 31, 1991, File No. 0-10201).
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 Registrants' Annual
Report on 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 Registrants' 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 February 1, 1992
between the Company and the Bank of Montreal.
(Incorporated by reference to Exhibit 10.3 of the
Registrants' 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 Registrants' 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 Registrants' 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 of February 1,
1992, executed by the Company to the order of the Bank
of
69
<PAGE>
Montreal. (Incorporated by reference to Exhibit 10.6 of the
Registrants' Annual Report on 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 Registrants' Annual Report
on 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 Registrants' Annual Report
on 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 Registrants' Annual
Report on Form 10-K for the year ended December 31, 1991,
File No. 0-10201).
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 1991, 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, File
No. 0-10201).
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).
70
<PAGE>
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 Limited 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 July 13, 1994
(Incorporated by reference to Exhibit 10.4 of the
Registrant's report on Form 8-K dated July 13, 1994).
Exhibit 10.23 First Amendment to Second Amended and Restated Credit
Agreement dated as of December 31, 1995. (Incorporated by
reference to Exhibit filed with original 10-K on March 28,
1995, File No. 0-1-10201).
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. 0-1-10201).
(b) Reports on Form 8-K for the quarter ended December 31, 1995:
None.
71
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this Report to be signed on its
behalf by the undersigned thereunto duly authorized.
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/ DAVID H. SCHEIBER Director February 25, 1997
---------------------------
David H. Scheiber
By: /s/ JEFFREY E. SUSSKIND Director February 25, 1997
---------------------------
Jeffrey E. Susskind
72
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<CASH> 384
<SECURITIES> 0
<RECEIVABLES> 1,467
<ALLOWANCES> 320
<INVENTORY> 0
<CURRENT-ASSETS> 1,582
<PP&E> 11,543
<DEPRECIATION> 4,132
<TOTAL-ASSETS> 9,791
<CURRENT-LIABILITIES> 3,353
<BONDS> 0
61,737
458
<COMMON> 290
<OTHER-SE> (61,882)
<TOTAL-LIABILITY-AND-EQUITY> 9,791
<SALES> 3,611
<TOTAL-REVENUES> 4,597
<CGS> 1,905
<TOTAL-COSTS> 1,905
<OTHER-EXPENSES> 2,518
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 607
<INCOME-PRETAX> (433)
<INCOME-TAX> 0
<INCOME-CONTINUING> (433)
<DISCONTINUED> 0
<EXTRAORDINARY> 93
<CHANGES> 0
<NET-INCOME> (17,693)
<EPS-PRIMARY> (0.71)
<EPS-DILUTED> (0.71)
</TABLE>
