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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-KSB
[X] ANNUAL REPORT PURSUANT TO SECTION l3 OR l5(d) OF THE SECURITIES
EXCHANGE ACT OF l934 (FEE REQUIRED)
For the fiscal year ended December 31, l995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 (NO FEE REQUIRED)
For the transition period from _______________ to _______________
Commission file number 0-10201
TGX CORPORATION
(Exact name of registrant as specified in its charter)
Delaware 72-0890264
(State or other jurisdiction 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 (713) 872-0500
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
--------------------- -----------------------
Common Stock, $.01 par value Not Applicable
Series A Senior Preferred Stock, $1 par value Not Applicable
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days: Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-KSB or any amendment to
this Form 10-KSB: [X]
APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE
PRECEDING FIVE YEARS: Indicate by check mark whether the registrant has filed
all documents and reports required to be filed by Section 12, 13 or 15(d) of the
Securities Exchange Act of 1934 subsequent to the distribution of securities
under a plan confirmed by a court. Yes [X] No [ ]
The aggregate market value of the voting stock held by non-affiliates as of
March 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............... 31
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE...................... 59
PART III.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT........ 59
ITEM 11. EXECUTIVE COMPENSATION.................................... 62
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT............................................... 64
PART IV.
ITEM 13. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K................................................ 67
SIGNATURES............................................... 71
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PART I.
ITEM l. BUSINESS
THE COMPANY
General
TGX Corporation ("TGX"), formerly named Templeton Energy, Inc., is a Delaware
corporation that was organized in June 1980. TGX's executive offices are at 222
Pennbright, Suite 200, Houston, Texas 77090 (telephone number 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.
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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 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
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 $1,747,000.
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
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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 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
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.
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On July 13, 1994, TGX entered into a series of agreements with BMO and Bank
One, Texas, N.A. ("Bank One") whereby the New BMO Loans were restructured and
all BMO Events of Default resolved. Pursuant to the restructuring, Bank One
established a borrowing-based facility of $2,350,000 under which TGX immediately
borrowed $1,600,000 of which $1,452,000 was paid to BMO in satisfaction of the
remaining amount due of the Required Payment. The Bank One facility bears
interest at Bank One's stated rate plus 2% and is secured by substantially all
of TGX's oil and gas properties. The loan is repayable in 36 months through
monthly principal reductions and matures on July 13, 1997. The borrowing base is
redetermined at a minimum of every six months or at Bank One's discretion. The
Bank One facility requires the maintenance of certain financial ratios including
a working capital ratio of 1 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, the Company had borrowed $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 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 TGX
note, to BMO's wholly owned subsidiary, BMO Financial, Inc. ("BMOF"). Pursuant
to the July 13, 1994 agreement, after repayment of the outstanding BMOF loan
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 were insufficient to repay the
BMOF loan, plus applicable interest, TGX would have no further obligation for
such repayment. Since the BMOF loan has no recourse, the Company recognized an
extraordinary gain from debt forgiveness, net of related transaction costs, of
$4,160,000, in the third quarter of 1994. The BMOF loan 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, interest pursuant to the BMOF loan totaled $683,000.
On December 31, 1995, TGX and BMOF executed a First Amendment to the Second
Amended and Restated Credit Agreement ("BMOF Agreement"). Pursuant 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 New BMO Loans 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.
See Note 3 of the Notes to Consolidated Financial Statements.
Administrative Claims
During the Reorganization Proceeding, TGX incurred, and claimants filed
applications for, approximately $7,131,000 in administrative fees and expenses
relating to the reorganization ("Administrative Claims"). TGX objected to
certain of the Administrative Claims and negotiated settlement amounts and terms
of payment with certain holders of Administrative Claims. As a
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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 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
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.
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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.
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.
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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 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.
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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
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.
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.
8
<PAGE>
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.
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.
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
9
<PAGE>
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".
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.
10
<PAGE>
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.
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
11
<PAGE>
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.
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.
12
<PAGE>
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 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
13
<PAGE>
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>
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>
As a result of TGX's debt restructuring (See "Bank Indebtedness") 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 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 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
14
<PAGE>
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, respectively, of gas volumes
balancing related to gas collections.
As a result of TGX's debt restructuring (See "Bank Indebtedness") 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 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
17
<PAGE>
liquidations the Company, as settlement of outstanding partnership notes and
receivables was assigned additional direct interests in related oil and natural
gas properties having an estimated value of $381,000 and realized from such
sales recoupment of $751,000 in previous allowed for receivables and notes. 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
18
<PAGE>
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.
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.
19
<PAGE>
The Company may conduct operations on federal oil and natural gas leases, and
such operations must comply with numerous regulatory restrictions and
requirements issued by the Mineral Management Service, including various
nondiscrimination statutes, and certain of such operations must be conducted
pursuant to appropriate permits issued by the Bureau of Land 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.
20
<PAGE>
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 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.
<TABLE>
<CAPTION>
Quarter Ended High Low
- --------------- ----- ------
<S> <C> <C>
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
</TABLE>
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.
22
<PAGE>
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 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 1994 1993
RESULTS OF OPERATIONS: ------------ --------- ---------
<S> <C> <C> <C>
From oil and natural gas operations:
Revenues $ 4,597 $ 6,477 $ 10,997
Gross profit 1,706 2,030 5,795
Net loss applicable to common stock (17,065) (10,769) (26,951)
Per common share (0.68) (0.42) (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) $ (1,482) $ (9,209)
Property and equipment, net 7,411 7,257 9,404
Total assets 9,791 10,676 30,065
Long-term debt 500 1,150 -
Redeemable Senior Preferred Stock 61,737 44,602 30,013
Stockholders' equity (deficit) (55,799) (39,004) (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.
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 Company without charge, for
further information.
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%)
General and administrative expenses (1,476) (1,747) (16%)
Operating income $ 1,147 $ 1,563 (27%)
======= ======= ====
</TABLE>
Operating income for 1995 and 1994 was significantly impacted by
management's continuing efforts regarding cost reductions and revenue collection
accelerations. As a result, operating income for 1995 and 1994 benefitted by
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
1995 also included a pre-petition tax settlement benefit, including interest, of
$251,000. Excluding receivable recoupments, gas balancing net revenues and tax
settlement, operating income for 1995 and 1994 would have been $258,000 and
$178,000, respectively.
25
<PAGE>
Revenues
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 14% 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 $15.22 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
<TABLE>
<CAPTION>
1995 1994 Change
<S> <C> <C> <C>
Oil revenues (in thousands) $ 1,081 $ 940 15%
Oil sales volume (barrels) 62,900 61,700 2%
Oil average price per barrel $ 17.20 $ 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 (14%)
</TABLE>
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 8 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.
Costs and Expenses
Consolidated costs and expenses decreased by $2,753,000 or 38% to $4,565,000
for 1995 as compared to $7,318,000 for 1994. This decrease was due to declines
in all expense categories, with significant decreases in operating and
exploration costs and interest expense.
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 $202,000 and $141,000, respectively, of production taxes and $274,000
and $167,000, respectively, of workover
27
<PAGE>
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 proved undeveloped and
proved developed nonproducing reserves. These reserves, which previously had not
been booked because of the Company's inability to develop them, were recorded.
As a result of these changes in calculating DD&A, 1995 and 1994 DD&A expense
were decreased 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 $271,000 or 16% to
$1,476,000 from $1,747,000 in 1994. This decrease was primarily the result of
lower franchise taxes and staff and related costs. 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 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.
28
<PAGE>
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.
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 $492,000.
Interest expense decreased $827,000 or 85% in 1995 to $142,000 from $969,000
in 1994. This decrease is primarily attributable to lower average debt
outstanding and lower interest rates. During 1995, maximum bank borrowings
outstanding were $1,150,000 resulting in a year end balance of $500,000. During
1994, borrowings outstanding peaked at $19,499,000. 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. 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.
In conjunction with the recognition of tax gains on property sales and debt
restructuring, the Company estimated and accrued federal and state alternative
minimum income taxes in 1994 of $180,000. As a result of additional benefits
derived from the 1994 partnership liquidations and tax complexities therewith,
and the recognition of additional tax basis on sold and abandoned properties,
the Company was able to reduce the prior year accrual resulting in a tax benefit
for 1995 of $163,000.
Debt forgiveness for 1995 and 1994 resulted in the recognition of an
extraordinary gain of $93,000 and $4,991,000, respectively. The 1995 gain was
derived from Administrative Note settlements and claim forfeitures. The 1994
gain was comprised of bank debt restructuring ($4,160,000) (See "Bank Debt-
Indebtedness") and the discounting of certain Administrative Notes ($831,000)
(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 $289,000 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 the excess
of borrowing base over year end borrowings outstanding and the current monthly
facility
29
<PAGE>
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 in
36 month period and all borrowings outstanding are due on July 13, 1997.
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 $55,799,000. 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.
30
<PAGE>
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.
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.
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.
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.
31
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
CONSOLIDATED FINANCIAL STATEMENTS
To the Board of Directors
and Stockholders of TGX Corporation
In our opinion, the accompanying consolidated financial statements 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.
The accompanying consolidated financial statements have been prepared assuming
that the Company will continue as a going concern. As discussed in Note 14 to
the consolidated financial statements, the Company has a substantial accumulated
deficit and a working capital deficit that raise substantial doubt about its
ability to continue as a going concern. Management's plans in regard to these
matters are also discussed in Note 14. The consolidated financial statements do
not include any adjustments that might result from the outcome of this
uncertainty.
PRICE WATERHOUSE LLP
Houston, Texas
March 28, 1996
32
<PAGE>
TGX Corporation and Subsidiaries
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
December 31,
(Thousands of dollars except for share 1995 1994
data)
- ------------------------------------------------------------------
<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 - 6 504
Note 10
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 $ 3,515
Accounts payable to affiliates - 242
Notes payable - 171
- -----------------------------------------------------------------
Total current liabilities 3,353 3,928
- -----------------------------------------------------------------
Long-term debt - Note 3 500 1,150
- -----------------------------------------------------------------
Total liabilities 3,853 5,078
- -----------------------------------------------------------------
Commitments and contingencies - Note 4
Redeemable Senior Preferred Stock,
8,851,360
issued; redemption value $88,514,000
- Note 7 61,737 44,602
- -----------------------------------------------------------------
Stockholder's deficit: - Note 8
9% Cumulative Convertible Preferred
Stock, 300,000 shares
issued plus 158,000 shares to be
issued for dividends 458 431
Common stock, 28,976,791 shares
issued; 24,956,033 and 25,313,533
outstanding, respectively 290 290
Additional paid-in capital 1,422 1,179
Accumulated deficit (57,969) (40,904)
- -----------------------------------------------------------------
Total stockholders' deficit (55,799) (39,004)
- -----------------------------------------------------------------
TOTAL LIABILITIES AND STOCKHOLDERS' $ 9,791 $ 10,676
DEFICIT
=================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
33
<PAGE>
TGX Corporation and Subsidiaries
CONSOLIDATED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
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
Provision for loss on sale of assets - -
Exploration costs 69 416
General and administrative expenses 1,476 1,747
Interest 142 969
- ------------------------------------------------------------------------------
4,565 7,318
- ------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES AND
EXTRAORDINARY GAIN 32 (820)
Income tax expense (benefit) - Note 9 (163) 180
- ------------------------------------------------------------------------------
NET INCOME (LOSS) BEFORE EXTRAORDINARY
GAIN 195 (1,000)
Extraordinary gain - Note 3 93 4,991
- ------------------------------------------------------------------------------
NET INCOME (LOSS) 288 3,991
Preferred stock dividends (12,308) (10,780)
Accretion of Senior Preferred
redemption value (5,045) (3,980)
NET LOSS APPLICABLE TO
COMMON STOCK $(17,065) $(10,769)
==============================================================================
PER SHARE OF COMMON STOCK AMOUNTS:
Before extraordinary gain $(.68) $(.62)
Extraordinary gain - .20
- ------------------------------------------------------------------------------
NET LOSS $(.68) $(.42)
==============================================================================
AVERAGE COMMON SHARES
OUTSTANDING 25,105 25,314
==============================================================================
</TABLE>
See accompanying notes to consolidated financial statements.
34
<PAGE>
TGX Corporation and Subsidiaries
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31,
(Thousands of dollars) 1995 1994
- ----------------------------------------------------------------------------
<S> <C> <C>
Cash flows from operating activities:
Net income (loss) $ 288 $ 3,991
Adjustments to reconcile net loss
before extraordinary gain 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)
Extraordinary gain (93) (4,991)
Changes in operating assets and
liabilities:
Decrease in accounts receivable 65 492
Decrease in accounts due from/to affiliates, net 256 791
Decrease in other current assets 9 15,216
Decrease in accounts payable and accrued expenses (162) (4,041)
- ----------------------------------------------------------------------------
Net cash provided by operating activities 1,554 12,711
- ----------------------------------------------------------------------------
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) (262)
Decrease in affiliate accounts receivable - 100
Notes payable issued to administrative claimants - -
Net cash used by financing activities (786) (14,488)
- ----------------------------------------------------------------------------
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 $ 93 $ 5,253
notes payable
</TABLE>
See accompanying notes to consolidated financial statements
35
<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, the cost of productive exploratory and all development wells is
capitalized and amortized based on proved producing reserves using the unit-of-
production method. Prior to 1994, the Company included only proved developed
producing reserves in its calculation of depletion, depreciation and
amortization. However, costs related to total proved reserves were included in
the amortization base. 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 proved non-producing and
undeveloped reserves. The undeveloped reserves, which heretofore had not been
booked because of the Company's inability to develop them, were recorded. As a
result of utilizing all 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 non-productive exploration wells is charged
to operations. If an assessment
36
<PAGE>
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.
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.
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.
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
37
<PAGE>
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.
38
<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
39
<PAGE>
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
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:
<TABLE>
<CAPTION>
(In thousands) 1995 1994
- ----------------------------------------------------
<S> <C> <C>
Bank borrowings:
Revolving credit facility (secured) $ 500 $1,150
Less current maturities - -
- ----------------------------------------------------
Long-term debt $ 500 $1,150
====================================================
</TABLE>
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 redetermination facility, borrowings are payable through
monthly principal reductions of $50,000. The loan was initially repayable in 36
months and 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.
40
<PAGE>
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 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 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"). 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 $4,652,000 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. Since the BMOF loan has no recourse, the Company
recognized an extraordinary gain from the effective debt forgiveness, net of
transaction expense of $492,000, of $4,160,000 in 1994. 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 of which $449,000 has been paid through
the issuance of additional notes to BMOF.
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
41
<PAGE>
$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.
In summary, the Company reflected a total net extraordinary gain for 1995 of
$93,000 for Administrative Note forgiveness and for 1994 of $4,991,000 as the
result of net secured debt and Administrative Note forgiveness of $4,160,000 and
$831,000, respectively.
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
42
<PAGE>
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 ("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.
43
<PAGE>
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 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.
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
44
<PAGE>
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 lis pendens 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.
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.
45
<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
- ---------------------------------------------------------------------
SUMMARY BALANCE SHEETS
<S> <C> <C>
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
Miscellaneous accruals 1,127 991
- ----------------------------------------------------------------------------------
$3,352 $3,515
==================================================================================
</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 and have priority over
the liquidation preference afforded the holders of Series B
46
<PAGE>
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"). 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. 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 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 5,045
dividends
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>
47
<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>
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 income - - - 3,991
- -------------------------------------------------------------------------------
Balance, December 31, 1994 431 290 1,179 (40,904)
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 income - - - 288
- -------------------------------------------------------------------------------
Balance, December 31, 1995 $458 $290 $1,422 $(57,969)
===============================================================================
</TABLE>
48
<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
49
<PAGE>
grant was charged to expense over a five-year period, regardless of whether or
not the shares are ultimately earned by the employee. The Company has reserved
89,333 shares of Common Stock for issuance under the plan. 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 Incentive
Plan 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 and debt
restructuring, the Company estimated and accrued federal and state alternative
minimum income taxes in 1994 of $180,000. As a result of additional benefits
derived from the 1994 partnership liquidations and tax complexities therewith,
and the recognition of additional tax basis on sold and abandoned properties,
the Company was able to reduce the prior year accrual resulting in a tax benefit
for 1995 of $163,000.
50
<PAGE>
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>
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 (130.4) 4.3
- ---------------------------------------------------------------
(130.4) 4.3%
===============================================================
</TABLE>
As of December 31, 1995, the Company had substantial tax net operating loss
carryovers and investment tax credit and depletion carryforwards which expire at
varying times from 1996 to 2008.
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. In addition, the amount of loss carryovers
utilized will be increased by any built-in gain exclusion recognized during the
five year period after the "change of ownership".
51
<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
is 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%
Natural Fuel Gas Distribution
Corporation - -
Noram Energy Services Inc. - 12%
Princeton Natural Gas Company 28% 15%
Transcontinental Gas Pipe Line Co. 26% -
</TABLE>
52
<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
- -------------------------------------------------------------------------------------------
Capitalized costs:
<S> <C> <C>
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 $ 686 $ 515
===========================================================================================
</TABLE>
(1) 1994 activity represents primarily properties received in settlement of
certain partnership notes and receivables.
(2) Excludes general and administrative and interest expense.
53
<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 volumes
related to gas balancing 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
54
<PAGE>
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.
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.
55
<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.
56
<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 $ 1,140 $ 956 $ 1,241 $ 1,260
Gross profit 529 144 327 706
Extraordinary gain (loss) 118 (25) - -
Net loss applicable to
common stock (4,300) (4,625) (4,609) (3,531)
Loss per common share $ (0.17) $ (0.19) $ (0.18) $ (0.14)
=============================================================================================
1994:
Revenues $ 1,487 $ 1,903 $ 1,645 $ 1,463
Gross profit 574 471 469 516
Extraordinary gain - - 4,288 703
Net income (loss) applicable to
common stock (4,051) (3,402) 115 (3,431)
Loss per common share $(0 .16) $ (0.13) $ 0.00 $ (0.13)
=============================================================================================
</TABLE>
57
<PAGE>
14. ONGOING BUSINESS OPERATIONS
The accompanying consolidated financial statements have been prepared
assuming that the Company will continue as a going concern. The Company has a
substantial accumulated deficit and a significant working capital deficit that
raise substantial doubts about its ability to continue as a going concern. The
financial statements do not reflect any adjustments that might result from the
outcome of this uncertainty.
In 1996, the Company will be looking to further reduce its overhead,
eliminate additional non-core assets, and improve 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. In addition, though the
Company, in opinion of management, 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.
Management does believe, however, that its current credit facility and
anticipated improving operating activity will generate the necessary cash flow
to support its ongoing business operations, NFG litigation cost and oil and gas
property development activities in accordance with its business plans.
58
<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
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.
59
<PAGE>
<TABLE>
<CAPTION>
The members of the Board are:
<S> <C> <C> <C>
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.
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.
</TABLE>
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.
60
<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.
<TABLE>
<CAPTION>
Name Age Position
- ---- --- ----------
<S> <C> <C>
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.
</TABLE>
61
<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
$100,000. For 1994, other annual compensation for Mr. Carpenter includes
reimbursement of house and automobile expenses.
SUMMARY COMPENSATION TABLE (1)
<TABLE>
<CAPTION>
LONG TERM
---------
COMPENSATION
ANNUAL COMPENSATION AWARDS
--------------------------- ------------
Name and Principal
Position Year Salary($) Bonus($) Other Annual Compensation($) Restricted Stock Awards($)
- -------------------- ---- ------------ ------------ ---------------------------- ---------------------------
<S> <C> <C> <C> <C> <C>
Larry H. Carpenter 1995 $ 209,000 $ 125,000 (4) -0- (5)
President/CEO 1994 $ 175,000 $ 100,000 $26,062 (3) (6)
Michael A. Gerlich 1995 $107,000 (2) $ 10,000 (4) -0- (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 no trading in the Series A Senior Preferred Stock and,
therefore, the Company was not able to determine a market value for such
stock.
(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
62
<PAGE>
in the Series A Senior preferred Stock and, therefore, the Company was not
able to determine a market value for such stock.
(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 no trading in the Series A. Senior Preferred Stock and,
therefore, the Company was not able to determine a market value for such
stock.
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.
63
<PAGE>
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.
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
Name of Sole Voting and Exercisable Percent 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 investment
powers. Unless otherwise stated, the percentage is less than one percent.
(2) Of Mr. Carpenter's shares 200,000 are subject to forfeiture pursuant to the
terms of his employment agreement. See "Employment Agreement".
64
<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 of Oklahoma Common 3,136,986/(1)/ 12.6%
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)/ 21.0%
</TABLE>
- ------------------------------------------------------------------------------
(1) In connection with its acquisition of Amarex, Inc. which was consummated on
December 5, 1985, the Company issued 11,475,000 shares of Common Stock into
escrow with Liberty National Bank and Trust Company of Oklahoma City as
escrow agent. Such shares are held by the escrow agent for the benefit of
various classes of creditors of Amarex and its affiliates entitled to
receive the shares under a Plan of Reorganization confirmed in Amarex's
bankruptcy proceeding, and the shares have been and will continue to be
distributed by the escrow agent from time to time as the various creditors'
claims are adjudicated and allowed by the Bankruptcy Court. As of March 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 supplied to the Company pursuant to a Schedule
13D filed with the Securities and Exchange Commission on December 31, 1994,
by AIF II, L.P., a Delaware
65
<PAGE>
limited partnership and Lion Advisors, L.P., a Delaware limited partnership
(collectively the "Reporting Persons"). Such Reporting Persons may together
constitute a "group" within the meaning of Rule 13d-5 under the Securities
Exchange Act of 1934, as amended.
66
<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) Reports of Independent Accountants
(i) Price Waterhouse LLP
(b) Financial Statements of TGX Corporation (the Registrant) and
Subsidiaries
(i) Consolidated Balance Sheet as of December 31, 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
67
<PAGE>
(Incorporated by reference to Exhibit 2.1 of the Registrant's
Current Report on Form 8-K dated December 1, 1986, File No. 0-
10201).
Exhibit 3.1 Restated Certificate of Incorporation of the Company. (Incorporated
by reference to Exhibit 3.1 of the 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 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).
68
<PAGE>
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 1, 1992, executed by the Company to the
order of the Bank of 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
and Ronald E. Grappe. (Incorporated by reference to Exhibit 10.13
of the Registrant's Annual Report on Form 10-K for the year ended
December 31, 1991, File No. 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).
69
<PAGE>
Exhibit 10.15 Form of Indemnification Agreement to be entered into by and among
the Company and each officer and director. (Incorporated by
reference to Exhibit 10.15 of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1991, File No. 0-10201).
Exhibit 10.16 Form of Indemnification Trust Agreement. (Incorporated by
reference to Exhibit 10.16 of the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1991, File No. 0-10201).
Exhibit 10.17 Promissory Note (Term Loan D) in the amount of $194,750 effective
October 1, 1992, executed by the Company to the order of Bank of
Montreal. (Incorporated by reference to Exhibit A of Form 8-K
dated October 2, 1992, File No. 0-10201).
Exhibit 10.18 Personal Service and Employment Agreement Dated March 30, 1992
between the Company and Larry H. Carpenter. (Incorporated by
reference to Exhibit 10.18 of Form 10-K for the year ended
December 31, 1992, File No. 0-10201).
Exhibit 10.19 Purchase and Sale Agreement between TGX Corporation and Belden and
Blake Corporation dated as of December 17, 1993 (Incorporated by
reference to Exhibit C of Form 8-K dated January 14, 1994, File
No. 0-10201).
Exhibit 10.20 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. (Filed herewith)
Exhibit 18 Letter regarding Change in Accounting Principles. (Incorporated by
reference to Exhibit 18 of Form 10-K for the year ended December
31, 1992, File No. 0-10201).
Exhibit 21.1 Subsidiaries of the Registrant.
Exhibit 27 Financial Data Schedule (Filed herewith)
(b) Reports on Form 8-K for the quarter ended December 31, 1995:
None.
70
<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/ LARRY H. CARPENTER Chairman of the Board,
--------------------------- President, and Chief
Larry H. Carpenter Executive Officer March 28, 1996
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/ LARRY H. CARPENTER Chairman of the Board,
------------------------------ President, and Chief
Larry H. Carpenter Executive Officer March 28, 1996
By: /s/ MICHAEL A. GERLICH Vice President, March 28, 1996
------------------------------ Chief Financial Officer,
Michael A. Gerlich and Chief Accounting
Officer
By: /s/ DAVID H. SCHEIBER Director March 28, 1996
------------------------------
David H. Scheiber
By: /s/ JEFFREY E. SUSSKIND Director March 28, 1996
-------------------------------
Jeffrey E. Susskind
71
<PAGE>
FIRST AMENDMENT TO
SECOND AMENDED AND RESTATED CREDIT AGREEMENT
THIS FIRST AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT (the
"Amendment"), dated as of December 31, 1995, is between TGX CORPORATION, a
Delaware corporation ("TGX"), and BMO FINANCIAL, INC., a Delaware corporation
("BMO Financial").
RECITALS:
A. TGX and BMO Financial have entered into that certain Second Amended and
Restated Credit Agreement (the "Agreement") dated as of July 13, 1994.
B. TGX and BMO Financial now desire to amend the Agreement as herein set
forth.
NOW, THEREFORE, in consideration of the premises herein contained and other
good and valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the parties hereto agree as follows:
ARTICLE I
DEFINITIONS
Section 1.1 Definitions. Capitalized terms used in this Amendment, to the
extent not otherwise defined herein, shall have the same meanings as in the
Agreement, as amended hereby.
ARTICLE II
AMENDMENTS
Section 2.1 Amendments to Definitions. Effective as of the date hereof, the
following defined terms in Section 1.1 of the Agreement are amended in their
respective entireties to read as follows:
"'Initial Net Proceeds Date' shall mean, if Holder has received aggregate
Prepayment Offers under Section 3.4(d) equal to the then outstanding principal
and interest on all outstanding Notes as of the date the most recent
Prepayment Offer was received by the Holder, the first date thereafter when
TGX has received aggregate Gross Proceeds equal to twice the amount of such
aggregate Prepayment Offers made to Holder pursuant to Section 3.4(d)."
"'Net Proceeds' shall mean (i) on the Initial Net Proceeds Date, an amount
equal to the aggregate of all Gross Proceeds received by TGX prior to and on
such date minus twice the amount of the aggregate Prepayment Offers received
by the Holder pursuant to Section 3.4(d), or (ii) after the Initial Net
Proceeds Date, any Gross Proceeds received by TGX from that date forward."
<PAGE>
Section 2.2 Amendments to Sections 3.4(d), 3.7(b) and 3.8(b). Effective as of
the date hereof, Sections 3.4(d), 3.7(b) and 3.8(b) are amended in their
respective entireties to read respectively as follows:
"3.4 (d) If TGX is required to send notices pursuant to Section 3.4(b)
before the Proceeds Share Calculation Date shall have occurred, each such notice
(referred to herein as a "Prepayment Offer") shall include an offer of payment
to the Holder in an amount equal to (i) fifty percent (50%) of Gross Proceeds
for the first Eight Million Dollars ($8,000,000.00) of aggregate Gross Proceeds
received from time to time by TGX; and (ii) One Hundred Percent (100%) of any
additional Gross Proceeds received by TGX (in excess of such first Eight Million
Dollars ($8,000,000.00) referred to in (i) above) until the amount offered to
the Holder pursuant to subparagraphs (i) and (ii) hereof equals the then
outstanding principal and interest on all outstanding Notes as of the date the
most recent Prepayment Offer was received by the Holder."
"3.7 (b) No later than 3 Business Days after the occurrence of the Maturity
Date as a result of the occurrence of the events specified in Section 3.6(b),
TGX shall notify the Holder that the Maturity Date has occurred (the "Notice of
Final Resolution"). Such Notice of Final Resolution shall include (i) an
estimate of the aggregate amount of all Gross Proceeds received by TGX up to the
Maturity Date and the aggregate amount of all Gross Proceeds held by TGX on the
Maturity Date and of any Net Proceeds Share due to the Holder and (ii) a
certificate of an executive officer of TGX that the Final Resolution has
occurred, which certificate shall constitute a representation and warranty of
TGX that shall survive the payment in full of the Notes and, if applicable, the
Initial Net Proceeds Date. In such event, the notice required by Section 3.4(b)
shall include (i) if the Proceeds Share Calculation Date shall have occurred, a
notice of such occurrence and a tender of payment in full of all Restated
Obligations including, if any, the outstanding principal of and accrued interest
on the Notes and the Net Proceeds Share due to the Holder or (ii) if the
Proceeds Share Calculation Date shall not have occurred, a tender of payment to
the Holder of an amount equal to all Gross Proceeds required to be made the
subject of a Prepayment Offer pursuant to Section 3.4(d) and not previously paid
to the Holder. Without prejudice to the right of the Holder to contest the
amount tendered, the Holder shall accept any tender of payment in connection
with the occurrence of the Final Resolution and, upon receipt of such payment,
the Notes (if not previously paid in full or if not paid in full upon receipt of
such payment) shall be deemed discharged and the Holder shall, at the cost and
expense of TGX, release its Lien on the Secured Property."
"3.8 (b) The Net Proceeds Share shall be permanently fixed as of the date
when Holder has received aggregate Prepayment Offers pursuant to Section 3.4(d),
less any amount accepted prior to such date by Holder pursuant to Section 3.5(a)
and applied against the principal of the Notes in accordance with Section 2.3,
which equal or exceed the principal of and accrued interest on the
2
<PAGE>
Notes outstanding as of such date (the "Proceeds Share Calculation Date");
provided, however, that the Net Proceeds Share shall be in an amount equal to
50% without regard to whether the Holder, prior to the Proceeds Share
Calculation Date, shall have accepted any payments that reduced the principal
amount outstanding under the Original Note if the Maturity Date shall have
occurred as a result of the occurrence of an event specified in Section 3.6(d)."
Section 2.3 Amendment to Section 3.4(c). Effective as of the date hereof,
Section 3.4(c) is amended in its entirety to read as follows:
"(c) If a receipt of Gross Proceeds by TGX causes the occurrence of, or
occurs after the occurrence of, the Proceeds Share Calculation Date,the
notice required by Section 3.4(b) shall include notice of such occurrence
and the tender of payment by TGX of payment in full of all Restated
Obligations, including the Net Proceeds Share, if any, due to the Holder.
Section 2.4 Amendment to Section 7.10(b). Effective as of the date hereof,
Section 7.10(b) of the Agreement is amended in its entirety to read as follows:
(b) Upon Election, BMO Financial shall have the right to cause TGX, and
TGX hereby agrees, to assign, transfer and deliver to BMO Financial all of
its right, title and interest in and to the NFG Related Claim that is the
subject of a Discontinuance and any Gross Proceeds thereof previously
received by TGX which are required to be made the subject of a Prepayment
Offer pursuant to Section 3.4(d) to the extent not otherwise paid to Holder
(unless the Proceeds Share Calculation Date shall have occurred in
accordance with Section 3.4(c) and Section 3.5(b), in which event TGX shall
deliver any portion of the Gross Proceeds that constitute any remaining Net
Proceeds Share due to the Holder) or, in the case of a Settlement, all of
the NFG Related Claims and any Gross Proceeds thereof previously received by
TGX which are required to be made the subject of a Prepayment Offer pursuant
to Section 3.4(d) to the extent not otherwise paid to Holder (unless the
Proceeds Share Calculation Date shall have occurred and tender and
acceptance of payment shall have occurred in accordance with Section 3.4(c)
and Section 3.5(b) in which event TGX shall deliver any portion of the Gross
Proceeds that constitute any remaining Net Proceeds Share due to the
Holder), in a form sufficient to satisfy all necessary and desirable legal
requirements for proper assignment thereof (the "Assignment").
Section 2.5 Amendment to Section 7.10. Effective as of the date hereof,
Section 7.10 of the Agreement is amended hereby by adding the following
paragraph at the end thereof:
"Notwithstanding the foregoing provisions of this Section 7.10 or any other
provisions as set forth in this Agreement or any Related Document to the
contrary, TGX is authorized to enter into any Settlement of all or any part
of the NFG Related Claims without obtaining any consent of BMO Financial or
any other
3
<PAGE>
party to any of the Related Documents so long as the Gross Proceeds of such
Settlement equal or exceed Seven Million Dollars ($7,000,000.00)."
ARTICLE III
RATIFICATIONS, REPRESENTATIONS AND WARRANTIES
Section 3.1 Ratifications. The terms and provisions set forth in this
Amendment shall modify and supersede all inconsistent terms and provisions set
forth in the Agreement except as expressly modified and superseded by this
Amendment, the terms and provisions of the Agreement are ratified and confirmed
and shall continue in full force and effect. TGX and BMO Financial agree
that the Agreement as amended hereby shall continue to be legal, valid, binding
and enforceable in accordance with its terms.
Section 3.2 Representations and Warranties. Each of the parties hereto hereby
represents and warrants to other that the execution, delivery and performance of
this Agreement has been authorized by all requisite corporate action on the part
of such party and will not violate the certificate of incorporation or bylaws of
such party.
Section 3.3 Reaffirmation. TGX acknowledges that, as of the date hereof, it
is justly and truly indebted to the Holder in the amount o $5,337,072.54,
constituting the aggregate amount of outstanding principal of and accrued and
unpaid interest on the Obligations evidenced by the Original Note and the PIK
Notes. The Obligations evidenced by the Original Note and the PIK Notes
constitute valid and subsisting obligations of TGX subject to no offsets,
defenses, counterclaims or other claims. Nothing contained in this Section or
elsewhere in this Amendment shall be deemed to affect the limited recourse
nature of the Original Note or the PIK Notes as set forth in Section 9.1 of the
Agreement.
ARTICLE IV
MISCELLANEOUS
Section 4.1 Survival of Representations and Warranties. All representations
and warranties made in this Amendment shall survive the execution and delivery
of this Amendment, and no investigation by BMO Financial or any closing shall
effect the representations and warranties or the right of BMO Financial to rely
upon them.
Section 4.2 Reference to Agreement. Each of the Related Documents, the
Agreement and the Notes and any and all other agreements, documents, or
instruments now or hereafter executed and delivered pursuant to the terms hereof
or pursuant to terms of the Agreement as amended hereby, are hereby amended so
that any reference in such documents and/or instruments to the Agreement shall
mean a reference to the Agreement as amended hereby.
Section 4.3 Amendments, Etc. No amendment, modification, termination or
waiver of any provision of this Amendment, nor consent to any departure by TGX
therefrom shall in any event be effective unless the same shall be in writing
and signed by the Holder. No notice to
4
<PAGE>
or demand on TGX in any case shall entitle TGX to any other or further notice or
demand in similar or other circumstances.
Section 4.4 No Third Party Beneficiaries. The parties acknowledge and agree
that, except as set forth in Section 9.2 of the Agreement, there are no third
party beneficiaries of this Amendment and that the parties hereto have no
obligations to any third parties regarding the terms of this Agreement.
Section 4.5 Binding Effect. This Agreement shall be binding upon and inure to
the benefit of TGX and BMO Financial and their respective successors and
assigns.
Section 4.6 GOVERNING LAW; SEVERABILITY. THIS AMENDMENT AND THE RIGHTS AND
OBLIGATIONS OF THE PARTIES HERETO SHALL BE GOVERNED BY, AND CONSTRUED IN
ACCORDANCE WITH, THE INTERNAL LAWS (AS OPPOSED TO CONFLICTS OF LAW PROVISIONS,
BUT INCLUDING SECTION 5-1401 OF THE NEW YORK GENERAL OBLIGATIONS LAW) OF THE
STATE OF NEW YORK. WHEREVER POSSIBLE, EACH PROVISION OF THIS AMENDMENT SHALL BE
INTERPRETED IN SUCH MANNER AS TO BE EFFECTIVE AND VALID UNDER APPLICABLE LAW;
BUT IF ANY PROVISION OF THIS AGREEMENT SHALL BE PROHIBITED BY OR INVALID UNDER
APPLICABLE LAW, SUCH PROVISION SHALL BE INEFFECTIVE TO THE EXTENT OF SUCH
PROHIBITION OR INVALIDITY, WITHOUT INVALIDATING THE REMAINDER OF SUCH PROVISION
OR THE REMAINING PROVISIONS OF THIS AGREEMENT. Without limiting the foregoing,
nothing contained in this Amendment, the Agreement or any of the Related
Documents shall ever entitle the Holder, upon the arising of any contingency
whatsoever, to receive or collect interest in excess of the highest rate allowed
by applicable law on any indebtedness or any other obligations owing to other
and in no event shall TGX be obligated to pay interest thereon in excess of such
rate.
Section 4.7 SUBMISSION TO JURISDICTION; JURY TRIAL. (a) ANY LEGAL ACTION OR
PROCEEDING WITH RESPECT TO THIS AMENDMENT OR ANY DOCUMENT RELATED HERETO MAY BE
BROUGHT IN THE COURTS OF THE STATE OF NEW YORK OR OF THE UNITED STATES OF
AMERICA FOR THE SOUTHERN DISTRICT OF NEW YORK, AND, BY EXECUTION AND DELIVERY OF
THIS AGREEMENT, TGX HEREBY ACCEPTS FOR ITSELF AND IN RESPECT OF ITS PROPERTY,
GENERALLY AND UNCONDITIONALLY, THE JURISDICTION OF THE AFORESAID COURTS.
(b) EACH OF THE PARTIES HERETO WAIVES ANY RIGHT IT MAY HAVE TO TRIAL BY JURY
IN RESPECT OF ANY LITIGATION BASED ON, OR ARISING OUT OF, UNDER OR IN CONNECTION
WITH THIS AMENDMENT OR ANY RELATED DOCUMENTS, OR ANY COURSE OF CONDUCT, COURSE
OF DEALING, VERBAL OR WRITTEN STATEMENTS OR ACTIONS OF ANY PARTY HERETO.
Section 4.8 Section Titles. The Section titles contained in this Amendment
are and shall be without substantive meaning or content of any kind whatsoever
and are not a part of the agreement between the parties hereto.
5
<PAGE>
Section 4.9 Execution in Counterparts. This Amendment may be executed in any
number of counterparts and by different parties hereto in separate counterparts,
each of which when so executed shall be deemed to be an original and all of
which taken together shall constitute one and the same agreement.
THIS WRITTEN AMENDMENT, THE AGREEMENT AND THE RELATED DOCUMENTS REPRESENT THE
FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF
PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE
NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.
Accepted and Agreed to effective as of the day and year first written above.
TGX CORPORATION
By: /s/ Larry H. Carpenter
--------------------------------
Larry H. Carpenter, President
Signed and Delivered in the
Presence of
/s/ Dawn T. Steele
- -----------------------------
Dawn T. Steele
- -----------------------------
(Type or Print Name)
/s/ Donna Villegas
- -----------------------------
Donna Villegas
- -----------------------------
(Type or Print Name)
6
<PAGE>
HOLDER:
BMO FINANCIAL, INC.
By: /s/ Thomas E. McGraw
--------------------------
Thomas E. McGraw
Title: Manager
Signed and Delivered in the
Presence of
/s/ Justine V. Fjeldal
- -------------------------------
Justine V. Fjeldal
- -------------------------------
(Type or Print Name)
/s/ Sandi Hartig
- -------------------------------
Sandi Hartig
- -------------------------------
(Type or Print Name)
STATE OF TEXAS )
)
COUNTY OF HARRIS )
On the 15th day of January, 1996, before me personally appeared Larry H.
Carpenter, as President of TGX Corporation, a Delaware corporation, to me known
to be the person described in and who executed the foregoing on behalf of said
corporation.
/s/ Kenneth A. Cravens
-------------------------------------------
Notary Public in and for the State of Texas
[NOTARY SEAL OF KENNETH A. CRAVENS APPEARS HERE]
7
<PAGE>
STATE OF TEXAS )
)
COUNTY OF HARRIS )
On the 23rd day of January, 1996, before me personally appeared Thomas E.
McGraw, as Manager of BMO Financial, Inc., a Delaware corporation, to me known
to be the person described in and who executed the foregoing on behalf of said
corporation.
/s/ Annette Sparks
-------------------------------------------
Notary Public in and for the State of Texas
[NOTARY SEAL OF ANNETTE SPARKS APPEARS HERE]
8
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<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<F1>
458
<COMMON> 290
<OTHER-SE> (56,547)
<TOTAL-LIABILITY-AND-EQUITY> 9,791
<SALES> 3,856
<TOTAL-REVENUES> 4,597
<CGS> 1,905
<TOTAL-COSTS> 1,905
<OTHER-EXPENSES> 2,518
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 142
<INCOME-PRETAX> 32
<INCOME-TAX> (163)
<INCOME-CONTINUING> 195
<DISCONTINUED> 0
<EXTRAORDINARY> 93
<CHANGES> 0
<NET-INCOME> (17,065)
<EPS-PRIMARY> (0.68)
<EPS-DILUTED> (0.68)
<FN>
<F1>Represents Series A Redeemable Senior Preferred Stock that has a $10
Liquidation preference and entitles holder to 10% annual compounded cash
dividend. No dividends paid to date.
</FN>
</TABLE>
