<PAGE> 1
================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
FORM 10-K
[ ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
OF 1934
[ ]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE YEAR ENDED DECEMBER 31, 1996
COMMISSION FILE NUMBER 1-10192
WRT ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
<TABLE>
<C> <C>
DELAWARE 73-1521290
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
</TABLE>
1601 NW EXPRESSWAY, SUITE 700
OKLAHOMA CITY, OKLAHOMA 73118-1401
(405) 848-8808
(Address, including zip code, and telephone number, including area code, of
registrant's principal executive office)
Securities registered pursuant to Section 12(b) of the Act:
NOT APPLICABLE
Securities registered pursuant to Section 12(g) of the Act:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
------------------- ------------------------
<S> <C>
Prior to Effective Date of Plan of Reorganization:
Common Stock, $0.01 par value............................. **
9% Convertible Preferred Stock, $0.01 par value........... **
Effective Date of Plan of Reorganization forward:
New Common Stock, $0.01 par value......................... **
New 9% Convertible Preferred Stock, $0.01 par value....... **
</TABLE>
Indicate by a 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 [ ] No [X]
Indicate by a check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.
The aggregate market value of the voting stock held by non-affiliates of the
registrant as of a recent date is not determinable as the Company's New Common
Stock is not actively traded.
All shares of common and preferred stock outstanding prior to the Effective
Date of the Plan of Reorganization (July 11, 1997) were cancelled on the
Effective Date. The number of shares of the registrant's Common Stock, $0.01 par
value, outstanding at September 30, 1997 was 22,076,315.
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 [ ]
DOCUMENTS INCORPORATED BY REFERENCE
NONE
** The registrant's common stock and 9% Convertible Preferred Stock were quoted
on the NASDAQ National Market until February 29, 1996, at which time NASDAQ
terminated its quotation of both classes of securities due to the failure of
the registrant to meet certain financial and other criteria for continued
quotation. See "Item 5. Market for Registrant's Common Stock and Related
Shareholder Matters." The Company intends to apply for listing of the New
Common Stock on the NASDAQ National Market. There can be no assurance that
the Company's New Common Stock will be listed.
================================================================================
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C> <C>
Disclosure Regarding Forward-Looking Statements....................... 3
PART I
Item 1. Business.................................................... 3
Item 2. Properties.................................................. 11
Item 3. Legal Proceedings........................................... 18
Item 4. Submission of Matters to a Vote of Security Holders......... 21
PART II
Item 5. Market for the Registrant's Common Stock and Related
Shareholder Matters......................................... 21
Item 6. Selected Financial Data..................................... 23
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 23
Item 8. Financial Statements and Supporting Data.................... F-1
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.................................... 35
PART III
Item 10. Directors, Executive Officers, Promoters and Control
Persons; Compliance with Section 16(a) of the Exchange
Act......................................................... 35
Item 11. Executive Compensation...................................... 36
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 38
Item 13. Certain Relationships and Related Transactions.............. 39
PART IV
Item 14. Exhibits and Reports on Form 8-K............................ 40
</TABLE>
2
<PAGE> 3
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-K includes "forward-looking statements" within the meaning of
Section 27A of the Securities Exchange Act of 1934 (the "Exchange Act"). All
statements, other than statements of historical facts, included in this Form
10-K that address activities, events or developments that WRT Energy
Corporation, a Delaware corporation, and its predecessor and subsidiaries,
referred to herein collectively as "New WRT" or the "Company", expects or
anticipates will or may occur in the future, including such things as estimated
future net revenues from oil and gas reserves and the present value thereof,
future capital expenditures (including the amount and nature thereof), business
strategy and measures to implement strategy, competitive strengths, goals,
expansion and growth of the Company's business and operations, plans, references
to future success, references to intentions as to future matters and other such
matters are forward-looking statements. These statements are based on certain
assumptions and analyses made by the Company in light of its experience and its
perception of historical trends, current conditions and expected future
developments as well as other factors it believes are appropriate in the
circumstances. However, whether actual results and developments will conform
with the Company's expectations and predictions is subject to a number of risks
and uncertainties; general economic, market or business conditions; the
opportunities (or lack thereof) that may be presented to and pursued by the
Company; competitive actions by other oil and gas companies; changes in laws or
regulations; and other factors, many of which are beyond the control of the
Company. Consequently, all of the forward-looking statements made in the Form
10-K are qualified by these cautionary statements and there can be no assurance
that the actual results or developments anticipated by the Company will be
realized, or even if realized, that they will have the expected consequences to
or effects on the Company or its business or operations.
PART I
ITEM 1. BUSINESS
DESCRIPTION OF BUSINESS
The Company owns and operates mature oil and gas properties in the
Louisiana Gulf Coast. The Company seeks to increase both the current production
and total oil and gas recovery through the use of technology, including
sophisticated radioactive logging equipment owned by the Company and specialized
fluid separation technologies.
BACKGROUND
On February 14, 1996 ("Petition Date"), the Company, WRT Energy
Corporation, a Texas corporation and the predecessor of the Company ("Debtor"),
filed a petition with the Bankruptcy Court for the Western District of Louisiana
("Bankruptcy Court") for protection under Chapter 11 of the Federal Bankruptcy
Code. Such case is referred to herein as the "Reorganization Case". Upon filing
of the voluntary petition for relief, the Debtor, as debtor-in-possession, was
authorized to operate its business for the benefit of claim holders and interest
holders, and continued to do so, without objection or request for appointment of
a trustee. All debts of the Debtor as of the Petition Date were stayed by the
bankruptcy petition and are subject to compromise pursuant to such proceedings.
The Debtor operated its business and managed its assets in the ordinary course
as debtor-in-possession, and obtained court approval for transactions outside
the ordinary course of business. Based on these actions, all liabilities of the
Company outstanding at February 14, 1996 were reclassified to estimated
pre-petition liabilities.
By order dated May 2, 1997, the Bankruptcy Court confirmed the Joint Plan
of Reorganization (the "Plan") of the Debtor's and co-proponents DLB Oil and
Gas, Inc. ("DLB") and Wexford Management LLC ("Wexford," and together with DLB
"DLBW"). The Plan was consummated and became effective on July 11, 1997 (the
"Effective Date"). On the Effective Date, the Debtor was merged with and into a
newly formed Delaware corporation named "WRT Energy Corporation". On the
Effective Date, New WRT allocated the actual reorganization value to the
entity's assets as defined by Statement of Position Number 90-7 "Financial
Reporting by Entities in Reorganization Under the Bankruptcy Code"
3
<PAGE> 4
("SOP 90-7"). As used herein, "Debtor" refers to the registrant prior to the
Effective Date of the Plan, "New WRT" refers to the registrant following the
Effective Date of the Plan, and the "Company" or "WRT" refers to the registrant
prior to or after the Effective Date of the Plan, as the context requires.
EVENTS LEADING TO THE REORGANIZATION CASE
Entering 1995, the Company's strategic focus was the acquisition and
development of operated working interests in large, mature oil and gas fields in
south Louisiana.
To help finance its acquisition and development program, the Company
utilized borrowings under its December 1994 $40,000,000 credit facility (the
"'Credit Facility"') with International Nederlanden (U.S.) Capital Corporation
("INCC") that was secured by substantially all of the Company's assets. In
addition, in February 1995, the Company offered 100,000 Units consisting of
$100,000,000 aggregate principal amount of 13 7/8% Senior Notes Due 2002 (the
"Senior Notes") and warrants (the "Warrants") to purchase an aggregate of
800,000 shares of the Company's Common Stock (the "Offering"). The net proceeds
from the Offering were used to acquire working interests in certain oil and gas
properties, to repay substantially all borrowings under the Credit Facility and
other indebtedness and for general corporate purposes.
During the remainder of 1995, the Company borrowed additional funds under
the Credit Facility, bringing the outstanding borrowings to $15,000,000, the
maximum amount of borrowings available under the Credit Facility. On December
31, 1995, the Credit Facility converted to a term loan whereby quarterly
principal payments of one-sixteenth of the outstanding indebtedness were due and
payable.
Following the completion of the acquisition of working interests in certain
oil and gas properties, the Company initiated a significant capital expenditure
program to increase oil and gas production levels in each of its fields. This
program consisted of approximately 70 workover, side track and recompletion
projects and ten new development wells. Funding was provided from operating cash
flow, remaining proceeds from the Offering and borrowings under the Credit
Facility. The Company's production levels increased on a gas equivalent (Mcfe)
basis from March 1995, when the oil and gas property acquisitions were
completed, to September 1995; however, the production increases were realized at
a slower pace than expected at the time of acquisition.
The lower than expected level of production resulted from various factors
including a combination of ordinary production declines, unexpected losses of
production from several key wells, mechanical difficulties in the Lac Blanc
Field and significant production declines in the predominantly oil producing
West Cote Blanche Bay Field, which was not then operated by the Company.
Contributing significantly to the shortfall in anticipated production rates were
three major well projects which proved to be unsuccessful in September 1995, for
which the Company expended a total of approximately $3,600,000. Also,
contributing to lower than expected net revenues and operating cash flow was a
significant decline in oil and gas prices during the third and early fourth
quarters of 1995 compared to the corresponding quarters of the previous year.
These lower than expected production rates, together with decreased oil and gas
prices during the third quarter of 1995, had a significant negative effect on
the Company's liquidity and cash flow from operations.
Based on operating results for the quarter ended September 30, 1995, the
Company had not yet realized the oil and gas production levels required at then
current prices and costs to support the Company's capital requirements and fund
existing debt service on the Senior Notes and pay dividends on its 9%
Convertible Preferred Stock ("Preferred Stock"). In early October 1995, the
Company had fully utilized the $15,000,000 borrowing base available under the
Credit Facility, and in response to liquidity and cash flow concerns, the
Company changed its focus from acquisition and development of non-producing
reserves to conservation of cash resources and maintenance of existing producing
properties. The Company curtailed its activities to the minimum level of
maintenance necessary to operate prudently its producing oil and gas wells. All
other activities, including prospect acquisitions, new drilling, and development
of the Company's proved non-producing and undeveloped reserves, ceased.
In connection with this strategy, the Company made certain changes to its
corporate structure and organization aimed at reducing costs and improving
operations. On November 10, 1995, Steven S. McGuire
4
<PAGE> 5
resigned as a director, Chairman of the Board and Chief Executive Officer of the
Company. Samuel C. Guy, the Company's Executive Vice President, also resigned as
a director. Mr. Guy's employment contract, which expired on February 29, 1996,
was not renewed by the Company. The Board of Directors appointed Raymond P.
Landry, previously President and Chief Operating Officer of the Company, to the
position of Chairman of the Board and Chief Executive Officer. See Item 10,
"Directors, Executive Officers, Promoters and Control Persons, Compliance with
Section (16)(a) of the Exchange Act."
The Company also implemented plans to reduce general and administrative
expenses in Houston, Texas as well as move the corporate offices from The
Woodlands, Texas, and reduce its workforce from 76 in October 1995 to 28 in June
1997. The workforce reductions, primarily from the Company's research and
development activities and wireline/logging operations, were consistent with the
Company's focus on conservation of cash and maintenance of existing producing
properties.
The Company experienced further decreases in oil and gas production and
related cash flows in late 1995 and early 1996, which further deteriorated the
Company's already weakened financial condition. At December 31, 1995, the
Company was in default under certain financial covenants of the Credit Facility.
As a result of the declines in oil and gas production and related cash flows,
the Company was not generating, and did not expect to generate in the near term,
sufficient cash flow to meet its existing obligations, including: the $6,900,000
interest payment on the Senior Notes due March 1, 1996, trade payable
obligations remaining from the Company's 1995 capital expenditure program,
quarterly principal and interest due on the Credit Facility, dividends on the
Preferred Stock and ongoing field operating and general and administrative
expenses. As liquidity problems became more severe, the Company concluded that a
comprehensive financial restructuring would provide the best result to the
various stakeholders in the Company.
On February 14, 1996, the Company commenced a voluntary reorganization case
under Chapter 11 of the Bankruptcy Code by filing a voluntary petition for
bankruptcy relief with the Bankruptcy Court (Case No. 96BK-50212). Upon the
filing of the voluntary petition for relief, the Company, as
debtor-in-possession, was authorized to operate its business for the benefit of
claim holders and interest holders, and continued to do so without objection or
request for appointment of a trustee. All debts of the Company as of the
Petition Date were stayed by the bankruptcy petition and were subject to
compromise pursuant to such proceedings. The Company did not make the March 1,
1996 interest payment on the Senior Notes and pursuant to an order of the
Bankruptcy Court did not make the scheduled interest payment of $381,000 to INCC
on February 28, 1996, nor did it make any interest payments from that date on
the Credit Facility through July of 1997. In addition, the Company did not make
the first scheduled payment of $938,000 due on the Credit Facility March 31,
1996, nor did it make any principal payments from that date through July of
1997. On July 11, 1997, the Credit Facility was paid in full, pursuant to the
Plan of Reorganization. The Company was required to obtain court approval for
transactions outside the ordinary course of business.
On October 22, 1996, the Company accepted and signed the proposal ("DLBW
Proposal") submitted by DLB and Wexford, on behalf of its affiliated investment
funds, providing the terms of a proposed capital investment in a plan of
reorganization for the Company. DLB and Wexford are together referred to herein
as DLBW. The Company subsequently obtained Bankruptcy Court approval of the
expense reimbursement provisions of the DLBW Proposal.
Subsequent to the Company's execution of the DLBW Proposal, DLB commenced
negotiations with Texaco Exploration and Production, Inc. ("TEPI") regarding,
(i) the claim asserted by TEPI against the Company and its affiliates ("Texaco
Claim"), (ii) the purchase of certain interests owned by TEPI in the West Cote
Blanche Bay Field ("WCBB Assets") and (iii) the Contract Area Operating
Agreement related to the WCBB Assets and various other agreements relating
thereto. As a result of the negotiations, on March 11, 1997 TEPI and DLB entered
into, among other agreements, the Purchase, Sale and Cooperation Agreement
("PS&C Agreement") pursuant to which DLB (i) agreed to purchase the Texaco
Claim, (ii) agreed to purchase the WCBB Assets from TEPI, and (iii) agreed to
guarantee ("P&A Guarantee") the performance of all plugging and abandonment
obligations related to both the WCBB Assets and the Company's interests in West
Cote Blanche Bay Field ("WCBB") and, in order to implement the P&A Guarantee,
the Company paid
5
<PAGE> 6
into a trust ("P&A Trust") established for the benefit of the State of
Louisiana, $1,000,000 on the Effective Date of the Plan.
Pursuant to the PS&C Agreement, on the Effective Date of the Plan, DLB
among other things, assigned its rights associated with the WCBB Assets to New
WRT, and as a result, New WRT assumed jointly and severally with DLB, the
liabilities with respect to the WCBB Assets.
By order dated May 2, 1997, the Bankruptcy Court approved the Plan. The
Plan involved (i) the issuance to WRT's unsecured creditors, on account of their
allowed claims, an aggregate of 10 million shares of New WRT Common Stock, (ii)
the issuance to WRT's unsecured creditors, on account of their allowed claims,
the right to purchase an additional three million eight hundred thousand shares
(3,800,000) of New WRT Common Stock at a purchase price of $3.50 per share
("Rights Offering"), (iii) the issuance to DLBW and affiliates of the number of
shares of New WRT Common Stock obtained by dividing DLBW's Allowed Secured Claim
("Secured Claim") amount by a conversion price of $3.50 per share, (iv) the
purchase by DLBW of all shares of New WRT Common Stock not otherwise purchased
pursuant to the Rights Offering, (v) the transfer by DLB of the WCBB Assets to
the Company along with the associated P&A Trust and associated funding
obligation in exchange for five million shares (5,000,000) of New WRT Common
Stock, (vi) the funding by WRT of $3,000,000 to an entity (the "Litigation
Entity") to be controlled by an independent party for the benefit of most of the
Company's existing unsecured creditors. WRT transferred to the Litigation Entity
any and all causes of action, claims, rights of actions, suits or proceedings
which have been or could be asserted by WRT except for (a) the action to recover
unpaid production proceeds payable to WRT by Tri-Deck Oil & Gas Company and (b)
the foreclosure action to recover title to certain assets, (vii) the
distribution of warrants to purchase New WRT Common Stock at an exercise price
of $10.00 per share to holders of certain securities litigation claims against
the Debtor and to holders of the Debtor's Common Stock and preferred stock, and
(viii) the cancellation of the Debtor's common stock and preferred stock.
Pursuant to the Plan, New WRT owns a 12% economic interest in the Litigation
Entity and the remainder of the economic interests in the Litigation Entity were
allocated to unsecured creditors based on their ownership percentage of the
thirteen million eight hundred thousand (13,800,000) shares distributed and
issued as described in (i) and (ii) above. The Plan became effective on July 11,
1997.
Upon the Effective Date of the Plan, New WRT became the owner of one
hundred percent (100%) of the working interest in the shallow contract area at
WCBB. The proceeds from the Rights Offering were utilized to provide the cash
necessary to satisfy Administrative and Priority Claims ("APC"), fund the
Litigation Entity with $3,000,000 and provide New WRT with working capital.
OIL AND GAS PROPERTY ACQUISITIONS
In December 1994, the Company entered into a definitive agreement with LLOG
Exploration Company ("LLOG") for the purchase of LLOG's working interest
(approximately 100%) in the Bayou Penchant Field (the "Initial LLOG Property").
The Company concluded the acquisition of the Initial LLOG Property in late
January 1995 for a purchase price of approximately $15,600,000 plus a $5,000,000
nonrefundable deposit towards the purchase from LLOG of certain additional oil
and gas properties, described below. The approximately $20,600,000 paid to LLOG
was financed by borrowings of $15,000,000 under the Credit Facility, and by the
issuance to LLOG of a short-term, promissory note for approximately $5,600,000
(the "Seller Financing Note"). In early February 1995, the Company refinanced
the Seller Financing Note from the proceeds of a $7,500,000 bridge loan (the
"Bridge Loan") provided by Cargill Financial Services Corporation. The net
proceeds from the Offering were used to repay the $7,500,000 Bridge Loan.
In December 1994, the Company and LLOG also entered into a letter of intent
for the purchase by the Company of a second group of oil and gas properties
owned by LLOG (the "Remaining LLOG Properties"). Separate purchase contracts for
each of the Remaining LLOG Properties were entered into in January 1995. The
Company concluded the acquisition of the Remaining LLOG Properties in early
March 1995 for an aggregate purchase price of approximately $46,400,000, less
the $5,000,000 nonrefundable deposit previously paid to LLOG in connection with
the Company's acquisition of the Initial LLOG Property. The Company
6
<PAGE> 7
paid interest to LLOG on the unpaid balance of the purchase price of the
Remaining LLOG Properties (approximately $41,400,000) at the rate of 8.5% per
annum from the date of the purchase contracts until closing of the acquisitions.
The approximately $41,400,000 paid to LLOG was financed with proceeds from the
Offering.
The Remaining LLOG Properties consist of working interests in four south
Louisiana oil and gas fields: the Bayou Pigeon Field, the Deer Island Field, the
Abbeville Field, and the Golden Meadow Field. The Company owns a 100% working
interest in substantially all acreage comprising the Initial LLOG Property and
the Remaining LLOG Properties, other than the Abbeville Field in which it owns
approximately 70% of the working interest. The Company is the operator of the
Initial LLOG Property and the Remaining LLOG Properties. During 1996, the
Company received notice of a possible title failure on approximately, 43 acres
in the Bayou Pigeon Field. See further discussion in "Item
2 -- Properties -- Title to Oil and Gas Properties."
In January 1995, the Company entered into an agreement in principle with an
affiliate of Benton Oil and Gas Company and two affiliates of Tenneco, Inc. to
purchase an additional 43.75% working interest in the shallow reservoirs (above
the Rob "C" marker located at approximately 10,500 feet) of WCBB, a property in
which the Company then owned a 6.25% working interest. The purchase price for
the additional interest in the WCBB was approximately $20.0 million. The
purchase was completed in April 1995.
In connection with the Plan, DLB executed definitive documentation with
TEPI, an affiliate of Texaco, related to WCBB. The transaction occurred in two
stages, the first of which closed on March 11, 1997. On that date, (i) DLB
acquired the Texaco Claim, (ii) acquired the remaining 50% working interest in
the shallow reservoirs (above the Rob "C" marker located at approximately 10,500
feet) in WCBB, and (iii) assumed certain operational and plugging and
abandonment obligations related to WCBB. At the second closing, which occurred
on July 11, 1997, the Effective Date of the Plan, DLB transferred the WCBB
Assets to New WRT in exchange for five million (5,000,000) shares of New WRT
Common Stock and the assumption by New WRT of certain plugging and abandonment
obligations related to WCBB.
In December 1994, the Company purchased a 100% working interest
(approximately 75% net revenue interest) in leases covering approximately 300
acres in the Napoleonville Field for a purchase price of $9.8 million which was
paid by the issuance of 1,300,000 shares of the Company's common stock.
During 1995, the Company purchased for approximately $1.2 million and
$600,000, respectively, certain additional leasehold acreage in the
Napoleonville Field and saltwater disposal facilities from BSFI Western E&P,
Inc. ("BSFI"). At the time of the purchase, BSFI, as a 5.5% common shareholder
of the Company, was a related party. In connection with the purchase, the
parties also effected the settlement of a potential dispute between BSFI and the
Company related to an assertion by BSFI that the Company allegedly failed to
timely register for resale of the 1,300,000 common shares issued to purchase the
Napoleonville Field.
BUSINESS STRATEGY
As previously discussed, until the fourth quarter of 1995, the Company's
stated business strategy was the acquisition of operated working interests in
large, mature oil and gas fields in south Louisiana and the development of such
properties utilizing its technology and its experience along the Louisiana Gulf
Coast. The Company sought to utilize current technologies to take advantage of
certain characteristics common to most of the principal oil and gas fields on
the Louisiana Gulf Coast, including their complex geology, the presence of large
numbers of shut-in wells, the presence of potentially productive bypassed
geological zones in these mature fields, and excessive water production from
producing wells.
The Company continued to evaluate potential oil and gas properties which
met its specific acquisition criteria until liquidity concerns and availability
of capital forced the Company to reevaluate its acquisition program. During the
fourth quarter of 1995, the Company suspended its property acquisition,
development and workover activities and while in bankruptcy operated as a
debtor-in-possession, performing only those workovers approved by the Bankruptcy
Court.
The Company's business strategy going forward is to exploit its existing
properties and acquire additional Louisiana Gulf Coast properties with
exploitation and exploration potential.
7
<PAGE> 8
Technology
Prior to its change in strategy, the Company utilized its technology and
experience along the Louisiana Gulf Coast in acquiring and operating mature,
underproduced properties in the region. The Company's principal areas of
technical expertise were well logging and interpretation, fluid separation and
its computerized database on approximately 100,000 wells.
The Company continued the development of its technologies during 1995,
primarily in the area of logging tool development. The Company contracted for
the construction of four logging tools during 1995, two of which were completed
in 1995 and two of which were completed in 1996. The Company has maintained its
wireline and logging assets; however, as discussed previously, the Company's
reduction in workforce included substantially all of the employees involved in
the wireline and logging operations. In November 1995 as part of the corporate
restructuring, the Company formed a new wholly-owned subsidiary, WRT
Technologies, Inc. allowing the Company to segregate into two lines of business,
one containing the existing oil and gas assets and the other containing the
technology based assets, including wireline and logging and fluid separation
assets. As part of the Plan, WRT Technologies was dissolved into WRT.
The Company plans to use certain of its logging tool technology in
developing its existing properties in accordance with its Plan of
Reorganization.
COMPETITION AND MARKETS
Availability of Markets. The availability of a ready market for any oil
and/or gas produced by the Company depends on numerous factors beyond the
control of management, including but not limited to, the extent of domestic
production and imports of oil, the proximity and capacity of gas pipelines, the
availability of skilled labor, materials and equipment, the effect of state and
federal regulation of oil and gas production and federal regulation of gas sold
in interstate commerce. Gas produced by the Company in Louisiana is sold to
various purchasers who service the areas where the Company's wells are located.
The Company's wells are not subject to any agreements that would prevent the
Company from either selling its gas production on the spot market or committing
such gas to a long-term contract; however, there can be no assurance that the
Company will continue to have ready access to suitable markets for its future
oil and gas production.
Impact of Energy Price Changes. Oil and gas prices can be extremely
volatile and are subject to substantial seasonal, political and other
fluctuations. The prices at which oil and gas produced by the Company may be
sold is uncertain and it is possible that under some market conditions the
production and sale of oil and gas from some or all of the Company's properties
may not be economical. The availability of a ready market for oil and gas and
the prices obtained for such oil and gas, depend upon numerous factors beyond
the control of the Company, including competition from other oil and gas
suppliers and national and international economic and political developments.
Because of all of the factors influencing the price of oil and gas, it is
impossible to accurately predict future prices.
REGULATION
Orphaned Well Act. In June 1993, the Louisiana legislature passed the
Louisiana Oilfield Site Restoration Law (the "Orphaned Well Act") which provides
that if an oil field site is transferred from one party to another, the parties
to the transfer may elect to establish a trust account for such site to provide
a source of funds for future site restoration. A primary advantage of this law
is that, once the site-specific trust account has been approved by the Secretary
of the Louisiana Department of Natural Resources (the "DNR"), the party
transferring the oil field site is relieved of liability by the state for any
site restoration costs or actions associated with the site. Management believes
that this makes the Company and others who are willing to use this law more
competitive as purchasers of oil and gas properties. If the parties to a
transfer elect to be covered under the Orphaned Well Act, the Secretary of the
DNR will require that a site assessment be performed by a contractor approved by
the special state commission created under the statute and will require the
parties to the transaction to provide a proposed funding schedule for the trust
account. The site assessment must specifically identify site restoration costs
needed to restore the oil field site based on conditions existing at the time of
the transfer. Generally, some contribution to the trust account will be
8
<PAGE> 9
required at the time of the transfer and additional funding will be required
quarterly thereafter until the account is fully funded. The trust account is
monitored by the DNR and the funds in the trust accounts remain the property of
the DNR. The purchaser of the oil field site is liable for site restoration at
the end of its useful life. If the purchaser restores the site, the purchaser
will be entitled to recover the balance of the trust account. Compliance with
such law does not, however, relieve the parties to the transaction from
liability to private parties.
The Company is contractually committed in its purchase contracts for the
Initial LLOG Property and Remaining LLOG Properties to establish plugging and
abandonment escrow funds as allowed by Louisiana's Orphaned Well Act. In
connection with its bankruptcy case, LLOG filed a claim asserting, inter alia,
that the Debtor was required, notwithstanding the bankruptcy case, to fulfill
its contractual commitment to establish plugging and abandonment funds (the
"Asserted LLOG P&A Trusts"), and that LLOG had a vendor's lien on the Initial
LLOG Property and Remaining LLOG Properties securing the Debtor's performance of
the contractual commitment. The Debtor disputed LLOG's claim and its asserted
vendor's lien, and filed an objection seeking a disallowance of LLOG's claim and
a determination that any claim asserted by LLOG with respect to the Asserted
LLOG P&A Trusts was unsecured. On July 8, 1997, the Bankruptcy Court ruled that
LLOG's claim with respect to the Asserted LLOG P&A Trusts was secured by a valid
vendor's lien on the Initial LLOG Property and Remaining LLOG Properties, but
did not determine the amount of such claim. The Debtor has filed a motion
requesting that the Bankruptcy Court reconsider its ruling. A hearing on the
Debtor's motion is currently scheduled for November 25, 1997. Should the Debtor
be unsuccessful in its defense of LLOG's claim with respect to the Asserted LLOG
P&A Trusts, New WRT will be required to establish plugging and abandonment
funds. The amount of and terms of payment into each fund will be established by
the State of Louisiana upon completion of an independent study to be
commissioned by the Company. As of December 31, 1996, and as of the date of this
report, the independent study had not been completed. Accordingly, the Company
is unable to determine the amount and payment towards the future obligation
related to these commitments.
Environmental Regulation. Operations of the Company are subject to numerous
federal, state, and local laws and regulations governing the discharge of
materials into the environment or otherwise relating to environmental
protection. These laws and regulations may require the acquisition of a permit
before drilling commences, restrict or prohibit the types, quantities and
concentration of substances that can be released into the environment in
connection with drilling and production activities, prohibit drilling activities
on certain lands lying within wetlands or other protected areas and impose
substantial liabilities for pollution resulting from drilling and production
operations. Moreover, state and federal environmental laws and regulations may
become more stringent. These environmental laws and regulations may affect the
Company's operations and costs as a result of their effect on oil and gas
development, exploration, and production operations. For instance, legislation
has been proposed in Congress from time to time that would amend the federal
Resource Conservation and Recovery Act of 1976 ("RCRA") to reclassify oil and
gas production wastes as "hazardous waste." If such legislation were enacted, it
could have a significant impact on the Company's operating costs, as well as the
oil and gas industry in general. It is not anticipated that the Company will be
required in the near future to expend amounts that are material in relation to
its total capital expenditures program by reason of environmental laws and
regulations, but inasmuch as such laws and regulations are frequently changed
the Company is unable to predict the ultimate cost of compliance. In addition,
The Comprehensive Environmental Response, Compensation and Liability Act of 1980
("CERCLA" or "Superfund") and certain state laws and regulations impose
liability for cleanup of waste sites and in some cases attorney's fees,
exemplary damages and/or trebling of damages.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose
a variety of regulations on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of a facility or
vessel, or the lessee or permittee of the area in which an offshore facility is
located. The OPA assigns liability to each responsible party for oil removal
costs and a variety of public and private damages. While liability limits apply
in some circumstances, a party cannot take advantage of liability limits if the
spill was caused by gross negligence or willful misconduct or resulted from
violation of a federal safety, construction or operating
9
<PAGE> 10
regulation. If the party fails to report a spill or to cooperate fully in the
cleanup, liability limits do not apply. Few defenses exist to the liability
imposed by the OPA. The OPA also imposes ongoing requirements on a responsible
party, including proof by owners and operators of offshore oil and gas
facilities of establishment of $150,000,000 in financial responsibility.
Financial responsibility could be established by various means including
insurance, guarantee, surety bond, letter of credit or qualification as a
self-insurer. There is substantial uncertainty as to whether insurance companies
or underwriters will be willing to provide coverage under the OPA. The financial
tests or other criteria that will be used to judge self-insurance are also
uncertain. The Company cannot predict the final resolution of these financial
responsibility issues but such requirements have the potential to result in the
imposition of substantial additional annual costs on the Company or otherwise
materially adversely affect the Company. The impact of the rule should not be
any more adverse to the Company than it will be to the other similarly situated
or less well capitalized owners or operators. See "Operational Hazards and
Insurance".
The Clean Water Act, together with the related National Pollution Discharge
Elimination System ("NPDES"), and similar state environmental laws are expected
to prohibit oil and gas producers from discharging produced water overboard into
waters of the U.S. shoreward of the territorial seas ("Coastal Waters") within
one year or less. The Company is currently discharging produced water overboard
at its Tigre Lagoon facility in Louisiana. In June 1995, the Company began
underground injection at its East Hackberry facility and discontinued overboard
discharge. The Company received the final permit (WP #4831) from the Louisiana
Department of Environmental Quality ("LDEQ") on February 18, 1995 in connection
with its Tigre Lagoon facility. The final permit expired on December 31, 1996.
In addition, the Company has filed and obtained a NPDES permit with the
Environmental Protection Agency ("EPA") for coverage of the applicable Company
Coastal Waters facilities under the EPA general permit relating to discharge of
produced water.
Radioactive Materials Licensing. The Company is licensed, regulated and
subject to inspection by the LDEQ with respect to the ownership and operation of
its radioactive well logging tools. Failure to comply with such licensing and
regulatory requirements could cause the Company to lose its rights to operate
its well logging tools. The Company's radioactive well logging tools require the
use of radioactive materials and explosives which may result in substantial
losses or liabilities to third parties, including claims for bodily injuries,
reservoir damage, loss of reserves, environmental damage and other damages to
persons or property. See "Operational Hazards and Insurance" below.
Federal and State Regulation. Complex regulations concerning all phases of
energy development at the local, state and federal levels apply to the Company's
operations and often require interpretation by the Company's professional staff
or outside advisors. The federal government and various state governments have
adopted numerous laws and regulations respecting the production, transportation,
marketing and sale of oil and gas. Regulation by state and local governments
usually covers matters such as the spacing of wells, allowable production rates,
pooling and unitization, environmental protection, pollution control, pricing,
taxation and other related matters. In Louisiana, the Commissioner of the Office
of Conservation is empowered to create geographic or geological units for
drilling and producing wells which units contain, in the Commissioner's sole
judgement, the production acreage likely to be efficiently and economically
drained by such well. These units are created only after notice to interested
parties and a hearing at which time the Commissioner will accept geological and
engineering testimony from the interested parties. The creation of these units
could have the result of combining the Company's leasehold interest with lease
acreage held by competing producers and could have the effect of reducing the
Company's interest in a drilling or producing well below the leasehold interest
to which the Company would otherwise be entitled. Unitization of the Company's
properties may force the Company to share production from its wells and leases
with others and can occur after development or acquisition costs have been
incurred by the Company. If the Company's leases are subjected to unitization,
the Company may ultimately be entitled to a lesser share of production from its
wells than it expected. Any federal leases acquired by the Company will be
subject to various federal statutes and the rules and regulations of federal
administrative agencies. Moreover, future changes in local, state or federal
laws and regulations could adversely affect the operations of the Company.
10
<PAGE> 11
Legislation affecting the oil and gas industry is under constant review for
amendment or expansion, frequently increasing the regulatory burden. Numerous
departments and agencies, both federal and state are also authorized by statute
to issue, and have issued, rules and regulations binding the oil and gas
industry that often are costly to comply with and that carry substantial
penalties for non-compliance. In addition, production operations are affected by
changing tax and other laws relating to the petroleum industry, by constantly
changing administrative regulations and possible interruption or termination by
government authorities.
The Federal Energy Regulatory Commission (the "FERC") regulates the
transportation and sale for resale of natural gas in interstate commerce
pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy
Act of 1978 (the "NGPA"). In the past, the federal government has regulated the
prices at which oil and gas could be sold. Currently, sales by producers of
natural gas, and all sales of crude oil, condensate and natural gas liquids can
be made at uncontrolled market prices, but Congress could reenact price controls
at any time.
The Company's natural gas gathering operations may be or become subject to
safety and operational regulations relating to the design, installation,
testing, construction, operation, replacement, and management of facilities.
Pipeline safety issues have recently become the subject of increasing focus in
various political and administrative arenas at both the state and federal
levels. The Company cannot predict what effect, if any, the adoption of
additional pipeline safety legislation might have on its operations, but does
not believe that any adverse effect would be material.
Proposals and proceedings that might affect the oil and gas industry are
routinely pending before the Congress, FERC, and the courts. The Company cannot
predict when or whether any such proposals may become effective. In the past,
the natural gas industry has been very heavily regulated. There is no assurance
that the current regulatory approach pursued by the FERC will continue
indefinitely into the future.
Notwithstanding the foregoing, it is not anticipated that compliance with
existing federal, state and local laws, rules and regulations will have a
material adverse effect upon the capital expenditures, earnings or competitive
position of the Company.
OPERATIONAL HAZARDS AND INSURANCE
The Company's operations are subject to all of the risks normally incident
to the production of oil and gas, including blowouts, cratering, pipe failure,
casing collapse, oil spills and fires, each of which could result in severe
damage to or destruction of oil and gas wells, production facilities or other
property, or injury to persons. The energy business is also subject to
environmental hazards, such as oil spills, gas leaks, and ruptures and discharge
of toxic substances or gases that could expose the Company to substantial
liability due to pollution and other environmental damage. Although the Company
maintains insurance coverage considered to be customary in the industry, it is
not fully insured against certain of these risks, either because such insurance
is not available or because of high premium costs. The occurrence of a
significant event that is not fully insured against could have a material
adverse effect on the Company's financial position.
EMPLOYEES
At December 31, 1996, the Company employed 29 persons, including 3
executives. At November 14, 1997, the Company employed 25 persons, including 1
executive. None of the Company's employees are represented by labor unions or
covered by any collective bargaining arrangement. The Company considers its
relations with its employees to be satisfactory.
ITEM 2. PROPERTIES
PRINCIPAL OIL AND GAS PROPERTIES
The Company owns interests in a number of producing oil and gas properties
located along the Louisiana Gulf Coast. At December 31, 1996, the Company served
as the operator of all properties in which it held an interest except for WCBB.
See "Principal Oil and Gas Properties -- West Cote Blanche Bay" for 1997
11
<PAGE> 12
activity. See description of WCBB and 1997 activity in field descriptions
following this table. The following table presents certain information as of
December 31, 1996 respecting the Company's net interest in its producing oil and
gas properties, including those held through joint ventures.
<TABLE>
<CAPTION>
PRODUCING SHUT-IN PROVED RESERVES(2)
WELLS WELLS ACREAGE --------------------------
------------ ------------- --------------- GAS OIL TOTAL
PROPERTY(1) GROSS NET GROSS NET GROSS NET (MMCF) (MBBLS) (MMCFE)
----------- ----- ---- ----- ----- ------ ------ ------ ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Abbeville Field............. 2 1.4 0 0.0 60 42 249 3 267
Bayou Penchant Field........ 7 7.0 5 5.0 1,360 1,360 5,767 25 5,917
Bayou Pigeon Field.......... 11 9.9 2 2.0 1,490 1,490 831 317 2,733
Deer Island Field........... 6 5.4 0 0.0 412 412 3,541 171 4,567
East Hackberry Field........ 22 11.8 63 32.8 3,582 1,791 2,230 1,661 12,206
Golden Meadow Field......... 1 1.0 0 0.0 171 171 1,063 29 1,237
Lac Blanc Field............. 3 0.2 6 4.0 4,841 2,887 90 0 90
Napoleonville Field......... 3 3.0 2 2.0 278 278 137 326 2,093
West Hackberry Field........ 7 7.0 18 18.0 592 592 0 31 186
West Cote Blanche Bay....... 56 26.0 336 168.0 5,892 2,946 1,213 11,360 69,373
Other Wells................. 2 0.7 8 4.3 1,559 522 0 0 0
--- ---- --- ----- ------ ------ ------ ------ ------
Total at year
end............. 120 73.4 440 236.1 20,237 12,491 15,121 13,923 98,669
--- ---- --- ----- ------ ------ ------ ------ ------
</TABLE>
- ---------------
(1) Substantially all properties are located in south Louisiana.
(2) Represents proved reserves attributable to properties as estimated by
independent petroleum engineers. See Note 20 to "Notes to Consolidated
Financial Statements."
Abbeville Field. The Abbeville Field, purchased in March 1995 and situated
on dry land near Abbeville in Vermillion Parish, Louisiana, was first discovered
by Continental Oil Company ("Conoco") in 1939. The Company acquired
approximately 70% of the working interest before payout (approximately 67% after
payout) with an average net revenue interest ("NRI") of approximately 54% before
payout (51% after payout) in approximately 60 gross acres, in the field. The
three tracts acquired contain varying depth limitations. In one tract the
Company acquired only the rights below 9,550 feet. Another tract is limited to
depths from the surface down to 13,000 feet. The third tract contains both
leases without depth limitations and leases with depth limited from the surface
down to 13,000 feet. The two wells in the Abbeville Field produce primarily gas.
During 1995, the Company successfully recompleted one gas well in the Abbeville
Field. During 1996, both of the wells were recompleted to new producing horizons
but one of the wells produced only a minimal amount of gas before depleting.
Bayou Penchant. The Bayou Penchant Field, purchased in January 1995,
consists of approximately 1,360 gross acres of leases, and includes nine
producing wells, three shut-in wells and one salt water disposal well in
Terrebonne Parish, Louisiana. The Company's working interest is 100%
(approximately 86% average NRI) in all but one well, the CL&F No 7 well in which
the Company's working interest is approximately 70% (59% NRI). The Bayou
Penchant Field is located in a marshy area with existing dredged canals and
produces primarily gas from multiple productive zones, ranging in depth from
2,400 to 10,400 feet. During 1995, there were eight successful gas zone
recompletion attempts in the Bayou Penchant Field and no failures. In addition,
two development wells were drilled, one resulting in a dry hole and the other
successfully completed as a producing gas well. During 1996, two wells were the
subject of unsuccessful recompletion attempts. Both of these operations involved
the use of relatively low cost "through-tubing" techniques utilizing wireline
equipment to perform the operations. A third well was also targeted for the use
of similar procedures but the intended operations were aborted when it was
discovered that the well's production tubing was damaged.
Bayou Pigeon Field. The Bayou Pigeon Field, purchased in March 1995,
consists of approximately 1,490 gross acres located in the marshy coastal waters
on both sides of Little Bayou Pigeon in Iberia Parish, Louisiana. The Company
has a 100% working interest in thirteen wells (eleven producing and two shut in
wells, approximately 80% average NRI). The Company initially believed they owned
a 100% working interest in three additional wells in the Bayou Pigeon Field;
however, subsequent to December 31, 1995, the Company
12
<PAGE> 13
received notice from a third party claiming that the Company's title has failed
as to approximately 43 acres. If it is ultimately determined that the Company's
title has failed, the Company's working interest in these three wells would be
reduced to approximately 7% (5% NRI), 75% (63% NRI) and 95% (72% NRI),
respectively. The Company's financial statements as of and for the years ended
December 31, 1995 and 1996 reflect operating results and proved reserves for the
reduced working and net revenue interests. As the title failure predates its
ownership of the field, the Company is currently evaluating its recourse against
the predecessors-in-title relative to this issue. Production from the Bayou
Pigeon Field is predominately oil from multiple productive zones at depths
ranging from 6,900 to 12,000 feet. During 1995, three successful gas zone and
three successful oil zone recompletions were performed in the Bayou Pigeon Field
with one attempt being unsuccessful. One new development well was successfully
drilled for previously untapped reserves and completed as a producing oil well.
During 1996, one well was successfully recompleted.
Deer Island Field. The Deer Island Field, purchased in March 1995, is
located in marshy, inland waters in Terrebonne Parish, Louisiana and is accessed
by workboat through dredged canals. The Company acquired a 100% working interest
(approximately 73% NRI before payout and 66% thereafter) in approximately 412
acres comprised of two non-contiguous lease blocks in the Deer Island Field.
Current production from the southern lease block is primarily gas from multiple
producing zones at depths ranging from 8,200 to 10,200 feet. The two wells in
the northern lease block produce from an oil sand at a depth of approximately
10,350 feet. The interests in both tracts were originally acquired through two
separate subleases from Exxon. In the southern lease block, the interest is
composed of three tracts with varying depth limitations, with the greatest depth
being approximately 10,500 feet. Exxon retained the rights below 10,500 feet and
Exxon or other producers own the rights to the other outstanding depths. In the
northern lease block, the interest is limited to depths between the surface and
10,720 feet. During 1996, LLOG Exploration Company completed a new well into a
unit in which the Company holds an interest. Although not yet approved by the
State of Louisiana, the Company expects to ultimately hold a minimum working
interest of approximately 38.9% (34% NRI) of production from this unit.
East Hackberry Field. In February 1994, the Company purchased a 100%
working interest (approximately 82% average NRI) in certain producing oil and
gas properties situated in the East Hackberry Field in Cameron Parish,
Louisiana. The purchase included two separate lease blocks, the Erwin Heirs
Block, originally developed by Gulf Oil Company and the Texaco State Lease
("S/L") 50 Block, originally developed by Texaco, Inc. The East Hackberry Field
is located along the western shore of Lake Calcasico in Cameron Parish,
Louisiana approximately 80 miles west of Lafayette and 15 miles inland from the
Gulf of Mexico. The properties cover approximately 3,582 acres of oil and gas
leases, together with 22 productive wells and 63 shut-in wells that were
originally drilled by Gulf Oil Company and Texaco.
In September 1994, the Company sold an overriding royalty interest in
certain producing oil and gas wells situated in the East Hackberry Field to
Milam Royalty Corporation ("Milam"). On an aggregate basis the overriding
royalty interests provide for payment to Milam of 62.5% of 80% (equal to 50% on
a 100% working interest basis) of the net profits attributable to the wells
covered by the arrangement until Milam recovers 150% of its cash investment and
46.875% of 80% thereafter (equal to 37.5% on a 100% working interest basis).
Related agreements further provide that for an additional royalty purchase price
based on the then effective percentage described in the two preceding sentences
of the Company's future cost of drilling new wells or recompleting existing
wells in new reservoirs (and subject to certain limitations stated in such
agreements), Milam may elect to retain an identical royalty interest in the new
wells. The Company retains complete operational control over the East Hackberry
Field. During 1995, the Company made 20 successful oil zone recompletions and
one successful gas zone recompletion. Seven such recompletion attempts proved to
be unsuccessful. In addition, the Company attempted three sidetracks, two of
which were completed successfully as oil wells and one of which missed the
geological objective resulting in a dry hole. During 1996, three wells were
successfully recompleted. Additionally, operations were conducted to convert six
wells in this field to gas-lift. Two wells were the subject of unsuccessful
recompletion attempts.
Golden Meadow Field. The Golden Meadow Field, purchased in March 1995, is
located in marshy, inland waters in Lafourche Parish, Louisiana and was
discovered by Texaco in 1961. The portion of the Golden Meadow Field in which
the Company owns a 100% working interest (approximately 79% average
13
<PAGE> 14
NRI) covers approximately 171 acres. The Golden Meadow Field is presently
producing from a gas bearing sand at a depth of approximately 12,500 feet.
During 1996, the sole producing well in Golden Meadow was reworked to repair a
downhole mechanical failure. This work was successful and the well was restored
to production.
Lac Blanc Field. The Lac Blanc Field, purchased in July 1993, consists of
4,841 gross acres and underlies a marsh and shoreline near the community of
Pecan Island in Vermilion Parish, Louisiana and was first discovered in 1975.
The Company purchased a 91% average working interest (55% average NRI) in
acreage within the Lac Blanc Field from an affiliate of Freeport-McMoRan, Inc.
The sellers retained a 20% back-in working interest in any new wells drilled in
previously undeveloped fault blocks. The field has produced approximately 150
Bcf of gas and 1.1 MMBbls of oil since its discovery, but in recent years it has
experienced substantial production declines, which were accompanied by
substantial increases in water production rates. Three unsuccessful attempts
were made during 1995 to restore production to this field and compensate for the
reduced gas volumes caused by the unexpected onset of water production. Two
workover attempts were made in the Exxon Fee No. 23 well. A split in the casing
ultimately resulted in the loss of future utility in the well. During 1996, one
"through-tubing" recompletion was attempted but this operation was aborted due
to encountered obstructions in the well's production tubing.
In connection with the purchase of the Lac Blanc Field, the Company
established a plugging and abandonment escrow arrangement. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Commitments and Contingencies."
Napoleonville Field. In December 1994, the Company purchased from BSFI
Western E&P, Inc. ("BSFI") a 100% working interest (approximately 75% average
NRI) in approximately 300 acres of leases within the Napoleonville Field. Three
producing wells, two shut-in wells and one saltwater disposal well are located
within the Company's lease acreage. The Napoleonville Field is located in
Assumption Parish, Louisiana on dry land and produces primarily oil from
multiple pay zones which range in depth from 9,500 to 10,000 feet. The Company's
interest in the Napoleonville Field was purchased in exchange for the issuance
of 1,300,000 shares of its Common Stock. During 1995, three unsuccessful
attempts were made to recomplete two shut-in wells in this field.
During 1995, the Company purchased for approximately $1,200,000 and
$600,000, respectively, certain additional leasehold acreage in the
Napoleonville Field and saltwater disposal facilities from BSFI. At the time of
the purchase, BSFI, as a 5.5% shareholder of the Company, was a related party.
See "Certain Relationships and Related Transactions."
West Hackberry Field. In November 1992, the Company purchased a 100%
working interest (approximately 80% average NRI) in acreage within the West
Hackberry Field, in Cameron Parish, Louisiana. The field was discovered in 1928
and was developed by Superior Oil Company (now Mobil) between 1938 and 1988. In
connection with its purchase of the East Hackberry Field properties, the Company
purchased a 7.5% overriding royalty interest in its West Hackberry Field that
was previously retained by the original seller of the property. As a result, the
Company's net revenue interest in the West Hackberry Field increased from
approximately 80% to approximately 87.5%, effective March 1, 1994.
West Cote Blanche Bay Field. TEPI, the operator of WCBB prior to March
1997, discovered the WCBB field in 1938. This field lies approximately five
miles off the coast of Louisiana in St. Mary Parish in a shallow bay, with water
depths averaging seven to eight feet, and overlies one of the largest salt dome
structures on the Gulf Coast. The Company acquired from TEPI a 6.25% working
interest in the WCBB in July 1988. In April 1995, the Company completed the
purchase of an additional 43.75% working interest in WCBB from an affiliate of
Benton Oil and Gas Company and two affiliates of Tenneco, Inc. The sellers
retained their interests in all depths below approximately 10,500 feet. Pursuant
to the Plan, at the Effective Date, the Company acquired the remaining 50%
working interest in WCBB in depths above the Rob "C" marker located at
approximately 10,500 feet and became the operator of the field. During 1995, ten
successful oil and three successful gas recompletions were made with two
additional attempts being unsuccessful. Additionally, five new development oil
wells and one new development gas well were drilled. One development well was
unsuccessful. These success ratios are consistent with the Company's past
experience in WCBB. During 1996,
14
<PAGE> 15
nine successful oil recompletions and one successful gas recompletion were made
with two attempts unsuccessful. One unsuccessful shallow attempt was also made.
During 1997, the Company has successfully completed nine workovers and two new
wells. Average production for the month of October was 1,354 BOPD, and recently
reached a peak rate of 1,755 BOPD on October 6, 1997. The Company's engineers
estimate total proved reserves from these eleven projects at approximately 1.0
MMBOE.
ACREAGE
The following table sets forth the Company's developed acreage at December
31, 1996. The Company did not own any undeveloped acreage at December 31, 1996.
<TABLE>
<CAPTION>
DEVELOPED ACREAGE(1)
---------------------
GROSS NET
-------- --------
<S> <C> <C>
Louisiana Onshore and State Waters.......................... 19,856 12,396
Texas Onshore............................................... 381 95
------ ------
Total............................................. 20,237 12,491
====== ======
</TABLE>
- ---------------
(1) Developed acreage is acreage assigned to producing wells for the spacing
unit of the producing formation. Developed acreage in certain of the
Company's properties that include multiple formations with different well
spacing requirements may be considered undeveloped for certain formations
but have only been included as developed acreage in the presentation above.
Certain acreage is subject to depth limitations.
The oil and gas leases in which the Company has an interest are for varying
primary terms and may require the payment of delay rentals to continue the
primary terms. The leases may be surrendered by the operator at any time by
notice to the lessors, by the cessation of production or by failure to make
timely payment of delay rentals. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Commitments and
Contingencies -- Texaco Global Settlement."
DRILLING AND RECOMPLETION ACTIVITIES
The following table contains data with respect to certain of the Company's
field operations during the years ended December 31, 1996, 1995 and 1994. The
Company drilled no exploratory wells during the periods presented.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1996 1995 1994
------------ ------------ ------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Recompletions, Side-Tracks and Deepenings
Oil.......................................... 12 5.7 35 19.5 23 9.9
Gas.......................................... 5 3.2 17 12.7 5 3.2
Non-Productive............................... 7 4.7 18 13.1 8 6.7
-- ---- -- ---- -- ----
Total................................ 24 13.6 70 45.3 36 19.8
== ==== == ==== == ====
Development Wells
Oil.......................................... 0 0 6 3.5 1 1
Gas.......................................... 0 0 2 1.1 1 0.1
Non-Productive............................... 1 0.5 2 1.1 0 0
-- ---- -- ---- -- ----
Total................................ 1 0.5 10 5.7 2 1.1
== ==== == ==== == ====
</TABLE>
TITLE TO OIL AND GAS PROPERTIES
It is customary in the oil and gas industry to make only a cursory review
of title to undeveloped oil and gas leases at the time they are acquired and to
obtain more extensive title examinations when acquiring producing properties.
However, with respect to future undeveloped leasehold and producing property
acquisitions, if any, the Company will conduct title examinations on material
portions of such properties in a
15
<PAGE> 16
manner generally consistent with industry practice. Certain of the Company's oil
and gas properties may be subject to title defects, encumbrances, easements,
servitudes or other restrictions, none of which, except as noted below, in
management's opinion, will in the aggregate materially restrict the Company's
operations.
During 1996, the Company received notice that a third party is claiming
that the Company's title has failed with respect to approximately 43 acres in
the Bayou Pigeon Field. Some or all of the acreage in dispute is considered to
be productive in three separate production units. Under the assumption that the
Company's title is flawed, the Company's working interest in three units may be
reduced from 100% of each unit to approximately 7% (5% NRI), 74% (63% NRI), and
95% (72% NRI). Financial statements as of and for the years ended December 31,
1996 and 1995, reflect operating results and proved reserves discounted for this
possible failure. As the title failure predates its ownership of the field, the
Company is currently evaluating its recourse against the predecessors-in-title
relative to this issue. The Company is currently negotiating a settlement with
the third party pursuant to their claim.
RESERVES
The oil and gas reserve information set forth below represents only
estimates. Reserve engineering is a subjective process of estimating volumes of
economically recoverable oil and gas that cannot be measured in an exact manner.
The accuracy of any reserve estimate is a function of the quality of available
data and of engineering and geological interpretation. As a result, the
estimates of different engineers often vary. In addition, the results of
drilling, testing and production may justify revisions of such estimates.
Accordingly, reserve estimates often differ from the quantities of oil and gas
that are ultimately recovered. Estimates of economically recoverable oil and gas
and of future net revenues are based on a number of variables and assumptions,
all of which may vary from actual results, including geologic interpretation,
prices, and future production rates and costs. The following table sets forth
estimates of the proved oil and gas reserves of the Company at December 31,
1996, as estimated by the Company's independent petroleum engineers, Netherland,
Sewell & Associates, Inc. ("NSAI"), reduced for the proved reserves attributable
to the possible title failure of approximately 43 acres in the Bayou Pigeon
Field. See "Title to Oil and Gas Properties" above.
<TABLE>
<CAPTION>
1996 1995
--------------------------------- ----------------------------------
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ------- --------- ----------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
Oil(MBbls).................... 9,550 4,373 13,923 10,209 4,418 14,627
Gas........................... 11,687 3,434 15,121 16,663 2,408 19,071
Mmcfe......................... 68,987 29,672 98,659 77,917 28,976 106,893
Year-end present value of
estimated future revenues... $67,527 $31,140 $98,667 $40,798 $10,569 $ 51,967
</TABLE>
Total reserves decreased to approximately 99 billion cubic feet equivalents
("Bcfe") at December 31, 1996, from approximately 107 Bcfe at December 31, 1995.
The 1996 year-end estimates decreased from amounts previously reported due to
production of approximately 7 Bcfe at December 31, 1996, and downward revisions
by NSAI of previous estimates offset by upward revisions attributable to the
general increase in oil and gas prices. The average price received for oil and
gas during the first nine months of 1997 was $20.25 per bbl and $2.52 per Mcf,
respectively.
The estimated future net revenues set forth above were determined by using
reserve quantities of proved reserves and the periods in which they are expected
to be developed and produced based on economic conditions prevailing at December
31, 1996. The estimated future production is priced at December 31, 1996,
without escalation using $26.07 per Bbl and $3.90 per Mcf. Additional
information concerning the Company's oil and gas reserves and disclosure of the
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves (Unaudited) is set forth in the notes to the Company's
consolidated financial statements.
The 1995 year-end reserve estimates prepared by NSAI included significant
downward revisions from previously reported volumes. Total reserves decreased
from approximately 205 billion cubic feet equivalents ("Bcfe"), as previously
reported on a pro forma basis in the Company's 1994 Annual Report after
considering
16
<PAGE> 17
the property acquisitions completed during 1995, to approximately 107 Bcfe at
December 31, 1995. These year-end estimates decreased from amounts previously
reported due to production of approximately 15 Bcfe and significant downward
revisions by NSAI of previous estimates. Approximately 38 Bcfe of these
revisions result from differences in professional opinion between NSAI and the
Company's predecessor independent engineering firms, The Scotia Group,
Huddleston & Co. and Veazey & Associates. These differences, many of which
relate to classification of reserves within the different oil and gas reserve
categories (i.e. proved, probable and possible) are due to the numerous
engineering, geological and operational assumptions that generally are derived
from limited data. Common assumptions, which involve the exercise of subjective
professional judgment, include such matters as the arial extent and average
thickness of a particular reservoir, the average porosity and permeability of
the reservoir, the anticipated future production from existing and future wells,
future development and production costs, and the ultimate hydrocarbon recovery
percentage. Additional downward revisions are attributed to field development
activity and production data during the year. Drilling and recompletion
activities, including the unsuccessful well projects in the Company's East
Hackberry and Bayou Penchant fields resulted in significant reserve losses. The
mechanical failure of the Exxon Fee #23 well and the increased water production
from the field also had a negative effect on the Company's reserves at December
31, 1995. These events, coupled with revised geological interpretation utilizing
recent well performance and reservoir data available, resulted in the further
downward revision of approximately 45 Bcfe.
In compliance with federal law, the Company files annual reports with the
Energy Information Agency of the U S. Department of Energy with respect to its
production of oil and gas during each calendar year and its estimated oil and
gas reserves at the end of each year. The reserve values set forth above and in
the Company's Consolidated Financial Statements attached hereto may vary within
five percent from the estimates previously provided to the Department of Energy
by the Company due to the Company's practice of including in its report to the
U.S. Department of Energy all oil and gas production and reserves attributable
to wells for which the Company serves as operator.
PRODUCTION, PRICES AND COSTS
The Company sells its oil and gas at the wellhead and does not refine
petroleum products. Other than normal production facilities, the Company does
not own an interest in any bulk storage facilities or pipelines. As is customary
in the industry, the Company sells its production in any one area to relatively
few purchasers, including transmission companies that have pipelines near the
Company's producing wells. Gas purchase contracts are generally on a short-term
"spot market" basis and usually contain provisions by which the prices and
delivery quantities for future deliveries will be determined. The majority of
the Company's crude oil production is sold on 30-day "evergreen" contracts with
prices based on postings plus a premium. The following table contains certain
historical data respecting the average sales prices received and the average
production costs incurred by the Company during the years ended December 31,
1996, 1995 and 1994.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1996 1995 1994
------ ------- ------
<S> <C> <C> <C>
Production Volumes
Oil (MBbls)............................................ 615 778 270
Gas (MMcf)............................................. 3,629 7,403 3,503
Gas equivalents (MMcfe)................................ 7,319 12,071 5,123
Average Prices
Oil (per Bbl).......................................... $22.17 $ 16.59 $16.44
Gas (per Mcf).......................................... $ 2.86 $ 1.59 $ 1.88
Gas equivalents (per Mcfe)............................. $ 3.28 $ 2.04 $ 2.15
Average production costs (per Mcfe)...................... $ 1.82 $ 0.79 $ 0.60
Average production taxes (per Mcfe)...................... $ 0.24 $ 0.18 $ 0.16
</TABLE>
17
<PAGE> 18
Percentages of revenues from oil and gas sales to specific customers
representing 10% or more of annual oil and gas revenues are recapped below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1996 1995 1994
---- ---- ----
<S> <C> <C> <C>
Texas-Ohio Gas, Inc...................................... N/A 13% 52%
Plains Marketing and Transportation...................... 39% 19% N/A
Riverside Pipeline Company............................... N/A 15% N/A
Tri-Deck Oil and Gas Company............................. 26% 32% N/A
Prior Energy............................................. 15% N/A N/A
</TABLE>
FACILITIES AND EQUIPMENT
As part of management's plans to reduce operating costs and overhead, in
March 1996 the Company relocated its principal offices to Lafayette, Louisiana,
occupying approximately 12,000 square feet of leased premises. In February 1996,
the Company moved its corporate office from The Woodlands, Texas, where it
occupied approximately 24,000 square feet, to Houston, Texas, where it occupied
approximately 7,000 square feet of leased space until June 24, 1997 at which
time the Houston office was closed. In connection with the Reorganization Case,
the Court approved the Company's rejection of the office lease in The Woodlands,
Texas. Rentals under such leases aggregated approximately $257,000 and $28,000
during 1995 and 1996, respectively. The Woodlands Corporation ("TWC") filed a
Secured Claim in the amount of $250,000 in connection with the rejection of this
lease alleging the Claim is secured by the value of certain office equipment and
furniture pledged by WRT. The value of such collateral is substantially less
than the asserted Secured Claim; therefore, WRT filed an objection to TWC's
Secured Claim to the extent that such Claim amount exceeds the value of the
collateral. On April 22, 1997, the Bankruptcy Court granted the claimant an
allowed secured claim in the amount of $118,000 and an allowed unsecured claim
in the amount of $150,000.
The Company owns an industrial building located in Lafayette, Louisiana
with approximately 12,500 square feet of office, warehouse and shop space. This
space currently houses the Company's well logging technology.
The Company's cased hole logging equipment includes two wireline logging
trucks with complete mobile laboratories, two skid mounted wireline units with
mobile laboratories, four sets of small diameter radioactive well logging tools,
five sets of large diameter radioactive well logging tools, and all necessary
wireline and pressure control equipment for onshore and offshore well logging.
ITEM 3. LEGAL PROCEEDINGS
On December 10, 1992, the Company, one of its executives, a former
executive and others instituted a lawsuit against Bear, Stearns & Co. Inc.
("Bear Stearns"), Drake Capital Securities, Inc. ("Drake"), Steven Antebi
("Antebi") and Jerry Friedman ("Friedman") in the District Court of Harris
County, Texas 133rd Judicial District. After settling with Drake and Friedman,
the plaintiffs commenced trial on February 28, 1995. On March 21, 1995, the jury
returned a verdict in favor of the Company and five of the Company's
shareholders against Antebi for approximately $1,100,000. Pursuant to the jury
verdict, advice of outside counsel and management's belief that recovery of its
legal fees was probable, the Company recorded as a receivable approximately
$1,100,000 of costs incurred in connection with the litigation. The Company,
however, considered the jury verdict to be insufficient. Accordingly, the
Company requested, and on August 4, 1995 was granted a new trial. Absent the
jury verdict from the original trial, and considering the uncertainty regarding
the timing of possible recovery in a new trial, the Company and its outside
counsel concluded that they could no longer consider the recovery of the
receivable to be probable. Therefore, the Company recorded a provision for this
receivable in the third quarter of 1995. Prior to commencement of the new trial,
the case went to mediation and was settled on February 16, 1996 for $600,000
plus court costs of approximately $69,000, subject to the approval of the
Bankruptcy Court. Consequently on April 22, 1996, WRT filed a Motion for
Authority to compromise the litigation, requesting that the settlement be
approved and that the distribution of proceeds generated therefrom be authorized
to the respective parties to the litigation pursuant to the Settlement Agreement
reached. Due to objections raised as to the distribution of the litigation
proceeds,
18
<PAGE> 19
the Bankruptcy Court approved the Settlement Agreement but instructed that a
subsequent Motion be provided to resolve the issue of disposition of the
proceeds. As a result, on August 27, 1996, WRT filed a Motion for Authorization
to finally settle distribution of the litigation proceeds. On September 10,
1996, the Bankruptcy Court approved such motion and the proceeds have since been
distributed accordingly, including the distribution of approximately $145,000 to
WRT, which was recorded as Other Income for the year ended December 31, 1996.
Settlement funds of $154,000 attributable to one of the Company's former
executives have been held in escrow, pending final resolution of claims of the
WRT's bankruptcy estate if any, against the former executive.
In 1994, the Company received a certification from the DNR qualifying
certain gas production under Section 107(c)(2) of the Natural Gas Policy Act of
1978 the NGPA as gas produced from geopressured brine. As required under the
NGPA, the DNR's determination was forwarded to the FERC for review. In April
1995, the FERC reversed the position of the DNR, rejecting the qualification of
the wells under Section 17(c)(2) of the NGPA. The Company appealed the FERC
determination to the United States Court of Appeals for the Fifth Circuit,
located in New Orleans, Louisiana. In February 1997, the United States Court of
appeals for the Fifth Circuit affirmed the FERC's determination. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Commitments and Contingencies".
On December 18 and 19, 1995, two class-action shareholders' suits were
filed in the United States District Court for the Southern District of
California, seeking damages on behalf of a purported class of persons who
purchased the publicly-traded securities of the Company between October 20, 1993
and October 27, 1995. In these complaints, the plaintiffs have sued the Company,
certain members of its Board of Directors, and others alleging joint and several
liability for violations of Section 12(2) and Section 15 of the Securities Act
of 1933. The plaintiffs also complain that all defendants violated Section 10(b)
of the Securities Exchange Act of 1934 and Rule 10(b)(5) of the Securities
Exchange Commission. The individual defendants are alleged to be liable under
Section 20(a) of the Securities Exchange Act of 1934. On February 23, 1996, a
Notice of Stay by reason of the Company's bankruptcy was filed in both actions.
On March 21, 1996, all parties entered into a Stipulation whereby plaintiffs
agreed to consolidate the two actions under an amended and consolidated
complaint. On June 1, 1996, by agreement of all parties, the case was
transferred to the Southern District of New York. By order dated May 2, 1997,
the Bankruptcy Court disallowed this lawsuit in full as it relates to the
Company. As a result of the Bankruptcy Court's disallowance of this lawsuit, the
litigation will not have an effect on the Company's financial condition or
results of operations.
On October 24, 1997, a Third Amended Consolidated Class Action Complaint
was filed in the U.S. District Court for the Southern District of New York. This
Amended Complaint names as defendants the former officers and directors of WRT
and certain of the Company's underwriters and reserve engineers. WRT is not
named as defendant because, by its Order of March 24, 1997, the U.S. Bankruptcy
Court severed all claims against WRT.
On September 28, 1995, a lawsuit was served against the Company, Arnoult
Equipment and Construction, Inc., Steven S. McGuire, Donald J. Arnoult and
others in the 24th Judicial District Court for the Parish of Jefferson, State of
Louisiana. The plaintiff, the former president, chief executive officer and
stockholder in certain oilfield service companies used by the Company in its
field development activities, alleged that the Company and others interfered
with his employment, ultimately resulting in his forced resignation from such
companies. The plaintiff further alleged the Company and others acted in a
manner that resulted in the devaluing of the services company's assets and
plaintiff's corresponding equity holdings in the companies. On November 9, 1995,
the Company, et al filed with the Court exceptions of no cause of action, no
right of action and vagueness. On June 6, 1997, the Bankruptcy Court disallowed
this lawsuit in full.
During 1996, WRT received notice from a third party claiming that WRT's
title has failed as to approximately 43 acres in the Bayou Pigeon Field. Some or
all of the acreage in the dispute is considered to be productive in three
separate production units. Assuming that WRT's title is flawed, WRT's working
interest in three units may be reduced from 100% of each unit to approximately
7% (5% NRI), 75% (63% NRI), and 95% (72% NRI), respectively. The financial
statements as of and for the years ended December 31, 1996 and
19
<PAGE> 20
1995, reflect operating results and proved reserves discounted for this possible
title failure. As the title failure predates its ownership of the field, WRT is
currently evaluating its recourse against the predecessors-in-title relative to
this issue.
During 1995, the Company entered into a marketing agreement with Tri-Deck
Oil and Gas Company ("Tri-Deck") pursuant to which Tri-Deck would market all of
WRT's oil and gas production. Subsequent to the agreement, Tri-Deck's principal
and WRT's Director of Marketing, James Florence, assigned to Plains Marketing
Tri-Deck's right to market WRT's oil production and assigned to Perry Oil & Gas
("Perry Gas") Tri-Deck's right to market WRT's gas production. During early
1996, Tri-Deck failed to make payments to WRT attributable to several months of
WRT's gas production. Consequently, on May 20, 1996, the Company filed a Motion
to Reject the Tri-Deck Marketing Agreement, and on May 29, 1996, the Company
initiated an adversary proceeding against Tri-Deck and Perry Gas. Perry Gas was
the party which ultimately purchased the Company's gas production for the months
in question.
With respect to the Motion to Reject, the Bankruptcy Court authorized the
rejection and directed Tri-Deck and WRT to determine the amount of production
proceeds attributable to WRT's June 1996 gas production which are payable to
WRT. Thereafter, Perry Gas made payment to WRT of the June gas proceeds less
$75,000 for a set-off claim by Perry Gas, which is subject to further
consideration by the Bankruptcy Court. Perry Gas subsequently filed an
administrative claim in the Chapter 11 case, seeking recovery for damages
allegedly arising out of WRT's conduct in connection with its rejection of the
Tri-Deck contract and related negotiations with Perry. By decision dated July 3,
1997, the Bankruptcy Court allowed, in part, Perry Gas' administrative claim, in
the aggregate amount of approximately $64,000, and directed Perry Gas to obtain
payment of such amount from the Perry Setoff Escrow, which as result of this
payment, currently has a balance of approximately $10,000.
With respect to the adversary proceeding, WRT sought recovery from Tri-Deck
and/or Perry Gas of all unpaid production proceeds payable to WRT under the
marketing agreement and the issuance of a temporary restraining order and
preliminary injunction against both parties to prevent further disposition of
such proceeds pending the outcome of the proceedings. On May 31, 1996, the
Bankruptcy Court entered a consensual temporary restraining order against both
Tri-Deck and Perry Gas. On June 18, 1996, a preliminary injunction was entered
by the Bankruptcy Court which required Perry Gas to segregate in to a separate
depository account the funds due for the purchase of WRT's April and May 1996
gas production from Tri-Deck. Subsequently, upon motion by WRT the Bankruptcy
Court ordered such funds to be placed into the Bankruptcy Court's registry, as
Perry Gas had made certain withdrawals from the separate depository account
without authorization by the Bankruptcy Court. As of October 1, 1997, funds in
the amount of approximately $1,700,000 remained in the registry of the
Bankruptcy Court. On April 1, 1997, WRT moved for partial summary judgement with
respect to Perry Gas seeking release of the escrow funds, as well as additional
funds from Perry Gas attributable to previous miscalculations of the amounts
owed by Perry Gas. At a hearing held on May 27, 1997, the Bankruptcy Court
denied WRT's motion to extent that it sought additional payments by Perry Gas to
WRT and reserved decision with respect to the disbursement to WRT of the funds
currently in the Court's registry. On July 9, 1997, Perry Gas filed its own
summary judgement motion with respect to its assertion that it is entitled to
certain adjustments for prior overpayments in the amount of approximately
$120,000. At oral argument on August 26, 1997, Perry requested permission to
amend its motion and subsequently filed an amended affidavit reducing the amount
claimed to approximately $51,000.
On August 21, 1997, WRT filed a motion for leave to amend the adversary
complaint, which if amended would, among other things, name as defendants, in
addition to Tri-Deck and Perry Gas, James Florence, Beth Perry Sewell, Steve
McGuire, Ronald Hale and Mark Miller, and included several additional causes of
action against both the original and these additional defendants. The additional
causes of action asserted in the proposed amended Tri-Deck Complaint include
breach of contract, breach of fiduciary duty, knowing participation in breach of
fiduciary duty, conversion, unjust enrichment, fraud, constructive trust and
fraudulent conveyance. Oral argument with respect to WRT's motion for leave to
amend was heard on September 16, 1997, and the motion is currently under review.
In light of the pendency of WRT's motion to amend, by Order dated September 5,
1997, the Court denied WRT's motion for partial summary judgement, which had
been under advisement since May, 1997.
20
<PAGE> 21
Ultimate resolution of the WRT -- Tri-Deck -- Perry Gas dispute, and thus
recovery by WRT of all amounts owed by Tri-Deck or Perry Gas, will also entail
Bankruptcy Court disposition of a counterclaim by Tri-Deck seeking, among other
things, damages for alleged tortious interference by WRT with Tri-Decks'
contractual relations with other Tri-Deck customers. Although management
believes that Tri-Deck's claim to the funds in the registry of the Bankruptcy
Court is invalid, and the aforementioned counterclaim is without merit, for
financial reporting purposes the receivable from Tri-Deck was fully reserved for
as of December 31, 1996.
On January 14, 1997, WRT initiated an adversary proceeding, WRT Energy
Corp. v Tri-Core Energy, L.P., (Adv. Pro. No 97AP-5003), in United States
Bankruptcy Court, Western District of Louisiana, Lafayette Opelousas Division,
to obtain a declaration of the invalidity of the security interest or liens
allegedly securing Tricore Energy Venture, LP's ("Tricore") asserted secured
claim of "up to $9,064,000" (as amended) or alternatively for avoidance of such
security interest or liens pursuant to Section 544 and 547 of the Bankruptcy
Code. Such suit is pending as of the date of this report. On March 7, 1997, the
Company also filed an objection to both the allowance and amount of Tricore's
claim. The objection has been consolidated with the adversary proceeding. On
August 6, 1997, the Bankruptcy Court issued an opinion holding that Tricore's
asserted security interest and liens were invalid under Louisiana law. See
further explanation regarding Tricore at Note 16, "Joint Venture Agreement" to
the Company's Consolidated Financial Statements. The Company is currently
negotiating a settlement with Tricore pursuant to their claim.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
As of the date of this report, the Company has not held a 1996 annual
meeting of shareholders.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS
HISTORICAL MARKET INFORMATION
Throughout 1995, the Company's old Common Stock and old Preferred Stock
were quoted on the NASDAQ National Market under the symbols "WRTE" and "WRTEP,"
respectively. In February 1996, the Company was advised that its old Common
Stock and old Preferred Stock would no longer be quoted on the NASDAQ National
Market due to the Company's failure to meet certain criteria for continued
quotation, including its failure to hold an annual meeting and solicit proxies
in 1995 and its inability, due to its $103 million year-end write-down, to meet
the minimum net tangible assets requirements. The Company sought and received an
oral hearing before the NASDAQ Listing Qualifications Committee (the
"Committee") to request a temporary exception from the application of the
unsatisfied listing standards. The Company's exception request was denied by the
Committee, and on February 29, 1996, both the Company's old Common Stock and old
Preferred Stock were delisted from the NASDAQ National Market. Subsequently, the
Company's old Common Stock and old Preferred Stock was sporadically traded in
the over the counter market under the symbols "WRTEQ" and "WRTEPQ,"
respectively. The following table sets forth, for the periods shown, the high
and low sales prices for the old Common Stock as reported on the NASDAQ National
Market.
21
<PAGE> 22
The New Common Stock of the Company is traded sporadically in the
over-the-counter market under the symbol "WRT". At the close of business on
September 30, 1997, there were 22,076,315 shares of New Common Stock outstanding
held by 138 shareholders of record.
<TABLE>
<CAPTION>
LOW HIGH
----- -----
<S> <C> <C>
YEAR ENDED DECEMBER 31, 1995
First Quarter............................................... $5.63 $8.50
Second Quarter.............................................. $4.63 $8.13
Third Quarter............................................... $3.69 $6.38
Fourth Quarter.............................................. $0.38 $4.00
YEAR ENDED DECEMBER 31, 1996 (1)
First Quarter (through February 29, 1996.................... $0.25 $1.19
Second Quarter.............................................. N/A N/A
Third Quarter............................................... N/A N/A
Fourth Quarter.............................................. N/A N/A
</TABLE>
- ---------------
(1) For the period from January 1, 1996 to February 29, 1996. The Company's old
Common Stock was delisted from the NASDAQ National Market on February 29,
1996.
HOLDERS OF RECORD
By order dated May 2, 1997, immediately prior to the Effective Date of the
Plan, the Company had 297 common and 85 preferred shareholders of record.
DIVIDEND POLICY
The holders of 9% Convertible Preferred Stock, par value $.01 per share,
were entitled, when, as, and if declared by the Board of Directors, to receive
an annual dividend of $2.25 per share, payable quarterly in arrears. Any
dividends that were not declared accumulated and all accumulated dividends on
the Preferred Stock were to be paid in full before dividends could be paid to
holders of Common Stock. In addition, the Indenture limited the circumstances in
which the Company could pay dividends on its Preferred Stock. The Board of
Directors did not declare Preferred Stock dividends in 1996. The Company accrued
for cumulative dividends in its December 31, 1995 financial statements; however,
additional dividends were not accrued for in the 1996 financial statements. The
Company has never paid dividends on its Common Stock. Under the Plan, effective
July 11, 1997, all pre-reorganization WRT preferred and common shareholder
claims were extinguished.
The Company anticipates retaining all available funds to operate New WRT
and pay its creditors under the Plan approved by the Bankruptcy Court.
Therefore, New WRT does not intend to pay dividends on its Common Stock in the
foreseeable future. Further, the Credit Facility restricts the Company from
declaring or paying any dividends on any class of its capital stock so long as
the Credit Facility is outstanding.
22
<PAGE> 23
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth a summary of consolidated financial and
operating information for the Company as of the dates and for the periods
indicated. Such financial information should be reviewed in conjunction with the
consolidated financial statements of the Company and the notes thereto and
Management's Discussion and Analysis of Financial Condition and Results of
Operations set forth elsewhere in this Report.
<TABLE>
<CAPTION>
AS OF AND FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1996 1995 1994 1993 1992
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Statement of Operations Data
Oil and gas sales................ $ 24,019 $ 24,655 $ 11,034 $ 4,657 $ 1,192
Field Service Revenues........... -- -- -- -- 1,511
---------- ---------- ---------- ---------- ----------
Total revenues........... 24,109 24,655 11,034 4,657 2,703
Operating expenses............... 40,855 139,497(1) 10,126 5,841 2,407
---------- ---------- ---------- ---------- ----------
Net income (loss) from
operations.................... (16,836) (114,842) 908 (1,184) 296
---------- ---------- ---------- ---------- ----------
Interest expense................. 5,562 13,759 19 447 277
Reorganization costs............. 7,345 -- -- -- --
Income (loss) before income
taxes......................... (29,387) (128,175) 4,266 (1,322) 383
Net income (loss) before
dividends on Preferred
Stock......................... (29,387) (128,175) 4,230 (1,322) 383
Dividends on Preferred Stock..... -- (2,846) (2,846) (591) --
Net income (loss) available to
Common Stock.................. (32,233) (131,021) 1,384 (1,913) 383
Earnings (loss) per common and
common equivalent share....... $ (3.38) $ (13.84) $ 0.18 $ (0.54) $ (0.13)
Average common and common
equivalent shares
outstanding................... 9,539,000 9,466,000 7,792,000 4,154,000 5,315,000
Capital expenditures............. $ 4,823 $ 116,730 $ 40,087 $ 14,325 $ 3,533
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------------------------
1996 1995 1994 1993 1992
--------- --------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Balance Sheet Data
Working capital (deficit)........ $(148,648) $(131,601) $ 6,301 $24,270 $(2,652)
Property, plant and equipment,
net........................... 56,899 63,913 59,042 18,586 7,397
Total assets..................... 68,076 79,247 81,857 48,233 11,206
Total long-term debt............. -- -- 6,260 205 2,606
Shareholder's equity (deficit)... (90,551) (61,869) 63,538 43,394 4,050
</TABLE>
- ---------------
(1) Operating expenses for 1995 include a non-cash charge of $103,000,000
related to impairment of long-lived assets pursuant to SFAS No. 121,
non-cash charges of $3,600,000 related to a minimum production guarantee
obligation, a $2,000,000 provision for doubtful accounts, and a $1,400,000
charge related to restructuring costs incurred. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis of the Company's financial condition
and results of operations is based in part on the consolidated financial
statements and the notes thereto included elsewhere in this Form 10-K and should
be read in conjunction therewith.
23
<PAGE> 24
RECENT EVENTS
See Item 1 "Business -- Events Leading to the Reorganization Case" for a
discussion of recent events related to the Company's operations and subsequent
filing for protection under Chapter 11 of the Federal Bankruptcy Code.
ACCOUNTING CHANGE
Effective December 31, 1995, the Company adopted Statement of Financial
Accounting Standards "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets To Be Disposed Of" ("SFAS No. 121"). SFAS No. 121 requires
that an impairment loss be recognized whenever the carrying amount of an asset
exceeds the sum of the estimated future cash flows (undiscounted) of the assets.
For each asset determined to be impaired, an impairment loss equal to the
difference between the carrying value and the fair value of the asset was
recognized. With respect to the Company's oil and gas properties, fair value, on
a depletable basis, was estimated to be the present value of expected future
cash flows computed by applying estimated future gas and oil prices, as
determined by management, to estimated future production of oil and gas reserves
over the economic lives of the reserves. The Company recorded a non-cash charge
of $103,300,000 in connection with the adoption of this new accounting standard.
Based upon the preliminary oil and gas reserve data then available, the
Company estimated in October 1995 it would recognize in the fourth quarter a
$60,000,000 to $65,000,000 charge related to the adoption of SFAS No. 121.
However, final year-end estimates of proved oil and gas reserves resulted in
significant downward revisions from the amounts estimated in October 1995. These
downward revisions were partially the result of differences in professional
opinion between the Company's current and predecessor independent engineering
firms. These differences, many of which relate to classification of reserves
within the different oil and gas reserve categories (i.e. proved, probable and
possible) are due to the numerous engineering, geological and operational
assumptions that generally are derived from limited data. Additional downward
revisions are attributed to field development activity and production data
during the year. Drilling and recompletion activities, including the
unsuccessful well projects in the Company's East Hackberry and Bayou Penchant
fields and the mechanical failure of the Exxon Fee #23 well, resulted in
significant reserve losses. These downward revisions resulted in the Company
recognizing an impairment of oil and gas properties of approximately $95,000,000
at December 31, 1995. Of this $95,000,000 impairment, the Company believes that
approximately 46% (or approximately $44,000,000) is attributable to the
differences in professional opinion between the Company's previous engineering
firms (on whose reports the Company based its October 1995 preliminary
estimates) and the Company's current engineering firm. See "Properties --
Reserves." At December 31, 1996, the Company incurred an additional non-cash
charge of $2,545,000 related to the further impairment to its oil and gas
properties as a result of additional downward revisions in the proved oil and
gas reserves at December 31, 1996.
In 1995, the Company also recorded a non-cash charge related to certain
rig, marine and field equipment owned or securing notes receivable. The Company
originally expected this equipment would provide drilling and field services in
the Company's oil and gas development program. Due to the liquidity problems and
the reduced level of development activity, the Company did not expect to utilize
these assets in the near term and, accordingly, the Company determined recovery
of the related carrying cost to be unlikely. As a result of the adoption of SFAS
No. 121, the Company recorded an impairment of $7,900,000 related to this
equipment in 1995. During 1996, the remaining portion of the non-cash charge, in
the amount of $1,319,000, related to the impairment of its office and field
equipment. Of this balance, $815,000 related primarily to a write-down of the
Company's office equipment and computer hardware and software to its appraised
fair value, and the remaining $504,000 relates to a write-down of the wireline
equipment to its appraised fair value.
IMPACT OF RECENTLY ISSUED ACCOUNTING STANDARDS NOT YET ADOPTED
In February, 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 128, ("SFAS No. 128") "Earnings
Per Share." SFAS No. 128 is effective for financial statements issued for
periods ending after December 15, 1997, and restatement of prior-period earnings
per
24
<PAGE> 25
share date is required. The new standard will not apply to the Company's
financial statements until the fourth quarter of 1997. SFAS No. 128 revises the
current calculation methods and presentation of primary and fully diluted
earnings per share. The Company has reviewed the requirements of SFAS No. 128,
and has concluded that they will not materially affect the Company's historical
primary earnings per share data post-reorganization. For periods prior to the
consummation of the Plan, the Company will not be presenting earnings (loss) per
share information as the calculations are not meaningful due to the
reorganization.
CREDIT FACILITY AND SENIOR NOTE OFFERING
In December 1994, the Company entered into a $40,000,000 credit facility
with INCC that was secured by substantially all of the Company's assets. The
Company borrowed $15,000,000 thereunder to purchase the Initial LLOG Property.
In March 1995, $12,000,000 of the outstanding borrowings under the Credit
Facility was repaid from the proceeds of the Offering. During 1995, the Company
borrowed an additional $12,000,000 under the credit facility, bringing the
outstanding borrowings to $15,000,000, the maximum amount of borrowings
available under the Credit Facility. On December 31, 1995, the Credit Facility
converted to a term loan whereby quarterly principal payments of one-sixteenth
of the outstanding indebtedness were due and payable commencing March 31, 1996.
The Credit Facility contained restrictive covenants which imposed
limitations on the Company and its subsidiaries with respect to, among other
things: (i) the maintenance of current assets equal to at least 110% of current
liabilities (excluding any current portion of the Credit Facility); (ii) the
incurrence of funded indebtedness; (iii) dividends and similar payments; (iv)
the creation of additional liens on, or the sale of, the Company's oil and gas
properties and other assets; (v) the Company's ability to enter into hedging
transactions; (vi) mergers or consolidations; (vii) investments outside the
ordinary course of business; (viii) transactions with affiliates; and (ix)
general and administrative expenditures in excess of $4,000,000 during 1995 or
during each fiscal year thereafter, in excess of 15% of the Company's
consolidated revenues from operations during such fiscal year.
In February 1995, the Company offered 100,000 Units consisting of
$100,000,000 aggregate principal amount of 13 7/8% Senior Notes Due 2002 and
warrants to purchase an aggregate of 800,000 shares of the Company's Common
Stock. The net proceeds from the Offering were used to acquire the Remaining
LLOG Properties, repay the Bridge Loan and substantially all borrowings under
the Credit Facility, acquire an additional working interest in WCBB and for
general corporate purposes. See Item 1 "Business -- Oil and Gas Property
Acquisitions."
The Senior Notes were issued under the Indenture, which contained certain
covenants that, among other things: limited (i) the incurrence of additional
indebtedness; (ii) the payment of dividends or making of certain other
restricted payments; (iii) the incurrence of liens; (iv) the disposition of
subsidiary stock; (v) transactions with affiliates; (vi) certain sale and
leaseback arrangements; (vii) investments; (viii) guarantees of indebtedness by
subsidiaries; (ix) the imposition of restrictions on the subsidiaries' ability
to make distributions to the Company; and (x) mergers, consolidations and
transfers of assets.
As of December 31, 1996 and 1995, the Company was in default under certain
financial covenants of the Credit Facility. In addition, due to the bankruptcy
filing in February 1996, the Company was in default under the Indenture.
Accordingly, the indebtedness represented by the Senior Notes and under the
Credit Facility was classified as current liabilities in the Company's December
31, 1996 and 1995 financial statements. While in bankruptcy, INCC and holders of
the Senior Notes were stayed from enforcing certain remedies provided for in the
credit agreement and the Indenture. The Company did not make the March 1, 1996
interest payment on the Senior Notes, and pursuant to an order of the Bankruptcy
Court did not make the scheduled interest payment of $381,000 to INCC on
February 28, 1996, nor did it make any interest or principal payments since that
date through the Effective Date. In addition, the Company did not make the first
scheduled principal payment of $938,000 due on the Credit Facility on March 31,
1996, nor has it made any principal payments since that date through July 11,
1997. On the Effective Date, the Company entered into a new loan agreement with
ING (U.S.) Capital Corporation (successor to INCC )("ING"), the terms of
25
<PAGE> 26
which required the payoff of the $15,000,000 in principal and interest
outstanding on the old credit agreement with proceeds of the new loan. Also
pursuant to the Plan, the Senior Notes were canceled.
ACQUISITIONS AND SALES
Initial LLOG Property Acquisition. In December 1994, the Company entered
into a definitive agreement with LLOG for the purchase of LLOG's working
interest (approximately 100%) in the Bayou Penchant Field (the "Initial LLOG
Property"). The Company concluded the acquisition of the Initial LLOG Property
in late January 1995 for a purchase price of approximately $15,600,000 plus a
nonrefundable deposit of $5,000,000 towards the purchase from LLOG of certain
additional oil and gas properties, described below. The approximately
$20,600,000 paid to LLOG was financed by borrowings of $15,000,000 under the
Company's Credit Facility, and by the issuance to LLOG of a short-term
promissory note for approximately $5,600,000. In early February 1995, the
Company borrowed $7,500,000 under the Bridge Loan to refinance the Seller
Financing Note and for general corporate purposes.
Remaining LLOG Properties Acquisition. In December 1994, the Company and
LLOG also entered into a letter of intent for the purchase by the Company of the
Remaining LLOG Properties. Separate purchase contracts for each of the Remaining
LLOG Properties were entered into in January 1995. The Company concluded the
acquisition of the Remaining LLOG Properties in early March 1995 for an
aggregate purchase price of approximately $46,400,000, less the $5,000,000
nonrefundable deposit previously paid to LLOG in connection with the Company's
acquisition of the Initial LLOG Property. The approximately $41,400,000 paid to
LLOG was financed through the offering of the Senior Notes in March 1995.
The Remaining LLOG Properties consist of working interests in four south
Louisiana oil and gas fields: the Bayou Pigeon Field; the Deer Island Field; the
Abbeville Field; and the Golden Meadow Field. The Company owns a 100% working
interest in substantially all acreage comprising the Remaining LLOG Properties,
other than the Abbeville Field in which it owns approximately 70% of the working
interest. The Company is the operator of the Initial LLOG Property and the
Remaining LLOG Properties. During 1996, the Company received notice of a
possible title failure on approximately, 43 acres in the Bayou Pigeon Field. See
further discussion in "Item 2 -- Properties -- Title to Oil and Gas Properties."
West Cote Blanche Bay Field Acquisition. In January 1995, the Company
entered into an agreement in principle with an affiliate of Benton Oil and Gas
Company and two affiliates of Tenneco, Inc., to purchase for $20,000,000 an
additional 43.75% working interest in the WCBB, a property in which the Company
held a 6.25% working interest. Pursuant to the agreement, the sellers retained
their interests in all depths below an average of approximately 10,500 feet. The
purchase was completed in April 1995. As of December 31, 1996, Texaco Inc. was
the operator of the field and was the owner of the remaining 50% working
interest in the lease rights the Company acquired. See Item 1 above relating to
the Reorganization of the Company.
Napoleonville Field. In December 1994, the Company purchased a 100% working
interest (approximately 75% net revenue interest) in leases covering
approximately 300 acres in the Napoleonville Field for a purchase price of
$9,800,000 which was paid by the issuance of 1,300,000 shares of the Company's
common stock.
During 1995, the Company purchased for approximately $1,200,000 and
$600,000, respectively, certain additional leasehold acreage in the
Napoleonville Field and saltwater disposal facilities from BSFI. At the time of
the purchase, BSFI, as a 5.5% common shareholder of the Company, was a related
party. In connection with the purchase, the parties also effected the settlement
of a potential dispute between BSFI and the Company related to an assertion by
BSFI that the Company allegedly failed to timely register for resale the
1,300,000 common shares issued to purchase the Napoleonville Field.
Sale of Rig and Marine Equipment. In December 1994, the Company sold four
drilling and workover rigs, obtained in connection with certain oil and gas
property acquisitions, to an oil field service contractor for a total
consideration of $3,900,000. The purchaser gave a 6% secured promissory note in
exchange. No gain or loss was recognized at the date of the sale and the
$1,000,000 gain on the sale was deferred and was being realized over the life of
the note. Subsequent concerns about the ability of the purchaser to perform
pursuant
26
<PAGE> 27
to the terms of the contract resulted in the Company reversing the deferred
gain, in September 1995. At December 31, 1995, the related note receivable was
canceled. The Company has hired counsel and currently is seeking to recover the
collateral securing this note.
In December 1994 and May 1995, the Company sold to the same oil field
service contractor, marine and oil field service equipment for a total
consideration of $5,200,000. The purchaser gave two 6% secured promissory notes
in exchange. No gain or loss was recognized at the date of the sale and the
$800,000 gain on the sale was deferred and was being realized over the life of
the notes. Subsequent concerns about the ability of the purchaser to perform
pursuant to the terms of the contracts resulted in the Company reversing the
deferred gain, in September 1995. At December 31, 1995, the two related
promissory notes were fully cancelled. The Company has hired counsel and is
currently seeking to recover the collateral securing these notes.
RESULTS OF OPERATIONS
Prices and Production Volumes.
The markets for oil and gas have historically been, and will continue to
be, volatile. Prices for oil and gas may fluctuate in response to relatively
minor changes in supply and demand, market uncertainty and a variety of factors
beyond the control of the Company. Set forth in the table below are the average
prices received by the Company and production volumes during the periods
indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1996 1995 1994
------ ------- ------
<S> <C> <C> <C>
Production volumes:
Oil (MBbls)........................................... 615 778 270
Gas (MMcf)............................................ 3,629 7,403 3,503
Gas equivalents (MMcfe)............................... 7,319 12,071 5,123
Average prices:
Oil price (per Bbl)................................... $22.17 $ 16.59 $16.44
Gas price (per Mcf)................................... $ 2.86 $ 1.59 $ 1.88
Gas equivalents (per Mcfe)............................ $ 3.28 $ 2.04 $ 2.15
Average production cost (per Mcfe):..................... $ 1.82 $ 0.79 $ 0.60
Average production tax (per Mcfe):...................... $ 0.24 $ 0.18 $ 0.16
</TABLE>
COMPARISON OF YEARS ENDED DECEMBER 31, 1996 AND 1995
The Company reported a net loss attributable to common stock of $32,233,000
($3.38) per share, for the year ended December 31, 1996, as compared with a net
loss attributable to common stock of $131,021,000, ($13.84) per share for 1995.
The reduction in net losses attributable to common stock of $98,788,000 was due
to the following factors:
Oil and Gas Revenues. During 1996, the Company reported oil and gas
revenues of $24,019,000, a 3% decrease from revenues of $24,655,000 for 1995.
The decreased revenues are attributable to a decrease in production volumes of
4,752 MMcfe offset by an increase of $1.24 per Mcfe in average sales price for
the year. The production declines are due in part to the mechanical failure of
the Exxon Fee #23 and in part due to normal production declines.
Production Costs. Production costs increased $3,770,000, or 40%, from
$9,534,000 in 1995 to $13,304,000 in 1996. Production costs per Mcfe increased
130% from $0.79 in 1995 to $1.82 in 1996. This increase in production costs per
Mcfe was due primarily to the following factors. At December 31, 1996, disputed
claims adjustments totaling approximately $2,814,000, the Milam Royalty Corp.
settlement in the amount of $1,172,000, and the Lac Blanc purchase price
adjustment in the amount of $479,000 were recorded as production costs.
Production costs on the properties excluding the previously mentioned items
decreased by 7% while the oil sales volume decreased by 21% and the gas sales
volumes decreased by 51%, resulting in significantly increased production costs
per Mcfe.
27
<PAGE> 28
Gross Production Taxes. Production taxes decreased by $348,000, or 16%,
from $2,139,000 in 1995 to $1,791,000 in 1996. This decrease is attributable to
the fact that in Louisiana, gross production taxes on gas sales are computed on
a volumetric basis rather than on the sales price, and gas volumes decreased by
51% in 1996. This decrease in production taxes is partially offset by a $5.58
per barrel increase in the average price received for oil in 1996, which
increased gross production taxes attributable to oil production.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense decreased 37% from $12,645,000 in 1995 to $7,973,000 in
1996. This decrease was due primarily to 21% decrease in oil production combined
with a 51% decrease in gas production. On an Mcfe basis, depreciation, depletion
and amortization expense increased 4% from $1.05 per Mcfe in 1995 to $1.09 per
Mcfe in 1996.
General and Administrative Expense. General and administrative expenses
decreased by 34% from $4,882,000 in 1995 to $3,210,000 in 1996 as a result of
the Company's change in strategy resulting in a substantial reduction in
personnel and third-party geological and engineering costs.
Provision for Doubtful Accounts. Provision for doubtful accounts increased
$3,151,000 from $2,007,000 at December 31, 1995 to $5,158,000 at December 31,
1996. The provision for doubtful accounts for 1996 consists primarily of an
allowance of a receivable in the amount of $4,278,000 relating to the Tri-Deck
legal proceeding (See below and "Legal Proceedings").
In April 1995, the Company entered into a marketing agreement with Tri-Deck
pursuant to which Tri-Deck would market all of the Company's oil and natural gas
production. Subsequent to the agreement, Tri-Deck's principal, James Florence,
who was also serving as WRT's Director of Marketing, assigned to Plains
Marketing its right to market the Company's oil production and entered into a
contract with Perry Oil and Gas to market the Company's gas production. During
the early stages of the Company's Reorganization Case, Tri-Deck failed to make
payments to the Company attributable to certain 1996 gas production. Due to the
uncertainty of the amount that will be recovered from Tri-Deck, the Company has
recorded an allowance for this receivable in the amount of $4,278,000. Of this
amount, approximately $1,700,000 related to the receivable from Tri-Deck for the
purchase of WRT's April and May, 1996 gas production and has been deposited into
a depository account with the Bankruptcy Court's registry.
In addition, during 1996 the Company charged an additional $880,000 to bad
debts expense related to receivables deemed uncollectible as a result of the
Reorganization Case.
Restructuring Charges and Reorganization Costs. The Company incurred
certain costs in connection with its change in strategy and corporate structure.
During 1996, the Company incurred reorganization costs of $7,345,000, consisting
primarily of professional fees totaling $2,594,000, and the write-off of
previously capitalized debt issuance costs on the Senior Notes in the amount of
$3,834,000.
During 1995, the Company incurred $1,433,000 in restructuring charges
consisting primarily of the write-off of approximately $1,000,000 in leasehold
improvements related to the relocation of the Company's operations from The
Woodlands, Texas, approximately $305,000 in severance costs related to staff
reductions and changes in senior management, and $145,000 in legal and other
costs directly related to the Company's Reorganization Case.
Minimum Production Guarantee Obligation. The Company has provided Tricore
with a limited production guarantee based on the minimum production schedule
attached to the Tricore Joint Venture Agreement. The minimum production schedule
assumes that Tricore's cumulative share of the future gross production from
jointly-owned properties will average 4,250 Mcf per day during the period
between October 1, 1996 and September 30, 1997, 2,350 Mcf per day during the
period October 1, 1997 and September 30, 1998, and 699 Mcf per day during the
period October 1, 1998 and September 30, 1999. The minimum production also
assumes that all future gas production allocated to Tricore will be sold at a
price of $1.50 per Mcf. As long as either the actual volume of natural gas
delivered or the gross revenue allocated to Tricore exceeds the cumulative
values reflected in the minimum production schedule, the Company will have no
current liability to Tricore under the production guarantee. Pursuant to the
Joint Venture Agreement, if the production during any annual period, commencing
October 1 through September 30, is less than the minimum production levels
required by the Joint Venture Agreement, the Company is required to eliminate
the annual production deficit
28
<PAGE> 29
by delivering sufficient quantities of gas from other properties in twelve equal
monthly installments, commencing the following December 1, or by the issuance to
the venture of registered debt or equity securities which have a full market
value equal to the required payment. As collateral for the Company's obligations
under the production guarantee, Tricore holds a partial assignment of an
interest in the West Cote Blanche Bay Field. This 4.68% working interest (3.72%
net revenue interest) assignment, was made subject to the terms and provisions
of the Joint Venture Agreement. Upon satisfaction of the production guarantee,
Tricore is required to execute and deliver a release of the partial assignment.
As discussed in the Note 16 -- "Joint Venture Agreement" section below, the
Company accrued $5,555,000 in 1996 and $3,591,000 in 1995 related to its
anticipated minimum production guarantee obligation to Tricore Energy Venture,
L.P. The additional accrual in 1996 was due in part to the disallowance of the
Section 29 Energy Credit by the FERC and the subsequent ruling in the FERC's
favor by the United States Court of Appeals, as further discussed below and in
part due to downward revisions of the reserve estimates associated with the
properties collateralizing the production payment obligations.
Pursuant to the terms of the production guarantee, if any of the gas
production from joint venture properties qualifies for the nonconventional fuels
tax credit provided for by Internal Revenue Code Section 29, then 150% of that
tax credit shall be included in the calculation of gross revenues for purposes
of the guarantee. Based upon a certification by the Louisiana Department of
Natural Resources ("DNR"), a significant amount of the production attributable
to the joint venture qualified under Section 107(c)(2) of the Natural Gas Policy
Act of 1978 (the "NGPA") as gas produced from geopressured brine. As required
under the NGPA, the DNR's determination was forwarded to the FERC for review. In
April 1995, the FERC reversed the position of the DNR, rejecting the
qualification of the wells under Section 107(c)(2) of the NGPA. The Company
appealed the FERC determination to the United States Court of Appeals for the
Fifth Circuit, located in New Orleans, Louisiana. In February 1997, the United
States Court of Appeals for the Fifth Circuit affirmed the FERC's determination.
Impairment of Long-Lived Assets. As previously discussed, effective
December 31, 1995, the Company adopted SFAS No. 121 resulting in the recognition
of an impairment loss related to the Company's oil and gas properties and other
long-lived assets in the amount of $103,266,000. During 1996, the Company
recognized an additional impairment loss related to its oil and gas properties
and long-lived assets in the amount of $3,864,000. The 1996 impairment loss was
due primarily to further declines in the Company's estimated oil and gas
reserves and the write-down of certain other equipment to its appraised value.
Interest Expense. The decrease in interest expense of $8,197,000, from
$13,759,000 for 1995 to $5,562,000 for 1996, is primarily due to the termination
of the interest accrual on the $100,000,000 in Senior Notes as of February 14,
1996 (the filing date of the Chapter 11 proceedings).
COMPARISON OF YEARS ENDED DECEMBER 31, 1995 AND 1994
The Company reported a net loss attributable to common stock of
$131,021,000, ($13.84 per share, for the year ended December 31, 1995, as
compared with net income of $1,384,000, $0.18 per share, for 1994. Although oil
and gas revenues increased substantially in 1995 compared to 1994 several
factors resulted in the $132,405,000 decrease in the Company's 1995 net income
available to common stock.
Oil and Gas Revenues. During 1995, the Company reported oil and gas
revenues of $24,655,000, a 123% increase over revenues of $11,034,000 for 1994.
The increased revenues are attributable to the oil and gas property acquisitions
completed by the Company during the first four months of 1995. These
acquisitions represent 58% of the Company's total 1995 production on a gas
equivalent basis. The overall increase in revenues related to increased volumes
was substantially offset by a 16% decline in gas prices in 1995 as compared to
the previous year.
Production Costs. Production costs increased $6,457,000, or 210%, from
$3,077,000 in 1994 to $9,534,000 in 1995, due primarily to the oil and gas
property acquisitions during 1995. Production costs per Mcfe increased 32% from
$0.60 in 1994 to $0.79 in 1995 primarily due to the significant level of
workover and field activity, coupled with the previously discussed lower than
expected production results. In addition, the Company incurred approximately
$900,000 in non-recurring operating expenses related to a test project for the
29
<PAGE> 30
down-hole disposal of oilfield environmental wastes and contaminated production
tubing done in connection with the plugging and abandonment of four wells. The
test included encapsulation of the waste in the abandoned wellbore and was
required by the DNR in connection with the Company's application for a downhole
disposal and waste-handling license.
Gross Production Taxes. Gross production taxes increased by $1,328,000, or
164%, from $811,000 in 1994 to $2,139,000 in 1995. This increase was due to the
significantly increased volumes and dollar amount of oil and gas sales in 1995.
The 1995 production increases are attributable to the 1995 property additions.
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased by $9,444,000, or 295%, from $3,201,000 in 1994
to $12,645,000 in 1995. This increase is partially attributable to a 188%
increase in oil production and an 111% increase in gas production. The remainder
of the increase is related to the significant downward revisions in proved oil
and gas reserves during the fourth quarter of 1995. On an Mcfe basis,
depreciation, depletion and amortization expense increased 69% from $0.62 per
Mcfe in 1994 to $1.05 per Mcfe in 1995.
General and Administrative Expenses. General and administrative expenses
increased 59% from $3,037,000 for the year ended December 31, 1994 to $4,882,000
for 1995. General and administrative expenses increased overall as a result of
the Company's substantial growth during 1995. A substantial portion of the
increase, however, is related primarily to higher personnel costs, third-party
geological costs and legal expenses. The Company increased its senior management
and field engineering staff in late 1994 and early 1995 in connection with the
contemplated oil and gas property acquisitions that closed in the first quarter
of 1995. This increase in staff was composed of industry professionals,
including petroleum engineers, geologists, well logging technicians,
environmental engineers and other professionals employed for the purpose of
planning and implementing the Company's 1995 field development plan. The Company
also incurred additional third-party geological and engineering costs related to
preparation of a mid-year independent reserve report required by the Credit
Facility. Legal fees increased during 1995 due to outside legal services
rendered in connection with the Bear Stearns and other lawsuits and regulatory
matters before the FERC.
Provisions for Doubtful Accounts. The provision for doubtful accounts
increased by $2,007,000, from zero at December 31, 1994 to $2,007,000 at
December 31, 1995. The increase was partially attributable to the provision for
a long-term receivable recovery which is made in the form of a production
payment from the oil and gas revenues in certain Company operated oil and gas
properties. The most significant well underlying the production payment ceased
production during the third quarter of 1995 due to mechanical failure of the
well bore. As a result, the ultimate recovery of the remaining receivable is
uncertain. The Company charged to expense the remaining $472,000 receivable
balance in 1995.
Also, in 1995, the Company charged to expense receivables of $1,100,000
relating to the Bear Stearns Litigation. (See "Legal Proceedings").
During 1994, the Company made two personal loans of $62,500 and $300,000 to
an executive officer of the Company on an unsecured basis payable on the last
day of February and June 1995, respectively. The loan for $62,500, which was due
on February 28, 1995, was repaid in March 1995 and the $300,000 loan maturity
date was extended until December 31, 1995. The loan was not repaid when due on
December 31, 1995 and the Company recorded an allowance of $300,000 for this
note. The executive resigned from the Company in January 1995. The executive
officer filed for personal bankruptcy subsequent to December 1996.
Restructuring Charges. The Company incurred certain costs in connection
with its change in strategy and corporate structure. During 1995, the Company
incurred restructuring costs totaling $1,433,000 consisting primarily of the
write-off of approximately $1,000,000 in leasehold improvements related to the
relocation of the Company's operations from The Woodlands, Texas to Lafayette,
Louisiana, approximately $305,000 in severance costs related to staff reductions
and changes in senior management, and $145,000 in legal fees and other costs
directly related to the Company's Reorganization Case.
Implementation of SFAS No. 121. As previously discussed, the Company's
adoption of SFAS No. 121 effective December 31, 1995 resulted in the recognition
of a $103,266,000 impairment loss related to the Company's oil and gas
properties and other long-lived assets.
30
<PAGE> 31
As discussed above, the Company at December 31, 1995 recognized a
$3,591,000 liability related to its obligation to a joint venture under a
minimum production guarantee. See "Commitments and Contingencies -- Tricore
Energy Ventures, L.P."
Interest Expense. The increase in interest expense of $13,740,000, from
$19,000 for the year ended December 31, 1994 to $13,759,000 for the comparable
period in 1995, is due to borrowings under the Company's Credit Facility and the
Senior Notes issued in March 1995. Interest expense for 1995 also includes
$803,000 in interest incurred and the amortization of debt issuance costs
related to the $7,500,000 bridge loan executed in February 1995 in connection
with the purchase of the Initial LLOG Property which was repaid by the Company
in March 1995.
LIQUIDITY AND CAPITAL RESOURCES
Capital Requirements and Resources. While remaining a debtor-in-possession,
the Company limited its property acquisition, development and workover
activities, performing only those workovers approved under court supervision.
Commencing with the Effective Date of the Plan (July 11, 1997), the Company
commenced a program to increase production rates, lengthen the productive life
of wells and increase total proved reserves primarily through sidetracks out of
and recompletions of shut-in wells and installation of hydrocyclones on gas
wells producing large volumes of formation water. In addition, certain sidetrack
and development drilling locations have been identified that are expected to
improve reservoir drainage and increase the ultimate recovery of reserves.
Pursuant to this strategy, the Company will be required to make substantial
capital expenditures to fully develop its oil and gas reserves. The Company's
capital budget for 1997 is approximately $9,132,000. Funding for this capital
budget is anticipated to come primarily from cash flows from operations along
with net available proceeds from the Rights Offering of approximately
$1,597,000.
On the Effective Date, the Company received gross proceeds from the Rights
Offering of $13,300,000. Proceeds of this offering were used to pay the interest
and loan fees in connection with the INCC loan of $3,248,000, fund the
litigation trust called for in the Plan of $3,000,000, pay pre-petition claims
of $2,963,000 and pay administrative claims of $2,492,000, leaving $1,597,000
which provided additional working capital for the Company.
In addition, on the Effective Date, the Company exchanged $123,845,000 in
unsecured debt for 10,000,000 shares of New WRT stock and DLBW and Dublin
Acquisitions exchanged $9,293,000 of secured debt for 2,655,000 shares of New
WRT stock.
Operating Activities. Net cash provided by operating activities for the
year ended December 31, 1996 was $9,140,000 as compared to $6,259,000 for 1995.
This increase was due primarily to an increase in payables of approximately
$16,920,000. The increase in payables was due to the stay provided by the
Bankruptcy Court from the payment of any pre-petition payables and interest on
the Credit Facility.
Net cash provided by operating activities for the year ended December 31,
1995 was $6,259,000 as compared to net cash used in operating activities of
$4,916,000 for 1994. This increase was due to the significant increase in the
Company's trade payables in 1995 related to the increased level of field
operations during 1995 and subsequent liquidity constraints in the fourth
quarter of 1995.
Investing Activities. During 1996, the Company did not acquire any new oil
and gas properties, although $4,282,000 was incurred in development costs on its
existing acreage and approximately $539,000 was spent on other property and
equipment.
During 1995, the Company invested $116,730,000 in properties and equipment.
Approximately $86,000,000 was related to oil and gas property acquisitions. The
Company spent an additional $27,800,000 on its 1995 development program. This
program included approximately 70 well projects and significant expenditures
related to field infrastructure costs in the Company's Hackberry and West Cote
Blanche Bay fields.
Financing Activities. Commencing on February 14, 1996 (the filing date for
the Reorganization Case), no further interest was accrued related to the Senior
Notes. Furthermore, all interest and principal payments
31
<PAGE> 32
due on the Credit Facility were deferred until the Effective Date, at which time
the Credit Facility was repaid and a new $15,000,000 Credit Facility with ING
was established and is secured by substantially all of the Company's assets.
COMMITMENTS AND CONTINGENCIES
Tricore Energy Venture, L.P. Pursuant to a joint venture agreement dated
October 18, 1991 ("Joint Venture Agreement"), the Company entered into a joint
venture to develop certain oil and gas properties with Tricore Energy Venture,
L.P., a Texas limited partnership ("Tricore"). Under the terms of the Tricore
agreements, the Company has provided Tricore with a limited production guarantee
based on the minimum production schedule attached to the Tricore venture
agreement. The minimum production schedule assumes that Tricore's cumulative
share of the future gross production from jointly-owned properties will average
5,530 Mcf per day during the period between October 1, 1995 and September 30,
1996, 4,250 Mcf per day during the period between October 1, 1996 and September
30, 1997 and 2,350 Mcf per day during the period between October 1, 1997 and
September 30, 1998 and 699 Mcf per day during the period October 1, 1998 and
September 30, 1999. The minimum production also assumes that all future gas
production allocated to Tricore will be sold at a price of $1.50 per Mcf. As
long as either the actual volume of natural gas delivered or the gross revenue
allocated to Tricore exceeds the cumulative volumes reflected in the minimum
production schedule, the Company will have no current liability to Tricore under
the production guarantee. In the event that the cumulative volume of natural gas
delivered and the cumulative gross revenues allocated to Tricore are both less
than the values set forth in the minimum production schedule, the Company will
be obligated to compensate Tricore for the smaller of the two deficits by either
temporarily reducing its interest in the jointly-owned properties, delivering
additional gas to Tricore from other properties or issuing registered securities
of the Company that have a fair value equal to the value of the deficit.
As a result of significant production declines from jointly owned
properties, notably the Lac Blanc Exxon Fee #23 well, production for the period
commencing October 1, 1995 to September 30, 1996 did not exceed the minimum
required under the guarantee. In addition, due to the substantial reserve loss
incurred during 1995 and 1996, it is unlikely that the ultimate production
volumes or estimated future gross revenues from the joint venture wells will be
adequate over the remaining term of the guarantee. As a result, the Company has
recorded at December 31, 1996 and 1995 charges to accrue minimum production
guarantee obligations in the amounts of $5,555,000 and $3,591,000, respectively.
This liability recognizes at December 31, 1996 and 1995 the Company's ultimate
obligation to the joint venture, net of estimated production volumes and gross
revenues accruing to the joint venture based upon the Company's year-end
estimates of proved oil and gas reserves.
Pursuant to the terms of the production guarantee, if any of the gas
production from the joint venture properties qualifies for the nonconventional
fuels tax credit provided for by Internal Revenue Code Section 29, then 150% of
that tax credit shall be included in the calculation of gross revenues for
purposes of the guarantee. Based upon a certification by the DNR, a significant
amount of the production attributable to the joint venture qualified under
Section 107(c)(2) of the NGPA as gas produced from geopressured brine. As
required under the NGPA, the DNR's determination was forwarded to the FERC for
review. In April of 1995, the FERC reversed the position of the DNR, rejecting
the qualification of the wells under Section 107(c)(2) of the NGPA. The Company
appealed the FERC determination to the United States Court of Appeals for the
Fifth Circuit, located in New Orleans, Louisiana. The United States Court of
Appeals upheld the FERC position. Consequently, as of December 31, 1996, the
computation of the Company's minimum production payment guarantee did not take
into consideration any possible nonconventional fuels tax credits that may be
associated with the properties subject to the production payment. See "Legal
Proceedings."
As collateral for the Company's obligations under the production guarantee,
Tricore has asserted a security interest by virtue of partial assignments of
interests in the WCBB. These 4.68% working interests (3.72% NRI) assignments
were made subject to the terms and provisions of the Joint Venture Agreement
(the "Joint Venture Agreement"). Pursuant to the Joint Venture Agreement, on
December 1, 1996, the Company was obligated to provide the joint venture with an
annual operating report for the 12 months ended the previous September 30
detailing production volumes during the period. If the production during the
period
32
<PAGE> 33
was less than the minimum production levels required by the Joint Venture
Agreement, the Company was required to eliminate the annual production deficit
by delivering sufficient quantities of gas from other properties in twelve equal
monthly installments commencing December 1, 1996, or by the issuance to the
venture of registered debt or equity securities which have a fair market value
equal to the required payment. Upon satisfaction of the production guarantee,
Tricore was required to execute and deliver a release of the partial
assignments.
Pursuant to the Plan, as of the Effective Date, the Debtor rejected the
Joint Venture Agreement. Tricore filed a claim against the Debtor arising from
the production guaranty in an amount not to exceed $9,064,000, and asserted that
this claim (the "Tricore Claim") was secured by a lien on the Asserted
Collateral. Under the Plan, if the Tricore Claim is allowed as a claim secured
by the Asserted Collateral, New WRT may either pay to Tricore cash equal to the
amount of the Tricore Claim as allowed or transfer to Tricore title to the
Asserted Collateral. See "Item 3 -- Legal Proceedings". The Company is currently
negotiating a settlement with Tricore pursuant to their claim.
Lac Blanc Escrow Account. In connection with its purchase of a 91% working
interest in the Lac Blanc Field, the Company deposited $170,000 in a segregated
trust account and agreed to make additional deposits of $20,000 per month until
the accumulated balance of the trust account reaches $1,700,000. These funds
will be held in a segregated account for the benefit of the State of Louisiana
to insure that the wells in the Lac Blanc Field are properly plugged upon
cessation of production. In return for this financial commitment, the State has
granted the sellers an unconditional release from their contingent liability to
the state to plug and abandon the wells. When all existing wells in the Lac
Blanc Field have been properly plugged and abandoned, the funds in the trust
account, should any remain, will revert to the Company. Pursuant to the terms of
the escrow agreement between the Company and the State of Louisiana, if for any
reason the Company is unwilling or unable to plug and abandon the wells because
of insolvency or bankruptcy filing, the State, at its own discretion, may
utilize the funds in the escrow without notice to the Company for the obligation
related to the remaining wells located on the leases. At December 31, 1996 and
1995, the Company had on deposit $831,000 and $710,000, respectively, in this
account. Under the Plan, the Company will fund the unfunded portion of the
escrow and maintain future funding requirements.
Plugging and Abandonment Funds. The Company is contractually committed in
its purchase contracts for the Initial LLOG Property and Remaining LLOG
Properties to establish plugging and abandonment funds as allowed by Louisiana's
Orphaned Well Act. In connection with its bankruptcy case, LLOG filed a claim
asserting, inter alia, that the Debtor was required, notwithstanding the
bankruptcy case, to fulfill its contractual commitment to establish plugging and
abandonment funds (the "Asserted LLOG P&A Trusts"), and that LLOG had a vendor's
lien on the Initial LLOG Property and Remaining LLOG Properties securing the
Debtor's performance of the contractual commitment. The Debtor disputed LLOG's
claim and its asserted vendor's lien, and filed an objection seeking a
disallowance of LLOG's claim and a determination that any claim asserted by LLOG
with respect to the Asserted LLOG P&A Trusts was unsecured. On July 8, 1997, the
Bankruptcy Court ruled that LLOG's claim with respect to the Asserted LLOG P&A
Trusts was secured by a valid vendor's lien on the Initial LLOG Property and
Remaining LLOG Properties, but did not determine the amount of such claim. The
Debtor has filed a motion requesting that the Bankruptcy Court reconsider its
ruling. A hearing on the Debtor's motion is currently scheduled for November 25,
1997. Should the Debtor be unsuccessful in its defense of LLOG's claim with
respect to the Asserted LLOG P&A Trusts, New WRT will be required to establish
plugging and abandonment funds. The amount of and terms of payment into each
fund will be established by the State of Louisiana upon completion of an
independent study to be commissioned by the Company. As of December 31, 1996,
and of the date of this report, the independent study had not been completed,
and the Company is unable to determine the amount and payment towards the future
obligation related to these commitments.
Under the Plan, the Company will fund the unfunded portion of the escrow
and maintain future funding requirements.
33
<PAGE> 34
Texaco Global Settlement. Pursuant to the terms of a global settlement
between Texaco and the State of Louisiana which includes the State Lease No. 50
portion of the Company's East Hackberry Field, the Company is obligated to
commence a well or other qualifying development operation on certain non-
producing acreage in the field prior to March 1998. If the Company fails to meet
this obligation, it will be required by the State to surrender approximately 440
non-producing acres in the field.
Tri-Deck Oil and Gas Company. In connection with the Reorganization Case,
the Company filed a motion with the Bankruptcy Court to reject an oil and gas
marketing contract with Tri-Deck. The Bankruptcy Court authorized the rejection.
As of May 31,1996, Tri-Deck owed the Company approximately $4.3 million related
to several months gas production that was due and unpaid. Additionally, as of
May 31, 1996, approximately $290,000 (approximately $230,000 at December 31,
1995) related to the sale of natural gas liquids remained unpaid. The Company is
currently seeking to enforce payment of these overdue receivables through
proceedings initiated in the Bankruptcy Court.
34
<PAGE> 35
ITEM 8. FINANCIAL STATEMENTS AND SUPPORTING DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPORTING DATA
<TABLE>
<S> <C>
Independent Auditors' Report................................ F-2
Consolidated Balance Sheets, December 31, 1996 and 1995..... F-3
Consolidated Statements of Operations, Years Ended December
31, 1996, 1995 and 1994................................... F-4
Consolidated Statements of Shareholders' Equity, Years Ended
December 31, 1996, 1995
and 1994.................................................. F-5
Consolidated Statements of Cash Flows, Years Ended December
31, 1996, 1995 and 1994................................... F-6
Notes to Consolidated Financial Statements.................. F-8
</TABLE>
All financial statement schedules are omitted, as the required information is
inapplicable or the information is presented in the consolidated financial
statements or related notes.
F-1
<PAGE> 36
INDEPENDENT AUDITORS' REPORT
The Board of Directors
WRT Energy Corporation
We have audited the accompanying consolidated balance sheet of WRT Energy
Corporation and subsidiary (the Company) (a debtor-in-possession as of February
14, 1996) as of December 31, 1996 and 1995, and the related consolidated
statements of operations, shareholders' equity (deficit), and cash flows for
each of the years in the three-year period ended December 31, 1996. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of the Company
as of December 31, 1996 and 1995, and the results of its operations and its cash
flows for each of the years in the three-year period ended December 31, 1996, in
conformity with generally accepted accounting principles.
The accompanying consolidated financial statements have been prepared
assuming that the Company will continue as a going concern which contemplates
among other things, the realization of assets and liquidation of its liabilities
in the ordinary course of business. As discussed in Note 2 to the consolidated
financial statements, the Company's Plan of Reorganization was confirmed by the
bankruptcy court by order dated May 2, 1997 and is subject to certain material
conditions before its effective date. However, continuation of the Company as a
going concern and realization of its assets and liquidation of its liabilities
is dependent upon, among other things, the Company's ability to achieve
successful future operations. These matters raise substantial doubt about the
Company's ability to continue as a going concern. The consolidated financial
statements do not include any adjustments relating to the recoverability and
classification of reported asset amounts or the amounts and classification of
liabilities that might be necessary should the Company be unable to continue in
existence.
As discussed in Note 6 to the consolidated financial statements, the
Company has adopted the provisions of the Financial Accounting Standards Board's
Statements of Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," in
1995.
KPMG Peat Marwick LLP
Houston, Texas
July 3, 1997
F-2
<PAGE> 37
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
CONSOLIDATED BALANCE SHEET
DECEMBER 31, 1996 AND 1995
ASSETS
<TABLE>
<CAPTION>
1996 1995
------------- -------------
<S> <C> <C>
Current assets:
Cash and cash equivalents................................. $ 5,679,000 $ 1,608,000
Accounts receivable, net of allowance for doubtful
accounts of $4,966,000 and $448,000 for 1996 and 1995,
respectively........................................... 3,667,000 7,139,000
Prepaid expenses and other................................ 633,000 768,000
------------- -------------
9,979,000 9,515,000
Cash held in escrow......................................... 831,000 710,000
Property and equipment, net -- successful efforts method.... 56,899,000 63,913,000
Debt issuance costs, net.................................... 367,000 5,109,000
------------- -------------
$ 68,076,000 $ 79,247,000
============= =============
LIABILITIES AND SHAREHOLDERS' DEFICIT
Current liabilities:
Accounts payable and accrued liabilities.................. $ 5,529,000 $ 23,576,000
Pre-petition liabilities not subject to compromise........ 16,752,000 --
Pre-petition liabilities subject to compromise............ 136,346,000 --
Long-term debt in default................................. -- 113,949,000
Minimum production guarantee obligation................... -- 3,591,000
------------- -------------
158,627,000 141,116,000
Shareholders' deficit:
Preferred stock -- $.01 par value, 2,000,000 authorized,
1,265,000 issued and outstanding at December 31, 1996
and 1995, respectively................................. 27,677,000 27,677,000
Common stock -- $.01 par value, 50,000,000 authorized,
9,539,207 issued and outstanding at December 31, 1996
and 1995, respectively................................. 95,000 95,000
Paid-in capital........................................... 39,571,000 38,866,000
Accumulated deficit....................................... (157,562,000) (128,175,000)
Treasury stock (35,100 shares at December 31, 1996 and
1995).................................................. (332,000) (332,000)
------------- -------------
Total shareholders' deficit....................... (90,551,000) (61,869,000)
------------- -------------
Commitments and contingencies
$ 68,076,000 $ 79,247,000
============= =============
</TABLE>
See accompanying notes to consolidated financial statements.
F-3
<PAGE> 38
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
CONSOLIDATED STATEMENT OF OPERATIONS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
<TABLE>
<CAPTION>
1996 1995 1994
------------ ------------- -----------
<S> <C> <C> <C>
Revenues:
Gas sales...................................... $ 10,382,000 $ 11,747,000 $ 6,597,000
Oil and condensate sales....................... 13,637,000 12,908,000 4,437,000
------------ ------------- -----------
Total revenues......................... 24,019,000 24,655,000 11,034,000
Expenses:
Production costs............................... 13,304,000 9,534,000 3,077,000
Production taxes............................... 1,791,000 2,139,000 811,000
Depreciation, depletion and amortization....... 7,973,000 12,645,000 3,201,000
General and administrative expenses............ 3,210,000 4,882,000 3,037,000
Provision for doubtful accounts................ 5,158,000 2,007,000 --
Restructuring charges.......................... -- 1,433,000 --
Minimum production guarantee obligation........ 5,555,000 3,591,000 --
Impairment of long-lived assets................ 3,864,000 103,266,000 --
------------ ------------- -----------
40,855,000 139,497,000 10,126,000
------------ ------------- -----------
Income (loss) from operations.......... (16,836,000) (114,842,000) 908,000
Interest expense................................. 5,562,000 13,759,000 19,000
Gain on sale of oil and gas properties........... -- -- 3,033,000
Other income, net................................ 356,000 426,000 344,000
------------ ------------- -----------
Income (loss) before reorganization
costs and income taxes............... (22,042,000) (128,175,000) 4,266,000
Reorganization costs............................. 7,345,000 -- --
------------ ------------- -----------
Income (loss) before income taxes...... (29,387,000) (128,175,000) 4,266,000
Income tax expense............................... -- -- 36,000
------------ ------------- -----------
Net income (loss)........................... (29,387,000) (128,175,000) 4,230,000
Dividends on preferred stock (undeclared in
1996).......................................... (2,846,000) (2,846,000) (2,846,000)
------------ ------------- -----------
Net income (loss) available to common
shareholders.............................. $(32,233,000) $(131,021,000) $ 1,384,000
============ ============= ===========
Per common share:
Earnings (loss) per common and common
equivalent share............................ $ (3.38) $ (13.84) $ 0.18
============ ============= ===========
Average common and common equivalent shares
outstanding................................. 9,539,000 9,466,000 7,792,000
============ ============= ===========
</TABLE>
See accompanying notes to consolidated financial statements.
F-4
<PAGE> 39
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (DEFICIT)
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
<TABLE>
<CAPTION>
1996 1995 1994
------------- ------------- -----------
<S> <C> <C> <C>
Preferred stock................................... $ 27,677,000 $ 27,677,000 $27,677,000
Common stock:
Balance at beginning of year.................... 95,000 90,000 65,000
Issued to purchase oil and gas properties.... -- 2,000 18,000
Exercise of common stock options and
warrants................................... -- 6,000 7,000
Restricted common stock cancellation......... -- (3,000) --
------------- ------------- -----------
Balance at end of year.......................... 95,000 95,000 90,000
Paid-in-capital:
Balance at beginning of year.................... 38,866,000 38,516,000 21,426,000
Issued to purchase oil and gas properties.... -- 1,615,000 14,948,000
Exercise of common stock options and
warrants................................... -- 2,502,000 3,833,000
Cancellation of restricted stock plan........ -- (2,157,000) --
Issuance of warrants......................... -- 1,600,000 --
Reversal of preferred stock dividends
previously accrued......................... 712,000 -- --
Dividends on preferred stock (undeclared in
1996)...................................... -- (2,846,000) (1,691,000)
Other........................................ (7,000) (364,000) --
------------- ------------- -----------
Balance at end of year.......................... 39,571,000 38,866,000 38,516,000
Accumulated deficit:
Balance at beginning of year.................... (128,175,000) -- (3,075,000)
Net income (loss) before dividends on
preferred stock............................ (29,387,000) (128,175,000) 4,230,000
Dividends on preferred stock................. -- -- (1,155,000)
------------- ------------- -----------
Balance at end of year.......................... (157,562,000) (128,175,000) --
Deferred compensation:
Balance at beginning of year.................... -- (2,430,000) (2,700,000)
Amortization of restricted stock............. -- 270,000 270,000
Cancellation of restricted stock plan........ -- 2,160,000 --
------------- ------------- -----------
Balance at end of year.......................... -- -- (2,430,000)
Treasury stock:
Balance at beginning of year.................... (332,000) (315,000) --
Purchase of treasury stock................... -- (17,000) (1,568,000)
Issued to purchase oil and gas properties.... -- -- 1,253,000
------------- ------------- -----------
Balance at end of year.......................... (332,000) (332,000) (315,000)
------------- ------------- -----------
Shareholders' equity (deficit).................... $ (90,551,000) $ (61,869,000) $63,538,000
============= ============= ===========
</TABLE>
See accompanying notes to consolidated financial statements.
F-5
<PAGE> 40
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
CONSOLIDATED STATEMENT OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
<TABLE>
<CAPTION>
1996 1995 1994
------------ ------------- ------------
<S> <C> <C> <C>
Cash flow from operating activities:
Net income (loss)......................................... $(29,387,000) $(128,175,000) $ 4,230,000
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion, and amortization............... 7,973,000 12,645,000 3,201,000
Provision for doubtful accounts and notes receivable.... 5,158,000 2,007,000 --
Amortization of debt issuance costs..................... 909,000 759,000 --
Write-off of debt issuance costs and Senior Notes
discount.............................................. 5,263,000 -- --
Amortization of restricted stock........................ -- 270,000 270,000
Impairment of long-lived assets......................... 3,864,000 103,266,000 --
Write-off of leasehold improvements..................... -- 946,000 --
Gain on sale of oil and gas properties.................. (5,000) (3,000) (3,033,000)
Write-off of accounts receivable included in production
costs................................................. (1,172,000) -- --
Changes in operating assets and liabilities:
Accounts receivable..................................... (515,000) (2,249,000) (3,553,000)
Prepaid expenses and other.............................. 132,000 (349,000) (406,000)
Accounts payable and accrued liabilities................ (18,376,000) 13,551,000 4,207,000
Pre-petition liabilities subject to compromise.......... 28,236,000 -- --
Pre-petition liabilities not subject to compromise...... 1,505,000 -- --
Minimum production guarantee obligation................. 5,555,000 3,591,000 --
------------ ------------- ------------
Net cash provided by operating activities.......... 9,140,000 6,259,000 4,916,000
Cash flow from investing activities:
Decrease in notes and other receivables................... -- 69,000 333,000
Additions to cash held in escrow.......................... (121,000) (220,000) (240,000)
Additions to property and equipment....................... (4,823,000) (116,730,000) (40,087,000)
Proceeds from sale of oil and gas properties.............. 5,000 390,000 11,765,000
------------ ------------- ------------
Net cash used in investing activities.............. (4,939,000) (116,491,000) (28,229,000)
Cash flow from financing activities:
Proceeds from borrowings.................................. -- 126,141,000 7,000,000
Proceeds from issuance of warrants........................ -- 1,600,000 --
Debt issuance costs....................................... -- (5,722,000) --
Principal payments on borrowings.......................... (130,000) (19,603,000) (206,000)
Purchase of treasury stock................................ -- (17,000) (1,569,000)
Proceeds from option and warrant exercises................ -- 2,508,000 3,840,000
Common stock filing fees.................................. -- (120,000) --
Dividends on preferred stock.............................. -- (2,135,000) (2,135,000)
------------ ------------- ------------
Net cash (used in) provided by financing
activities....................................... (130,000) 102,652,000 6,930,000
Net increase (decrease) in cash and cash equivalents...... 4,071,000 (7,580,000) (16,383,000)
Cash and cash equivalents -- beginning of year............ 1,608,000 9,188,000 25,571,000
------------ ------------- ------------
Cash and cash equivalents -- end of year.................. $ 5,679,000 $ 1,608,000 $ 9,188,000
============ ============= ============
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Interest paid............................................. $ -- $ 8,232,000 $ 18,000
Income taxes paid......................................... -- 36,000 --
SUPPLEMENTAL INFORMATION OF NON-CASH INVESTING AND FINANCING
ACTIVITIES
Common stock issued to purchase oil and gas properties.... -- 1,617,000 14,966,000
Note receivable from sale of property and equipment....... -- 3,400,000 5,700,000
Reduction in drilling and workover rigs and marine
equipment notes receivable and related deferred gain.... -- 1,763,000 --
Accrued dividends on preferred stock...................... (712,000) 712,000 712,000
Treasury stock issued to purchase oil and gas
properties.............................................. -- -- 1,253,000
Deferred gain on sale of oil property and equipment....... -- -- (1,805,000)
</TABLE>
See accompanying notes to consolidated financial statements.
F-6
<PAGE> 41
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. DESCRIPTION OF BUSINESS
WRT Energy Corporation, a Texas corporation, and subsidiaries, are referred
to herein collectively as "WRT" or the "Company". The Company owns and operates
mature oil and gas properties in the Louisiana Gulf Coast area. The Company
seeks to increase both the current production and total oil and gas recovery
through the use of advanced technologies, including sophisticated radioactive
logging equipment owned by the Company and fluid separation technologies.
2. THE REORGANIZATION CASE
Chapter 11 Bankruptcy Filing
On February 14, 1996, ("Petition Date"), the Company filed a petition with
the Bankruptcy Court for the Western District of Louisiana ("Bankruptcy Court")
for protection under Chapter 11 of the Federal Bankruptcy Code. Such case is
referred to herein as the "Reorganization Case". Upon filing of the voluntary
petition for relief, the Company, as debtor-in-possession, was authorized to
operate its business for the benefit of claim holders and interest holders, and
has continued to do so, without objection or request for appointment of a
trustee. All debts of the Company as of the Petition Date are currently stayed
by the bankruptcy petition and subject to compromise pursuant to such
proceedings. The Company has operated its business and managed its assets in the
ordinary course as debtor-in-possession, and has obtained court approval for
transactions outside the ordinary course of business.
Plan of Reorganization
On October 22, 1996, the Company accepted and signed the proposal ("DLBW
Proposal") submitted by DLB Oil & Gas, Inc. ("DLB") and Wexford Management LLC
("Wexford"), on behalf of its affiliated investment funds, providing the terms
of a proposed capital investment in a plan of reorganization for the Company.
DLB and Wexford are collectively referred to herein as DLBW. The Company
subsequently obtained Bankruptcy Court approval of the expense reimbursement
provisions of the DLBW Proposal.
Subsequent to the Company's execution of the DLBW Proposal, DLB commenced
negotiations with Texaco Exploration and Production, Inc. ("TEPI") regarding,
(i) the claim asserted by TEPI against the Company and its affiliates ("Texaco
Claim"), (ii) the purchase of certain interests owned by TEPI in the West Cote
Blanche Bay Field ("WCBB Assets") and (iii) the Contract Area Operating
Agreement on the WCBB Assets and various other agreements relating thereto. As a
result of the negotiations, TEPI and DLB reached an agreement pursuant to which
DLB (i) agreed to purchase the Texaco Claim, (ii) as required by TEPI, agreed to
purchase the WCBB Assets from TEPI, and (iii) will guarantee ("P&A Guarantee")
the performance of all plugging and abandonment obligations related to both the
WCBB Assets and the Company's interests in West Cote Blanche Bay Field ("WCBB")
and, in order to implement the P&A Guarantee, will pay into a trust ("P&A
Trust") established for the benefit of the State of Louisiana, $1,000,000 on or
before the first date, no less than thirty days nor more than ninety days
following the confirmation date, on which (i) the confirmation order has been
stayed and (ii) the conditions to effectiveness have been satisfied (the
"Effective Date") and certain other amounts. This transaction closed on March
11, 1997.
On January 20, 1997, WRT and DLBW jointly filed the First Amended Joint
Plan of Reorganization ("Plan") and First Amended Disclosure Statement. The Plan
contemplates (i) the issuance to WRT's unsecured creditors, on account of their
allowed claims, an aggregate of 10 million shares of New WRT ("New WRT") Common
Stock, (ii) the issuance to WRT's unsecured creditors, on account of their
allowed claims, of the right to purchase an additional 3,800,000 of New WRT
Common Stock at a purchase price of $3.50 per share ("Rights Offering"), (iii)
the issuance to DLBW and affiliates of the number of shares of
F-7
<PAGE> 42
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
New WRT Common Stock obtained by dividing DLBW's allowed secured claim amount by
a purchase price of $3.50 per share, (iv) the purchase by DLBW of all shares of
New WRT Common Stock not otherwise purchased pursuant to the Rights Offering,
(v) the transfer by DLB of the WCBB Assets to New WRT along with the associated
P&A trust fund and associated funding obligation in exchange for 5,000,000
shares of New WRT Common Stock and in exchange the transfer by New WRT to TEPI
certain assets and non-producing acreage, and (vi) the funding by WRT of
$3,000,000 to an entity (the "Litigation Entity") to which WRT will transfer any
and all causes of action, claims, rights of actions, suits or proceedings which
have been or could be asserted by WRT except for (a) the action to recover
unpaid production proceeds payable to WRT by Tri-Deck Oil & Gas Company and (b)
the foreclosure action to recover title to certain assets (See Note 4 regarding
recovery of drilling and workover rigs). New WRT will own a 12% economic
interest in the Litigation Entity and the remainder of the economic interests in
the Litigation Entity will be allocated to unsecured creditors and DLBW based on
their ownership percentage of the 13.8 million shares to be distributed and
issued as described in (i) and (ii) above.
As a consequence of these transactions, upon the Effective Date of the
Plan, New WRT will own one hundred percent (100%) of the working interest in the
shallow contract area at WCBB. The proceeds from the Rights Offering will be
utilized to provide the cash necessary to satisfy Administrative and Priority
Claims, fund the Litigation Entity with $3,000,000 and provide New WRT with
working capital. New WRT will continue to conduct business and own and operate
the oil and gas properties. The Litigation Entity will pursue causes of action
assigned to it under the Plan. The beneficiaries of the Litigation Entity will
be unsecured creditors, DLBW and New WRT, which will own 12% of the Litigation
Entity.
By order dated May 2, 1997, the Bankruptcy Court confirmed WRT's Plan of
Reorganization, as amended. The effective date of the Plan was July 11, 1997.
WRT's financial statements will reflect fresh-start reporting, as defined by the
Accounting Standards Division of the American Institute of Certified Public
Accountants Statement of Position Number 90-7, "Financial Reporting by Entities
in Reorganization Under the Bankruptcy Code" ("SOP 90-7"), as of the effective
date when all material conditions precedent to the Plan became binding. Under
SOP 90-7, the reorganization value, or enterprise value, of the entity is
allocated to the entity's assets in conformity with the purchase method
described in Accounting Principles Board ("APB") Opinion No. 16, "Business
Combinations." Upon the effective date, New WRT allocated the actual
reorganization value to the entity's assets.
An unaudited pro forma condensed balance sheet reflecting the anticipated
fresh start reporting had the Plan become effective on December 31, 1996 is as
follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1996
------------------------------------------------------------
PROFORMA (UNAUDITED)
HISTORICAL ADJUSTMENTS PROFORMA
------------ ------------- -----------
<S> <C> <C> <C> <C>
Cash................................... $ 5,679,000 $ 3,855,000 d,e,f,g,i,j $ 9,534,000
Accounts receivable, net............... 3,667,000 -- 3,667,000
Other current assets................... 633,000 -- 633,000
------------ ------------- -----------
Total current assets......... 9,979,000 3,855,000 13,834,000
------------ ------------- -----------
Property and equipment, net............ 56,899,000 14,152,000 a,c 71,051,000
------------ ------------- -----------
Other assets........................... 1,198,000 20,000 e 1,218,000
------------ ------------- -----------
$ 68,076,000 $ 18,027,000 $86,103,000
============ ============= ===========
Current liabilities.................... $158,627,000 $(154,807,000) d,e,g,h,j $ 3,820,000
------------ ------------- -----------
Long-term debt......................... -- 15,000,000 e 15,000,000
------------ ------------- -----------
Stockholders' equity (deficit)......... (90,551,000) 157,834,000 a,b,c,f,g,h,i 67,283,000
------------ ------------- -----------
$ 68,076,000 $ 18,027,000 $86,103,000
============ ============= ===========
</TABLE>
F-8
<PAGE> 43
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The condensed unaudited pro forma balance sheet is not necessarily
indicative of the actual fresh start balance sheet as of the Effective Date.
Assumptions used in the preparation of this unaudited pro forma balance sheet
are as follows:
a. To adjust oil and gas properties and other property and equipment to fair
market value in accordance with SOP 90-7.
b. All of the currently outstanding preferred stock, common stock, paid-in
capital and treasury stock were canceled, resulting in a decrease in equity
of $65,659,000.
c. The Company issued 5,000,000 shares of New WRT stock in exchange for oil and
gas properties valued at $13,500,000.
d. The INCC note of $15,000,000 was paid in full, including unpaid interest
accrued through December 31, 1996 of $1,593,000.
e. Financing was recorded from ING in the amount of $15,000,000 less $187,000
in loan fees which were deducted from the loan proceeds and $200,000 in loan
fees which are due in two annual installments of $100,000 each.
Additionally, $367,000 of debt issuance costs related to the INCC note were
written-off.
f. Stock rights offerings in the amount of $13,300,000 were recorded
reflecting the issuance of 3,800,000 additional shares at $3.50 per share.
g. Priority and secured claims in the amount of $13,105,000 were exchanged for
2,681,000 shares of stock and $3,720,000 in cash.
h. Unsecured claims in the amount of $124,364,000 were exchanged for 10,000,000
shares of New WRT.
i. Establishment of a litigation trust in the amount of $3,000,000.
j. Payment of administrative claims in the amount of $945,000.
3. SIGNIFICANT ACCOUNTING POLICIES
Going Concern Considerations
The accompanying financial statements of the Company have been prepared on
a going concern basis, which contemplates the realization of assets and the
liquidation of liabilities in the ordinary course of business. As described in
Note 2 above, the Company filed for reorganization under Chapter 11 of the
United States Bankruptcy Code. The consolidated financial statements do not
include any adjustments relating to recoverability and classification of
reported asset amounts or the amounts and classification of liabilities that
might result from the ultimate resolution of the Plan of Reorganization.
On the Effective Date of the Plan of Reorganization, the Company will
utilize fresh-start reporting in accordance with the requirements of SOP 90-7.
The application of SOP 90-7 will result in the creation of a new reporting
entity for financial purposes having no retained earnings or accumulated
deficit.
Consolidation
The consolidated financial statements include the accounts of WRT Energy
Corporation and its wholly-owned subsidiary, WRT Technologies, Inc. Until
December 31, 1995, WRT owned 100% of the stock of two subsidiaries, Tesla
Resources, Inc. ("Tesla") and Southern Petroleum, Inc. ("Southern Petroleum").
On that date, both Tesla and Southern Petroleum were merged into WRT with WRT
emerging as the sole surviving corporation. In November 1995, WRT formed a
wholly-owned subsidiary, WRT Technologies, Inc., which was established to own
and operate WRT's proprietary, radioactive, cased-hole logging technology. As of
F-9
<PAGE> 44
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
December 31, 1996, WRT Technologies, Inc. held only immaterial assets and had no
operating activities. All significant intercompany transactions have been
eliminated.
Cash and Cash Equivalents
The Company considers all highly liquid investments with an original
maturity of three months or less to be cash equivalents for purposes of the
statement of cash flow.
Fair Value of Financial Instruments
Cash, accounts receivable and accounts payable and accrued liabilities
approximate fair value due to the short-term maturity of these financial
instruments.
Due to their nature, pre-petition liabilities not subject to compromise and
pre-petition liabilities subject to compromise do not have reasonably
estimatable fair values.
At December 31, 1995, the fair value of the Company's long-term debt in
default, approximately $50,000,000, was estimated based on quoted market prices
for the Senior Notes (defined herein), and based on the principle balance
outstanding for the Credit Facility (defined herein), because it bears interest
rates that adjust to market rates.
Depreciation and Amortization
The Company provides for depreciation and amortization on the straight-line
basis as follows:
<TABLE>
<S> <C>
Office equipment............................................ 5-10 years
Shop equipment.............................................. 3-5 years
Field and wireline equipment................................ 5-15 years
</TABLE>
Oil and Gas Operations
The Company follows the successful efforts method of accounting for its oil
and gas operations. Under the successful efforts method, costs of productive
wells, development dry holes and productive leases are capitalized and amortized
on a unit-of-production basis over the life of the remaining proved reserves.
The Company's estimate of future dismantlement and abandonment costs has been
considered in computing the aforementioned amortization.
Cost centers for amortization purposes are determined based on a reasonable
aggregation of properties with common geological structures or stratigraphic
conditions, such as a reservoir or field. The Company performs a review for
impairment of proved oil and gas properties on a depletable unit basis when
circumstances suggest the need for such a review. For each depletable unit
determined to be impaired, an impairment loss equal to the difference between
the carrying value and the fair value of the depletable unit will be recognized.
Fair value, on a depletable unit basis, is estimated to be the present value of
expected future net cash flows computed by applying estimated future oil and gas
prices, as determined by management, to estimated future production of oil and
gas reserves over the economic lives of the reserves.
Exploration expenses, including geological, geophysical and costs of
carrying and retaining undeveloped properties are charged to expense as
incurred.
Unproved properties are assessed periodically and a loss is recognized to
the extent, if any, that the cost of the property has been impaired. If proved
reserves are not discovered within one year after drilling is completed, costs
are charged to expense.
F-10
<PAGE> 45
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Earnings (Loss) per Share
Earnings (loss) per share computations are calculated on the
weighted-average of common shares and common share equivalents outstanding
during the year. Common stock options and warrants are considered to be common
share equivalents and are used to calculate earnings per common and common
equivalent share except when they are anti-dilutive.
Income Taxes
The Company uses the asset and liability method of accounting for income
taxes. Under the asset and liability method, deferred tax assets and liabilities
are recognized for the future tax consequences attributable to differences
between the financial statement carrying amounts and the tax bases of existing
assets and liabilities and operating loss and tax credit carryforwards. Deferred
income tax assets and liabilities are based on enacted tax rates applicable to
the future period when those temporary differences are expected to be recovered
or settled. The effect of a change in tax rates on deferred tax assets and
liabilities is recognized in income in the period the rate change is enacted.
Revenue Recognition
Natural gas revenues are recorded in the month produced using the
entitlement method, whereby any production volumes received in excess of the
Company's ownership percentage in the property are recorded as a liability. If
less than the Company's entitlement is received, the underproduction is recorded
as a receivable. Oil revenues are recognized in the month produced.
Concentrations of Credit Risk
The Company operates in the oil and natural gas industry with sales to
refineries, re-sellers such as pipeline companies, and local distribution
companies. While certain of these customers are affected by periodic downturns
in the economy in general or in their specific segment of the natural gas
industry, the Company believes that its level of credit-related losses due to
such economic fluctuations has been immaterial and will continue to be
immaterial to the Company's results of operations in the long term. Unrelated to
economic fluctuations, during 1996, the Company incurred a bad debt in the
amount of $4,278,000 related to marketing of its oil and gas by Tri-Deck Oil &
Gas Company ("Tri-Deck"). See Notes 5 and 18 for further discussion.
During the years ended December 31, 1996, 1995 and 1994, approximately 89%,
79% and 52%, respectively, of the Company's revenues from oil and natural gas
sales were attributable to sales to five primary customers: Tri-Deck, Plains
Marketing and Transportation, Inc., Texas-Ohio Gas, Inc., Riverside Pipeline
Company and Prior Energy.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates, judgments
and assumptions that affect the reported amounts of assets and liabilities as of
the date of the financial statements and revenues and expenses during the
reporting period. The financial statements are highly dependent on oil and gas
reserve estimates which are inherently imprecise. Actual results could differ
from those estimates.
Stock Options
As more fully described in Note 13, the Company has various employee and
outside director stock option plans outstanding at December 31, 1996. Statement
of Financial Accounting Standards ("SFAS") No. 123
F-11
<PAGE> 46
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
"Accounting for Stock-Based Compensation" ("SFAS No. 123"), issued in October
1995, allows a company to adopt a fair value based method of accounting for its
stock-based compensation plans, or to continue to follow the intrinsic value
method of accounting prescribed by APB Opinion No. 25 "Accounting for Stock
Issued to Employees", in accounting for its stock option plans. In accordance
with APB Opinion No. 25, compensation costs are not recognized in the Company's
fixed stock option plans.
The Company has elected to continue to apply APB Opinion No. 25 in
accounting for its granted stock options and accordingly, no compensation cost
has been recognized for the fair value of stock options granted to employees and
outside directors in the financial statements. Had the Company recognized
compensation cost based on the fair value at the grant date for its stock
options under SFAS No. 123, the Company's net loss would have been increased to
the pro forma amounts indicated in the table below. The pro forma amounts shown
below do not include the effects of stock options granted prior to January 1,
1995. The pro forma net loss reflects only options granted in 1995, as no
options were granted in 1996. The per share weighted average fair value of stock
options granted during 1995 was $4.34 on the date of grant using the Black
Scholes option-pricing model with the following assumptions: expected dividend
yield 0%, risk free interest rate of 6.85% and 6.04% for the grants dated April
13, 1995 and September 1, 1995, respectively, expected volatility of 90.4% and
an expected life of five years. The full impact of compensation cost for stock
options under SFAS No. 123 is not reflected in the pro forma net loss amounts
presented below because compensation cost is reflected over the option vesting
period of five years.
<TABLE>
<CAPTION>
1996 1995
------------ -------------
<S> <C> <C>
Net loss --
As reported.......................................... $(32,233,000) $(131,021,000)
Pro forma............................................ $(32,831,000) $(131,749,000)
Net loss per share --
As reported.......................................... $ (3.38) $ (13.84)
Pro forma............................................ $ (3.44) $ (13.92)
</TABLE>
The Company's stock options have no estimated fair value at December 31,
1996, as under the Company's proposed Plan, the holders of WRT stock options
will receive no distribution and their rights will be extinguished.
Commitments and Contingencies
Liabilities for loss contingencies arising from claims, assessments,
litigation or other sources are recorded when it is probable that a liability
has been incurred and the amount can be reasonably estimated.
In October 1996, the American Institute of Certified Public Accountants
issued SOP 96-1, "Environmental Remediation Liabilities." SOP 96-1 was adopted
by the Company on January 1, 1997. It requires, among other things, that
environmental remediation liabilities be accrued when the criteria of SFAS No.
5, "Accounting for Contingencies," have been met. SOP 96-1 also provides
guidance with respect to the measurement of the remediation liabilities. Such
accounting is consistent with the Company's method of accounting for
environmental remediation costs. Therefore, adoption of SOP 96-1 will not have a
material impact on the Company's financial position or results of operations.
F-12
<PAGE> 47
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
4. PROPERTY AND EQUIPMENT
The major categories of property and equipment and related accumulated
depreciation, depletion and amortization as of December 31, 1996 and 1995 are as
follows:
<TABLE>
<CAPTION>
1996 1995
------------ ------------
<S> <C> <C>
Oil and gas properties.................................. $ 77,541,000 $ 75,609,000
Equipment............................................... 2,954,000 3,312,000
Office furniture and fixtures........................... 1,669,000 2,297,000
Building................................................ 235,000 236,000
Land.................................................... 260,000 263,000
------------ ------------
Total property and equipment............................ 82,659,000 81,717,000
Accumulated depreciation, depletion and amortization.... (25,760,000) (17,804,000)
------------ ------------
Property and equipment, net............................. $ 56,899,000 $ 63,913,000
============ ============
</TABLE>
In December 1994, the Company sold four drilling and workover rigs,
obtained in connection with certain oil and gas property acquisitions, to an oil
field service contractor for a total consideration of $3,900,000. The purchaser
gave a 6% secured promissory note in exchange. No gain or loss was recognized at
the date of the sale. The $1,000,000 gain on the sale was deferred and was being
realized over the life of the note. Concerns about the ability of the purchaser
to perform pursuant to the terms of the contract resulted in the Company
reversing the deferred gain in September 1995. At December 31, 1995, the related
note receivable was canceled. The Company has hired counsel and currently is
seeking to recover the collateral securing these notes.
In December 1994 and May 1995, the Company sold to the same oil field
service contractor marine and oil field service equipment for a total
consideration of $5,200,000. The purchaser gave two 6% secured promissory notes
in exchange. No gain or loss was recognized at the date of the sale. The
$800,000 gain on the sale was deferred and was being realized over the life of
the notes. Concerns about the ability of the purchaser to perform pursuant to
the terms of the contracts resulted in the Company reversing in September 1995
the deferred gain. At December 31, 1995, the two related promissory notes were
fully canceled. The Company has hired counsel and is currently seeking to
recover the collateral securing these notes.
5. PROVISION FOR DOUBTFUL RECEIVABLES
The Company has recorded provisions for certain receivables in which
collectibility is uncertain as follows:
In April 1995, the Company allegedly entered into a marketing agreement
with Tri-Deck pursuant to which Tri-Deck would market all of the Company's oil
and natural gas production. Subsequent to the agreement, Tri-Deck's principal,
James Florence, who was also serving as WRT's Director of Marketing, assigned to
Plains Marketing its right to market the Company's oil production and entered
into a contract with Perry Oil and Gas to market the Company's gas production.
During the early stages of the Company's Reorganization Case, Tri-Deck failed to
make payments to the Company attributable to several months of the Company's gas
production. Due to the uncertainty of the amount that will be recovered from
Tri-Deck, the Company has recorded an allowance for this receivable in the
amount of $4,278,000. Of this amount, approximately $1,700,000 related to the
receivable from Tri-Deck for the purchase of WRT's April and May, 1996 gas
production and has been deposited into a depository account with the Bankruptcy
Court's registry. See Note 18 for further details.
F-13
<PAGE> 48
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company has a long-term receivable, recovery of which is made in the
form of a production payment from the oil and gas revenues in certain Company
operated oil and gas properties. The most significant well underlying the
production payment ceased production during the third quarter of 1995 due to
mechanical failure of the well bore. As a result, the ultimate recovery of the
remaining receivable is uncertain. The Company wrote-off the remaining $472,000
receivable balance in 1995.
During 1994, the Company made two personal loans of $62,500 and $300,000 to
an executive officer of the Company on an unsecured basis payable on the last
day of February and June 1995, respectively. The loan for $62,500 was repaid in
March 1995 and the $300,000 loan maturity date was extended until December 31,
1995. The loan was not repaid when due on December 31, 1995 and the Company has
recorded an allowance of $300,000 for this note. The executive resigned from the
Company in January 1995. The executive officer filed for personal debt
protection subsequent to December 1996.
6. IMPAIRMENT OF LONG-LIVED ASSETS AND NOTES RECEIVABLE
Effective December 31, 1995, the Company adopted SFAS No. 121 which
requires that an impairment loss be recognized whenever the carrying amount of a
long-lived asset exceeds the sum of the estimated future cash flows
(undiscounted) of the asset. For each long-lived asset determined to be
impaired, an impairment loss equal to the difference between the carrying value
and the fair value of the asset is recognized. During 1995, the Company recorded
a non-cash charge of $103,266,000 in connection with the adoption of this new
accounting standard of which approximately $95,000,000 was related to the
impairment of oil and gas properties, the result of significant downward
revisions in the Company's proved oil and gas reserves at December 31, 1995. At
December 31, 1996, the Company incurred an additional non-cash charge of
$2,545,000 related to the further impairment of its oil and gas properties as
well as the impairment of some of its field equipment. Principal fields
suffering further impairment in value in 1996 were the Abbeville Field, the Lac
Blanc Field, and the West Hackberry Field as a result of additional downward
revisions in the proved oil and gas reserves at December 31, 1996.
The Company also recorded non-cash charges related to certain rig, marine
and field equipment owned or securing notes receivable. The Company originally
expected this equipment would provide drilling and field services in the
Company's oil and gas development program. Due to liquidity problems and the
reduced level of development activity, the Company did not expect to utilize
these assets in the near term and, accordingly, recovery of the related carrying
cost was deemed unlikely. As a result of the adoption of SFAS No. 121, the
Company recorded an impairment of $7,900,000 related to this equipment in 1995.
During 1996, the Company incurred an additional non-cash charge of $1,319,000
related to the further impairment of its office and field equipment. Of this
balance, $815,000 relates primarily to a write down of the Company's office
equipment and computer hardware and software to its appraised fair value, and
the balance of $504,000 relates to a write-down of the wire-line equipment to
its appraised fair value.
7. RESTRUCTURING CHARGES AND REORGANIZATION COSTS
The Company incurred certain restructuring costs in connection with its
change in strategy and corporate structure. For the year ended 1995, these costs
consisted primarily of the write-off of approximately $1,000,000 in leasehold
improvements related to the relocation of the Company's operations from The
Woodlands, Texas, approximately $300,000 in severance costs related to staff
reductions and changes in senior management and $100,000 in legal fees and other
costs directly related to the Company's Reorganization Case.
During 1996, the Company incurred $7,345,000 in reorganization costs,
primarily consisting of professional fees totaling $2,594,000 and the write-off
of previously capitalized debt issuance costs on the Senior Notes (herein
defined) in the amount of $3,834,000.
F-14
<PAGE> 49
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. OIL AND GAS PROPERTY ACQUISITIONS
Initial LLOG Property Acquisition
In December 1994, the Company entered into a definitive agreement with LLOG
Exploration Company ("LLOG") for the purchase of LLOG's working interest in the
Bayou Penchant Field ("Initial LLOG Property"). The Company concluded the
acquisition of the Initial LLOG Property in late January 1995 for a purchase
price of approximately $15,600,000 plus a nonrefundable deposit of $5,000,000
towards the purchase from LLOG of certain additional oil and gas properties,
described below. The approximately $20,600,000 paid to LLOG was financed by
borrowings of $15,000,000 under the Company's Credit Facility, and by the
issuance to LLOG of a short-term, promissory note for approximately $5,600,000
("Seller Financing Note"). In early February 1995, the Company refinanced the
Seller Financing Note from the proceeds of a $7,500,000 bridge loan ("Bridge
Loan").
Remaining LLOG Properties Acquisition
In December 1994, the Company and LLOG also entered into a letter of intent
for the purchase by the Company of a second group of oil and gas properties
owned by LLOG ("Remaining LLOG Properties"). Separate purchase contracts for
each of the Remaining LLOG Properties were entered into in January 1995. The
Company concluded the acquisition of the Remaining LLOG Properties in early
March 1995 for an aggregate purchase price of approximately $46,400,000, less
the $5,000,000 nonrefundable deposit previously paid to LLOG in connection with
the Company's acquisition of the Initial LLOG Property. The approximate
$41,400,000 paid to LLOG was financed through offering of the Senior Notes in
March 1995 as more fully described in Note 9.
The Remaining LLOG Properties consist of working interests in four south
Louisiana oil and gas fields: the Bayou Pigeon Field, the Deer Island Field, the
Abbeville Field, and the Golden Meadow Field. The Company owns a 100% working
interest in substantially all acreage comprising the Remaining LLOG Properties,
other than the Abbeville Field in which it owns approximately 70% of the working
interest. However, during 1996 a title dispute arose related to certain acreage
in the Bayou Pigeon Field. See "Title to Oil and Gas Properties" in Note 18 for
further discussion. The Company is the operator of the Initial LLOG Property and
the Remaining LLOG Properties.
West Cote Blanche Bay Field Acquisition
In January 1995, the Company entered into an agreement in principle with an
affiliate of Benton Oil and Gas Company and two affiliates of Tenneco, Inc., to
purchase an additional 43.75% working interest in the West Cote Blanche Bay
Field, a property in which the Company previously owned a 6.25% working
interest. The agreement in principle contemplated that the sellers retain their
interests in all depths below an average of approximately 10,500 feet. The
purchase price for the additional interests in the West Cote Blanche Bay Field
was approximately $20,000,000. The purchase was completed in April 1995. On
March 11, 1997, in connection with the Plan, DLB executed definitive
documentation with TEPI related to the West Cote Blanche Bay Field, whereby DLB
(i) acquired the claim asserted by TEPI against WRT (ii) acquired the remaining
50% working interest in the reservoirs above 10,500 feet in the West Cote
Blanche Bay Field, and (iii) assumed certain operational and plugging and
abandonment obligations related to the WCBB Assets. At the second closing, which
is expected to occur on the Effective Date of the Plan, DLB will transfer the
WCBB Assets to New WRT in exchange for five million (5,000,000) shares of New
WRT Common Stock and the assumption by New WRT of certain plugging and
abandonment obligations related to the West Cote Blanche Bay Field.
F-15
<PAGE> 50
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Napoleonville Field
In December 1994, the Company purchased a 100% working interest
(approximately 75% net revenue interest) in leases covering approximately 300
acres in the Napoleonville Field for a purchase price of $9.8 million which was
paid by the issuance of 1,300,000 shares of the Company's common stock
During 1995, the Company purchased for approximately $1.2 million and
$600,000, respectively, certain additional leasehold acreage in the
Napoleonville Field and saltwater disposal facilities from BSFI Western E&P,
Inc. ("BSFI"). At the time of the purchase, BSFI, as a 5.5% common shareholder
of the Company, was a related party. In connection with the purchase, the
parties also effected the settlement of a potential dispute between BSFI and the
Company related to an assertion by BSFI that the Company allegedly failed to
timely register for resale of the 1,300,000 common shares issued to purchase the
Napoleonville Field.
9. LONG-TERM DEBT
<TABLE>
<CAPTION>
1995
------------
<S> <C>
Long-term debt in default:
Credit Facility........................................... $ 15,000,000
Other long-term debt...................................... 377,000
Senior Notes.............................................. 98,572,000
------------
$113,949,000
============
</TABLE>
Credit Facility
In December 1994, the Company entered into a $40,000,000 credit facility
with International Nederlanden (U.S.) Capital Corporation ("INCC") ("Credit
Facility") that is secured by substantially all of the Company's assets. At
December 31, 1996 and 1995, WRT has borrowings outstanding of $15,000,000, the
maximum amount of borrowings available under the Credit Facility. At December
31, 1995, the revolving loan borrowings were converted to a term loan whereby
quarterly principal payments of one-sixteenth of the outstanding indebtedness
were due and payable. Amounts outstanding under the Credit Facility bear
interest at an annual rate selected by the Company of either (i) the London
Inter-Bank offered rate ("LIBOR") plus 3%, or (ii) the Lender's prime lending
rate plus 1.25%. The estimated fair value of the Company's indebtedness under
its Credit Facility approximates the principal balance outstanding, as the
facility bears interest at rates tied to market rates and is secured by
substantially all of the Company's assets.
At December 31, 1996 and 1995, the Company was in default under certain
financial covenants of the Credit Facility. Accordingly, the Company has
classified the debt as current at December 31, 1996 and 1995. While in
bankruptcy, INCC is stayed from enforcing certain remedies provided for in the
credit agreement and the indenture. The Company, pursuant to an order of the
Bankruptcy Court, did not make the scheduled interest payment of $400,000 to
INCC on February 28, 1996, nor has the Company made any interest payments since
that date. At December 31, 1996, accrued interest related to the credit facility
was $1,593,000. In addition, the Company did not make the first scheduled
principal payment of $900,000 due on the Credit Facility on March 31, 1996, nor
has the Company made any other principal payments on this Credit Facility since
that date.
DLBW and ING (U.S.) Capital Corporation (successor to INCC) ("ING") have
reached an agreement in principle providing for the consensual treatment of
INCC's claim and for availability of a new loan to New WRT in the amount of
$15,000,000. The agreement remains subject to the completion of definitive
documentation, corporate approvals and certain other conditions.
F-16
<PAGE> 51
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13 7/8% Senior Note Offering
In February 1995, the Company offered 100,000 Units consisting of
$100,000,000 aggregate principal amount of 13 7/8% Senior Notes and warrants
("Warrants") to purchase an aggregate of 800,000 shares of the Company's Common
Stock ("Offering"). The net proceeds from the Offering were used to acquire the
Remaining LLOG Properties, to repay the Bridge Loan and substantially all
borrowings under the Credit Facility, to acquire an additional working interest
in the West Cote Blanche Bay Field and for general corporate purposes.
The Senior Notes are redeemable at the option of the Company in whole or in
part, at any time on or after March 1, 2000. Prior to March 1, 1998, up to
$35,000,000 of the aggregate principal amount of the Senior Notes will be
redeemable at the option of the Company from the net proceeds of any public
offering of Common Stock of the Company at 113.5% of the principal amount
thereof, plus accrued interest.
The Senior Notes are senior unsecured obligations of the Company ranking
senior in right of payment to any subordinated indebtedness of the Company, and
pari passu with the existing and future senior indebtedness of the Company. The
Senior Notes and the Warrants are separately transferable. The Warrants became
exercisable on June 1, 1995. Each Warrant entitles the holder thereof to
purchase from the Company one share of Common Stock at a price of $8.00 per
share. Unexercised Warrants will expire on March 1, 2000. See Note 12 regarding
the warrants.
The Senior Notes were issued under an indenture ("Indenture"), and such
Indenture contains certain covenants that, among other things, limit (i) the
incurrence of additional indebtedness; (ii) the payment of dividends or making
of certain other restricted payments; (iii) the incurrence of liens; (iv) the
disposition of subsidiary stock; (v) transactions with affiliates; (vi) certain
sale and leaseback arrangements; (vii) investments; (viii) guarantees of
indebtedness by subsidiaries; (ix) the imposition of restrictions on the
subsidiaries' ability to make distributions to the Company; and (x) mergers,
consolidations and transfers of assets. WRT was not in compliance with the
provisions of the Indenture at December 31, 1996 and 1995. Accordingly, the
Company has classified the debt as current at December 31, 1996 and 1995. See
Note 10 for further details regarding the treatment of this claim in the Plan.
The Company, pursuant to an order of the Bankruptcy court, did not make the
scheduled interest payment of $6,938,000 on March 1, 1996, nor has the Company
made any interest payments since that date. In accordance with SOP 90-7, the
Company has not recorded interest expense on the Senior Notes subsequent to the
Petition Date. At December 31, 1996, interest accrued related to the Senior
Notes was $6,359,000. Had the Company accrued interest on the Senior Notes for
the period subsequent to the Petition Date through December 31, 1996, an
additional $12,141,000 of interest expense would have been recorded as of
December 31, 1996.
10. DESCRIPTION OF THE PLAN RELATING TO CLAIMS
By order dated May 2, 1997, the Bankruptcy Court confirmed WRT's (and
DLBW's) second amended joint Plan of Reorganization. Pursuant to the Plan, all
liabilities incurred prior to the filing for bankruptcy are classified as
pre-petition liabilities. Accordingly, pre-petition liabilities are separately
identified on the accompanying balance sheet. Pre-petition liabilities not
subject to compromise in the amount of $16,752,000 will (a) be paid in cash to
the full amount of the claim or to the extent of collateral, (b) be paid in
stock of New WRT at the amount of the claim divided by $3.50 per share, or (c)
allowed priority tax claims will be paid in full in deferred cash payments in
equal quarterly payments through the end of year 2001 with interest at a rate of
LIBOR plus 2%. Pre-petition liabilities subject to compromise in the amount of
$136,346,000 will be satisfied in the form of either (a) a cash payment of 50%
of the allowed claim (for claims equal to or less that $2,500 in amount) or (b)
a pro rata share of the 10,000,000 shares of New WRT Common Stock and the
F-17
<PAGE> 52
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
right to participate in the Rights Offering of 3,800,000 shares of New WRT
common stock at $3.50 per common share (for claims in excess of $2,500). All
preferred and common shareholder claims will extinguish under the Plan. All
warrants and stock options are extinguished under the Plan.
With respect to all claim related liabilities recorded in the accompanying
balance sheet, such claims have been recorded in accordance with SFAS No.5,
"Accounting for Contingencies," which dictates that the loss contingencies be
accrued through a charge to income when (a) it is probable that a liability has
been incurred at the financial statement date and (b) the amount of the
liability can be reasonably estimated. Loss contingencies that do not meet these
conditions are disclosed when the Company believes there is a reasonable
possibility that a loss may have been incurred.
As of December 31, 1996, the Company had disputed claims for which the
Bankruptcy Court has not made a final determination as to the ultimate
liability, if any, of the Company. The Company has accrued certain amounts
related to these disputed claims in its financial statements as of December 31,
1996 which are probable that a liability has been incurred and the amount of
such liability can be reasonably estimated. The ultimate resolution of the
claims will be reflected in the future financial statements as they are settled,
and could vary significantly from the amounts accrued at December 31, 1996.
11. PREFERRED AND COMMON STOCK OFFERINGS
Public Offering of Preferred Stock
On October 27, 1993, the Company completed its public offering of 1,265,000
shares of 9% Convertible Preferred Stock ("Preferred Stock") at a price of $25
per share. The offering resulted in cash proceeds to the Company of $27,700,000,
net of underwriting fees, commissions and offering costs. The proceeds of the
offering were used to purchase additional oil and gas properties, to conduct oil
and gas property development, to develop and fabricate logging tools and for
general purposes.
The Preferred Stock has a liquidation preference of $25 per share and is
convertible, at the option of the holder, into 2.083 shares of the Company's
common stock. Commencing on October 20, 1994, if the last reported sales price
of the common stock equals or exceeds $15.60 per share for ten consecutive
trading days, the Preferred Stock will convert automatically into common stock.
No shares were converted under this provision, as the last reported sales price
of the common stock did not equal or exceed $15.60 per share for ten consecutive
trading days. The Preferred Stock was not redeemable before October 20, 1995.
Dividends on the Preferred Stock will accrue and are cumulative from October 20,
1993, and are payable quarterly in arrears when declared by the Board of
Directors. The Company was precluded under the terms of the Senior Note
Indenture and Credit Facility from declaring any dividends during 1996. As a
result of this and the bankruptcy proceedings, the Company did not accrue
dividends payable on its Preferred Stock during 1996. In addition, accrued and
unpaid Preferred Stock dividends at December 31, 1995 have been reversed in the
1996 financial statements. See Note 10 for treatment under the Plan of
Reorganization.
12. COMMON STOCK WARRANTS
As a result of various public and private common and preferred stock and
senior notes offerings, litigation settlements and oil and gas property
acquisitions, the Company had 1,149,167 and 1,699,167 common stock warrants
outstanding as of December 31, 1996 and 1995, respectively, for the right to
purchase the Company's common stock at prices ranging from $6.45 to $14.40 per
share.
Under the Company's Plan, the holders of WRT warrants will receive no
distribution and their rights will be extinguished; therefore, the WRT warrants
have no estimated fair value at December 31, 1996.
F-18
<PAGE> 53
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
13. STOCK OPTION AND STOCK GRANT PLANS
Between 1991 and 1995, the Company issued stock options to its employees
and outside directors. As of December 31, 1996 and 1995, 1,781,450 and 2,056,450
options, respectively, were outstanding with exercise prices ranging from $2.00
to $11.00 per common share. All of the aforementioned options either have
expired due to the termination of employment of the employee or director or will
be canceled as a result of the Plan.
Additionally, in December 1993, the Company's shareholders approved a grant
of an aggregate of 300,000 shares of restricted stock ("Restricted Stock") to
the Company's four incumbent executive officers ("Restricted Stock Grant"). The
Restricted Stock vested at a rate of 10% per year commencing on January 15,
1995. The Restricted Stock shares were subject to forfeiture restrictions and
could not be sold, transferred or disposed of during the restriction period.
During 1994, one executive officer's employment with the Company terminated
prior to the vesting of any of his stock, and, pursuant to the terms of the
Restricted Stock Grant, his 60,000 shares were reallocated among the remaining
original three executive officers. Similarly, in February 1995, another
executive officer's employment with the Company terminated prior to the vesting
of any of his stock, and, pursuant to the terms of the Restricted Stock Grant,
his 75,000 shares were reallocated among the remaining original two executive
officers. During 1995 and 1994, the Company recorded to general and
administrative expense $270,000 related to the amortization of this deferred
compensation plan.
The Restricted Stock Grant was terminated by the Company's Board of
Directors on November 10, 1995. The two remaining participants were paid $90,000
and $18,000, respectively, for the cancellation of 225,000 and 48,750 shares
beneficially owned. The Company recorded $108,000 in compensation expense in
1995 related to the termination of the plan.
Changes in options outstanding under the various employee, executive and
director plans described above for the years ended December 31, 1996, 1995 and
1994 are summarized as follows:
<TABLE>
<CAPTION>
NON-QUALIFIED WEIGHTED AVERAGE
STOCK OPTIONS EXERCISE PRICE
-------------------------- --------------------------
OUTSTANDING EXERCISABLE OUTSTANDING EXERCISABLE
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
December 31, 1993................... 692,000 427,000 $5.39 $4.58
Granted........................... 1,690,000 1,070,500 6.23 6.34
Became exercisable................ -- -- -- --
Exercised......................... (289,550) (289,550) 5.50 5.50
Canceled or expired............... (2,000) (2,000) 3.00 3.00
--------- --------- ----- -----
December 31, 1994................... 2,090,450 1,205,950 $6.05 $5.92
Granted........................... 550,000 165,000 6.69 6.69
Became exercisable................ -- 519,800 -- 7.00
Exercised......................... (509,000) (509,000) 4.01 4.01
Canceled or expired............... (75,000) (75,000) 6.69 6.69
--------- --------- ----- -----
December 31, 1995................... 2,056,450 1,306,750 $6.70 $7.15
Granted........................... -- -- -- --
Became exercisable................ -- 320,750 -- 5.91
Exercised......................... -- -- -- --
Canceled or expired............... (275,000) (275,000) 6.69 6.69
--------- --------- ----- -----
December 31, 1996................... 1,781,450 1,352,500 $6.71 $6.95
========= ========= ===== =====
</TABLE>
F-19
<PAGE> 54
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. INCOME TAXES
The Company's income tax expense consists of the following:
<TABLE>
<CAPTION>
1996 1995 1994
------- ------- -------
<S> <C> <C> <C>
Current........................................... $ -- $ -- $36,000
Deferred.......................................... -- -- --
------- ------- -------
Total................................... $ -- $ -- $36,000
======= ======= =======
</TABLE>
A reconciliation of the statutory federal income tax amount to the recorded
expense follows:
<TABLE>
<CAPTION>
1996 1995 1994
------------ ------------- ----------
<S> <C> <C> <C>
Income (loss) before federal income tax... $(29,387,000) $(128,175,000) $4,266,000
Expected income tax (benefit) at
statutory rate.......................... (10,285,000) (44,861,000) 1,451,000
Valuation allowance....................... 9,358,000 44,977,000 (557,000)
Tax deduction in excess of book for stock
options exercised....................... -- (144,000) (677,000)
Net operating loss carryforward
utilized................................ -- -- (190,000)
Reorganization costs...................... 923,000 -- --
Other..................................... 4,000 28,000 9,000
------------ ------------- ----------
Income tax expense recorded............... $ -- $ -- $ 36,000
------------ ------------- ----------
</TABLE>
The tax effects of temporary differences and net operating loss carry
forwards, which give rise to deferred tax assets (liabilities) at December 31,
1996 and 1995, respectively, are as follows:
<TABLE>
<CAPTION>
1996 1995
------------ ------------
<S> <C> <C>
Net operating loss carry forward........................ $ 19,002,000 $ 10,350,000
Oil and gas property bases differences.................. 28,971,000 34,042,000
Other................................................... 6,702,000 957,000
------------ ------------
Total gross deferred tax asset.......................... 54,675,000 45,349,000
Valuation allowance..................................... (54,607,000) (45,269,000)
------------ ------------
Deferred tax asset...................................... 68,000 80,000
------------ ------------
Other................................................... (68,000) (80,000)
------------ ------------
Deferred tax liability.................................. (68,000) (80,000)
------------ ------------
Net deferred tax asset (liability)...................... $ -- $ --
============ ============
</TABLE>
The Company has available tax net operating loss carry forwards of
approximately $54,292,000 as of December 31, 1996. These carry forwards expire
in varying annual amounts during the years 2006 through 2011. Prior to the
Effective Date of the Plan, the Company does not believe that it is more likely
than not that the net operating loss carry forward and other deferred tax assets
are likely to be utilized prior to their expiration. As such, at December 31,
1996 the Company has recorded a valuation allowance for its net deferred tax
assets in the amount of $54,607,000.
F-20
<PAGE> 55
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
15. EARNINGS (LOSS) PER SHARE
The following schedule summarizes the calculation of earnings (loss) per
common and common stock equivalent, assuming the exercise of the outstanding
Common Stock options and warrants to purchase Common Stock, using the modified
treasury stock method except in those periods when the inclusion of options and
warrants is anti-dilutive.
<TABLE>
<CAPTION>
1996 1995 1994
------------ ------------- -----------
<S> <C> <C> <C>
Net income (loss) before dividends on
Preferred Stock........................ $(29,387,000) $(128,175,000) $ 4,230,000
Dividends on Preferred Stock............. (2,846,000) (2,846,000) (2,846,000)
------------ ------------- -----------
Total income (loss) available to common
shareholders........................... $(32,233,000) $(131,021,000) $ 1,384,000
============ ============= ===========
Average common shares outstanding........ 9,539,000 9,466,000 7,392,000
Common stock equivalents................. -- -- 400,000
------------ ------------- -----------
9,539,000 9,466,000 7,792,000
============ ============= ===========
Earnings (loss) per common and common
stock equivalent....................... $ (3.38) $ (13.84) $ 0.18
============ ============= ===========
</TABLE>
16. JOINT VENTURE AGREEMENT
By a Joint Venture Agreement dated October 18, 1991, the Company entered
into a joint venture to develop certain oil and gas properties with Tricore
Energy Venture, L.P., a Texas limited partnership ("Tricore") and Stag Energy
Corporation ("Stag").
Under the terms of the Tricore agreements Tricore contributes the
capitalization required to complete the development of selected prospects, and
Stag and the Company contribute, or arrange for contribution of, the prospects
to be developed.
The allocation of the net income, profits, credits, gains and losses of the
joint venture are distributed as follows:
<TABLE>
<CAPTION>
INITIAL ONGOING
ALLOCATION ALLOCATION
---------- ----------
<S> <C> <C>
Tricore.......................................... 70% 55%
WRT.............................................. 25% 35%
Stag............................................. 5% 10%
</TABLE>
The distributions will convert from the initial to the ongoing allocation
upon Tricore receiving aggregate distributions equal to 125% of its initial
contributions to the joint venture.
In March 1995, the Company contributed the K.G. Wilbert No. 1 well, located
in Iberville Parish, Louisiana, the Atkinson No. 2 well, located in Hayes Field
in Jefferson Davis Parish, Louisiana and State Lease 8396 #1 and #2 wells,
located in South Atchafalaya Bay Field in St. Mary Parish, Louisiana, to the
joint venture and received $867,850 as compensation for the recompletion and
field services rendered. The cash received was a recovery of costs incurred, and
no field service revenues were recognized.
In July 1994, the Company contributed a portion of its interest in the
Exxon Fee #23 well, located in Lac Blanc Field in Vermilion Parish, to the joint
venture and received $1,200,000 as compensation for the
F-21
<PAGE> 56
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
recompletion of the well. The cash received was a recovery of costs incurred and
no field service revenues were recognized.
In March 1993, the Company contributed the Delcambre No. 1 well, located in
Tigre Lagoon Field in Vermilion Parish, Louisiana and the Summers No. 1 well
located in North Rowan Field in Brazoria County, Texas, to the joint venture and
received $2,000,000 as compensation for recompletion and wireline services
rendered. The cash received was a recovery of costs incurred, and no field
service revenues related to the recompletion and wireline services rendered were
recognized.
In March 1992, Tricore paid the Company $1,300,000 for the turnkey
development of the Delcambre A-2 well located in Tigre Lagoon Field in Vermilion
Parish, Louisiana. The Company used the funds to recover the costs of drilling
the well and as compensation for wireline services rendered. The Company
recognized field service revenues to the extent that cash received exceeded its
costs in the property, however, no field service revenue was recorded related to
the initial 25% joint venture interest received.
The Company has provided Tricore with a limited production guarantee based
on the minimum production schedule attached to the Tricore joint venture
agreement. The minimum production schedule assumes that Tricore's cumulative
share of the future gross production from jointly-owned properties will average
4,250 Mcf per day during the period between October 1, 1996 and September 30,
1997, 2,350 Mcf per day during the period October 1, 1997 and September 30,
1998, and 699 Mcf per day during the period October 1, 1998 and September 30,
1999. The minimum production also assumes that all future gas production
allocated to Tricore will be sold at a price of $1.50 per Mcf. As long as either
the actual volume of natural gas delivered or the gross revenue allocated to
Tricore exceeds the cumulative values reflected in the minimum production
schedule, the Company will have no current liability to Tricore under the
production guarantee. Pursuant to the Joint Venture Agreement, if the production
during any annual period, commencing October 1 through September 30, is less
than the minimum production levels required by the Joint Venture Agreement, the
Company is required to eliminate the annual production deficit by delivering
sufficient quantities of gas from other properties in twelve equal monthly
installments, commencing the following December 1, or by the issuance to the
venture of registered debt or equity securities which have a fair market value
equal to the required payment. As collateral for the Company's obligations under
the production guarantee, Tricore holds a partial assignment of an interest in
the West Cote Blanche Bay Field. This 4.68% working interest (3.72% net revenue
interest) assignment, was made subject to the terms and provisions of the Joint
Venture Agreement. Upon satisfaction of the production guarantee, Tricore is
required to execute and deliver a release of the partial assignment.
As a result of significant production declines from jointly-owned
properties, notably the Exxon Fee #23 well, production did not currently exceed
the minimum required under the guarantee for the period commencing October 1,
1995 to September 30, 1996. In addition, due to the substantial reserve losses
incurred during 1995 and 1996, the estimated future gross revenues from the
joint venture wells are not adequate over the remaining term of the guarantee.
As a result, the Company has recorded in 1996 and 1995, minimum production
guarantee charges of $5,555,000 and $3,591,000, respectively. The $9,146,000
liability recognized at December 31, 1996 represents the Company's estimated
ultimate obligation to the joint venture, including the disallowance of certain
tax credits as discussed below.
Pursuant to the terms of the production guarantee, if any of the gas
production from joint venture properties qualifies for the nonconventional fuels
tax credit provided for by Internal Revenue Code Section 29, then 150% of that
tax credit shall be included in the calculation of gross revenues for purposes
of the guarantee. Based upon a certification by the Louisiana Department of
Natural Resources ("DNR"), a significant amount of the production attributable
to the joint venture qualified under Section 107(c)(2) of the Natural Gas Policy
Act of 1978 (the "NGPA") as gas produced from geopressured brine. As required
under the NGPA, the DNR's determination was forwarded to the FERC for review. In
April 1995, the FERC
F-22
<PAGE> 57
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
reversed the position of the DNR, rejecting the qualification of the wells under
Section 107(c)(2) of the NGPA. The Company appealed the FERC determination to
the United States Court of Appeals for the Fifth Circuit, located in New
Orleans, Louisiana. In February 1997, the United States Court of Appeals for the
Fifth Circuit affirmed the FERC's determination.
On January 14, 1997, the Company initiated an adversary proceeding to
obtain a declaration of the invalidity of the security interests or liens
securing Tricore's asserted Secured Claim of "up to $9,224,000" or alternatively
for avoidance of such security interests or liens pursuant to Sections 544 and
547 of the Bankruptcy Code. Such suit is pending as of this date. On March 7,
1997, the Company also filed an objection to the asserted Claim of Tricore (i)
under Section 502(d) of the Bankruptcy Code seeking to disallow such asserted
Claim in full on the grounds that Tricore is the transferee of a transfer
available under Sections 544 and 547 of the Bankruptcy Code, and (ii) under
Section 502(c) of the Bankruptcy Code seeking to estimate such asserted Claim on
the grounds that it is a contingent claim the liquidation of which would unduly
delay the administration of the Reorganization Case. On June 19, 1997, Tricore
filed an amendment to reduce their proof of claim to $9,064,000 from $9,224,000.
Nevertheless, to the extent that Tricore is determined to be a secured claim,
the Plan provides for the claim to be paid in full. The Company is currently
negotiating a settlement with Tricore pursuant to their claim. See Note 18 for
further discussion.
17. COMMITMENTS
Leases
As of December 31, 1996, the Company had no long-term, non-cancelable
operating lease commitments. Rental expense for all operating leases for the
years ended December 31, 1996, 1995 and 1994 was $207,000, $482,000 and
$364,000, respectively.
During 1996, the Company terminated its office lease covering approximately
24,000 square feet in The Woodlands, Texas. The lessor asserted a secured claim
in connection with the Company's reorganization case in the amount of $250,000
and an unsecured claim in the amount of $127,000, attributable to rental
obligations and lease rejection damages associated with such lease. On April 22,
1997, the Bankruptcy Court granted the claimant an allowed secured claim of
$118,000 and an allowed unsecured claim in the amount of $150,000.
Lac Blanc Escrow Account
In connection with its purchase of a 91% working interest in the Lac Blanc
Field, the Company deposited $170,000 in a segregated trust account and agreed
to make additional deposits of $20,000 per month until the accumulated balance
of the trust account reaches $1,700,000. These funds are held in a segregated
account for the benefit of the State of Louisiana to insure that the wells in
the Lac Blanc Field are properly plugged upon cessation of production. In return
for this financial commitment, the State has granted the sellers an
unconditional release from their contingent liability to the state to plug and
abandon the wells. When all existing wells in the Lac Blanc Field have been
properly plugged and abandoned, the funds in the trust account, should any
remain, will revert to the Company. Due to the filing of the Reorganization Case
in June 1996, the Company ceased contributions to the segregated account. At
December 31, 1996, the Company had deposited $831,000 in this account.
Under the Plan, the Company will fund the unfunded portion of the escrow
and maintain future funding requirements.
F-23
<PAGE> 58
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Plugging and Abandonment Funds
The Company is contractually committed in its purchase contracts for the
Initial LLOG Property and Remaining LLOG Properties to establish plugging and
abandonment funds as allowed by Louisiana's Orphaned Well Act. The amount of and
terms of payment into each fund will be established by the State of Louisiana
upon completion of an independent study to be commissioned by the Company. As of
December 31, 1996, the independent study has not been completed. Accordingly,
the Company is unable to determine the amount and payment towards the future
obligation related to these commitments.
Under the Plan, the Company will fund the unfunded portion of the escrow
and maintain future funding requirements.
Texaco Global Settlement.
Pursuant to the terms of a global settlement between Texaco and the State
of Louisiana which includes the State Lease No. 50 portion of the Company's East
Hackberry Field, the Company is obligated to commence a well or other qualifying
development operation on certain non-producing acreage in the field prior to
March 1998. If the Company fails to meet this obligation, it will be required by
the State to surrender approximately 440 non-producing acres in the field.
Reimbursement of Employee Expenses & Contributions to 401(k) Plan
The Company sponsors a 401(k) savings plan under which eligible employees
may choose to save up to 15% of salary income on a pre-tax basis, subject to
certain IRS limits. At December 31, 1996, the Company is matching employee
contributions with 25% cash contributions. During 1996, 1995 and 1994, the
Company incurred $12,000, $22,000, and $26,000, respectively, in matching
contributions expense associated with this plan.
On or about March 26, 1996, the Company filed a Motion for Authority to Pay
Pre-Petition Reimbursable Employee Expenses and Employer Matching Contributions
to the 401(k) Plan, requesting that it be permitted to reimburse pre-petition
employee expenses and to make matching 401(k) plan contributions which had
fallen due pre-petition, collectively in amounts not to exceed $4,000 per
person, the amount which would be allowable as a priority expense in bankruptcy.
On April 30, 1996, the Bankruptcy Court entered an Order Authorizing Payment of
Pre-Petition Reimbursable Employee Expenses and Employer Matching Contributions
to the 401(k) Plan.
Stay Bonus
The Company's Board of Directors determined that it was necessary to
provide a "stay bonus" to facilitate retention of employees during the
Reorganization Case in view of the uncertainties of the future of the Company.
The policy, approved by the Board, was to provide (1) certain designated "key"
employees with a stay bonus of 50% of salary earned subsequent to the Petition
Date, limited to a maximum of six months salary; and (2) non-"key" employees
with a stay bonus of 25% of salary earned subsequent to the Petition Date,
limited to maximum of three months' salary. A condition precedent to the receipt
of such bonus is continued employment through confirmation or a sale of a
substantial portion of the Company's properties, unless permitted otherwise by
order of the Bankruptcy Court under extenuating circumstances. On November 6,
1996, the Bankruptcy Court entered an Order Authorizing Company to Provide
Employment "Stay Bonus" to Employees. The Company accrued $614,000 for these
stay bonuses as of December 31, 1996. The stay bonuses were subsequently paid in
June 1997.
F-24
<PAGE> 59
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
18. CONTINGENCIES
Bear Stearns Litigation
On December 10, 1992, the Company, one of its executives, a former
executive and others instituted a lawsuit against Bear, Stearns & Co. Inc.
("Bear Stearns"), Drake Capital Securities, Inc. ("Drake"), Steven Antebi
("Antebi") and Jerry Friedman ("Friedman") in the District Court of Harris
County, Texas 133rd Judicial District. After settling with Drake and Friedman,
the plaintiffs commenced trial on February 28, 1995. On March 21, 1995, the jury
returned a verdict in favor of the Company and five of the Company's
shareholders against Antebi for approximately $1,100,000. Pursuant to the jury
verdict, advice of outside counsel and management's belief that recovery of its
legal fees was probable, the Company recorded as a receivable approximately
$1,100,000 of costs incurred in connection with the litigation. The Company,
however, considered the jury verdict to be insufficient. Accordingly, the
Company requested, and on August 4, 1995 was granted, a new trial. Absent the
jury verdict from the original trial, and considering the uncertainty regarding
the timing of possible recovery in a new trial, the Company and its outside
counsel concluded that they could no longer consider the recovery of the
receivable to be probable. Therefore, the Company recorded a provision for this
receivable in the third quarter of 1995. Prior to commencement of the new trial,
the case went to mediation and was settled on February 16, 1996 for $600,000
plus court costs of approximately $69,000, subject to the approval of the
Bankruptcy Court. Consequently on April 22, 1996, WRT filed a Motion for
Authority to Compromise the Bear Stearns Litigation, requesting that the
settlement be approved and that the distribution of proceeds generated therefrom
be authorized to the respective parties to the Litigation pursuant to the
Settlement Agreement reached. Due to objections raised as to the distribution of
the Bear Stearns Litigation Proceeds, the Bankruptcy Court approved the
Settlement Agreement but instructed that a subsequent Motion be provided to
resolve the issue of disposition of the proceeds. As a result, on August 27,
1996, WRT filed a Motion for Authorization to finally settle distribution of the
Bear Stearns Litigation Proceeds. On September 10, 1996, the Bankruptcy Court
approved such Motion and the proceeds have since been distributed accordingly,
including the distribution of approximately $145,000 to WRT, which was recorded
as Other Income for the year ended December 31, 1996. Settlement funds of
$154,000 attributable to one of the Company's former executives has been held in
escrow, pending final resolution of claims of the bankruptcy estates, if any,
against the former executive.
Tri-Deck/Perry Gas Litigation
During 1995, the Company entered into a marketing agreement with Tri-Deck
Oil and Gas Company ("Tri-Deck") pursuant to which Tri-Deck would market all of
WRT's oil and gas production. Subsequent to the agreement, Tri-Deck's principal
and WRT's Director of Marketing, James Florence, assigned to Plains Marketing
its right to market WRT's oil production and assigned to Perry Oil & Gas its
right to market WRT's gas production. During early 1996, Tri-Deck failed to make
payments to WRT attributable to several months of WRT's gas production.
Consequently, the Company responded in two ways. First, on May 20, 1996, the
Company filed a Motion to Reject the Tri-Deck Marketing Agreement. Second, on
May 29, 1996, the Company initiated an adversary proceeding against Tri-Deck and
Perry Oil and Gas ("Perry Gas"). Perry Gas was the party which ultimately
purchased the Company's gas production for the months in question.
With respect to the Motion to Reject, the Bankruptcy Court authorized the
rejection and directed Tri-Deck and WRT to determine the amount of production
proceeds attributable to WRT's June gas production which are payable to WRT.
Consequently, Perry Gas thereafter made payment to WRT of the June gas proceeds
less $75,000 for a set-off claim by Perry Gas, which is subject to further
consideration by the Bankruptcy Court.
Next, with respect to the adversary proceeding, WRT sought turnover by
Tri-Deck and/or Perry Gas of all unpaid production proceeds payable to WRT under
the marketing agreement and the issuance of a
F-25
<PAGE> 60
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
temporary restraining order and preliminary injunction against both parties to
prevent further disposition of such proceeds pending outcome of the proceedings.
On May 31, 1996 the Bankruptcy Court entered a consensual temporary restraining
order against both Tri-Deck and Perry Gas. On June 18, 1996, a Preliminary
Injunction was entered by the Court which required Perry Gas to segregate into a
separate depository account the funds due for the purchase of WRT's April and
May 1996 gas production from Tri-Deck. Subsequently, upon motion by WRT the
Court ordered such funds to be placed into the Bankruptcy Court's registry, as
Perry Gas had made certain withdrawals from the separate depository account
without authorization by the Court. Currently, funds in the amount of
approximately $1,700,000 remain in the registry of the Court. Additionally, a
dispute exists between WRT and Perry Gas as to additional funds owed by Perry
Gas for the purchase of WRT's April and May 1996 gas production. Currently, the
adversary proceeding remains pending as to the ultimate issue of ownership of
proceeds. Tri-Deck has also filed an answer and counterclaim in which Tri-Deck
is asserting, among other items, damages for tortious interference of its
contractual relationships with others. Recovery of the $1,700,000 receivable is
dependent on the court rendering a favorable ruling on the issue. As of the date
of the report, the court has not ruled on this issue. Although management
believes that Tri-Deck's claim to the funds in the registry of the court is
invalid, and the aforementioned counterclaim is without merit, for financial
reporting purposes the receivable from Tri-Deck was fully reserved for as of
December 31, 1996. See also Notes 3, 5, and 19.
Tricore Litigation
On January 14, 1997, WRT initiated an adversary proceeding to obtain a
declaration of the invalidity of the security interests or liens allegedly
securing Tricore Energy Venture, LP's (Tricore's) asserted secured claim of "up
to $9,064,000," (as amended) or alternatively for avoidance of such security
interests or liens
pursuant to Sections 544 and 547 of the Bankruptcy Code. See further explanation
regarding Tricore at Note 16, "Joint Venture Agreement". Such suit is pending as
of the date of this report. On March 7, 1997, the Company also filed an
objection to both the allowance and amount of Tricore's claim. The Company is
currently negotiating a settlement with Tricore pursuant to their claim.
Employment Litigation
On September 28, 1995, a lawsuit was served against the Company, Arnoult
Equipment and Construction, Inc., Steven S. McGuire, Donald J. Arnoult and
others in the 24th Judicial District Court for the Parish of Jefferson, State of
Louisiana. The plaintiff, the former president, chief executive officer and
stockholder in certain oil field service companies used by the Company filed
with the court exceptions of no cause of action, no right of action and
vagueness. The Company's filing of the Reorganization Case has resulted in an
automatic stay of this litigation. The Company believed the case to be without
merit and that the outcome of the litigation would not have had a material
effect on its financial condition or results of operations. On June 6, 1997, the
Bankruptcy Court disallowed this lawsuit in full.
Securities Litigation
On December 18 and 19, 1995, two class-action suits were filed in the
United States District Court for the Southern District of California, seeking
damages on behalf of a purported class of persons who purchased the
publicly-traded securities of the Company between October 20, 1993 and October
27, 1995. In these complaints, the plaintiffs have sued the Company, certain of
its Board of Directors, certain of its officers and others, alleging joint and
several liability for violations of Section 12(2) and Section 15 of the
Securities Act of 1933. The plaintiffs also complain that all defendants
violated Section 10(b) of the Securities Exchange Act of 1934 and Rule 10(b)(5)
of the Securities Exchange Commission. The individual defendants are alleged to
be liable under Section 20(a) of the Securities Exchange Act of 1934. On
February 23, 1996, a Notice of Stay by reason of the Company's bankruptcy was
filed in both actions. On March 21, 1996, all
F-26
<PAGE> 61
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
parties entered into a Stipulation whereby plaintiffs agreed to consolidate the
two actions under an amended and consolidated complaint. On June 1, 1996, by
agreement of all parties, the case was transferred to the Southern District of
New York. This case is currently pending in the courts of the Southern District
of New York. On April 28, 1997 the Bankruptcy Court disallowed this lawsuit in
full as it relates to the Company. As a result of the Bankruptcy Court's
disallowance of this lawsuit, the litigation will not have an effect on the
Company's financial condition or results of operations.
Title to Oil and Gas Properties
During 1996, WRT received notice from a third party claiming that WRT's
title has failed as to approximately 43 acres in the Bayou Pigeon Field. Some or
all of the acreage in dispute is considered to be productive in three separate
production units. Under the assumption that WRT's title is flawed, WRT's working
interest in three units may be reduced to approximately 7% (5% Net Revenue
Interest, ("NRI") 75% (63% NRI), and 95% (72% NRI). The financial statements as
of and for the years ended December 31, 1996 and 1995, reflect operating results
and proved reserves discounted for this possible title failure. As the title
failure predates its ownership of the field, WRT is currently evaluating its
recourse
against the predecessors-in-title relative to this issue. The Company is
currently negotiating a settlement with the Third Party, pursuant to their
claim.
Other
Other unasserted claims against the Company may be alleged as a result of
the Plan of Reorganization. Management cannot estimate the impact of such
unasserted claims on the consolidated financial statements at December 31, 1996.
19. EXAMINER'S REPORT
On August 13, 1996, the Bankruptcy Court executed and entered its Order
Appointing Examiner directing the United States Trustee to appoint a
disinterested person as examiner in the Company's bankruptcy case.
The Court ordered the appointed examiner ("Examiner") to file a report "of
the investigation conducted, including any fact ascertained by the examiner
pertaining to fraud, dishonesty, incompetence, misconduct, mismanagement or
irregularity in the management of the affairs of the Company".
Additionally, the Examiner investigated insider transactions involving
current and former officers of the Company, the Company's purchase of oil and
gas properties in the Napoleonville Field, the purchase of leases in the South
Hackberry and East Hackberry Fields, transactions related to the purchase and
sale of certain workover rigs and marine equipment and related contracts, the
marketing of the Company's oil and gas production, claims acquisition by an
investment company and transactions with a certain joint venture partner. The
Examiner's final report dated April 2, 1997 recommends numerous actions for
recovery of property or damages for the Company's estate which appear to exist
and should be pursued. Management does not believe the resolution of the matters
referred to in the Examiner's report will have a material impact on the
Company's consolidated financial statements or results of operations.
Pursuant to the Company's Plan, all of the Company's possible causes of
action against third parties (with the exception of certain litigation related
to recovery of marine and rig equipment assets and Tri-Deck), existing as of the
effective date of the Plan, will be transferred into a "Litigation Trust"
controlled by an independent party for the benefit of most of the Company's
existing unsecured creditors. (The Company retains a 12% interest in the trust,
net of Trustee Fees and expenses). Currently, management is aggressively
pursuing those claims and causes of action against Tri-Deck and Perry Gas
relating to the recovery of revenues
F-27
<PAGE> 62
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
for the sale of oil and gas production. See notes 5 and 18 for additional
information. In addition, the company has instituted legal action to recover the
aforementioned marine and rig equipment assets. See Note 4 for further details.
The Company has not recognized the potential value of recoveries which may
ultimately be obtained, if any, as a result of such causes of action, or
possible future actions, in the accompanying consolidated financial statements.
20. SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION
ACTIVITIES (UNAUDITED)
The following is historical revenue and cost information relating to the
Company's oil and gas operations located entirely in the southeastern United
States:
Capitalized Costs Related to Oil and Gas Producing Activities
<TABLE>
<CAPTION>
1996 1995
------------ ------------
<S> <C> <C>
Proved Properties........................................ $ 77,541,000 $ 75,609,000
Accumulated depreciation, depletion and amortization..... (23,401,000) (16,153,000)
------------ ------------
Proved properties, net................................... $ 54,140,000 $ 59,456,000
============ ============
</TABLE>
Costs Incurred in Oil and Gas Property Acquisition and Development Activities
<TABLE>
<CAPTION>
1996 1995 1994
---------- ------------ -----------
<S> <C> <C> <C>
Acquisition.................................. $ -- $ 87,379,000 $25,823,000
Development.................................. 4,282,000 27,225,000 21,216,000
---------- ------------ -----------
Total........................................ $4,282,000 $114,604,000 $47,039,000
========== ============ ===========
</TABLE>
Results of Operations for Producing Activities
The following schedule sets forth the revenues and expenses related to the
production and sale of oil and gas. The income tax expense is calculated by
applying the current statutory tax rates to the revenues after deducting costs,
which include depreciation, depletion and amortization allowances, after giving
effect to the permanent differences. The results of operations exclude general
office overhead and interest expense attributable to oil and gas production.
<TABLE>
<CAPTION>
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Revenues..................................... $24,019,000 $24,655,000 $11,034,000
Production costs............................. 15,095,000 11,673,000 3,888,000
Depletion.................................... 7,216,000 12,645,000 2,836,000
----------- ----------- -----------
1,708,000 337,000 4,310,000
Income tax expense........................... 34,000 7,000 86,000
----------- ----------- -----------
Results of operations from producing
activities................................. $ 1,674,000 $ 330,000 $ 4,224,000
=========== =========== ===========
</TABLE>
Oil and Gas Reserves
The following table presents estimated volumes of proved and proved
developed oil and gas reserves, prepared by independent reserve engineers, as of
December 31, 1996, 1995 and 1994 and changes in proved reserves during the last
three years, assuming continuation of economic conditions prevailing at the end
of each year. Volumes for oil are stated in thousands of barrels (MBbls) and
volumes for natural gas are stated
F-28
<PAGE> 63
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
in millions of cubic feet (Mmcf). The weighted average prices at December 31,
1996 used for reserve report purposes are $26.07 and $3.90 for oil and gas
reserves, respectively.
The Company emphasizes that the volumes of reserves shown below are
estimates which, by their nature, are subject to revision. The estimates are
made using all available geological and reservoir data, as well as production
performance data. These estimates are reviewed annually and revised, either
upward or downward, as warranted by additional performance data.
<TABLE>
<CAPTION>
1996 1995 1994
--------------- ---------------- ---------------
OIL GAS OIL GAS OIL GAS
------ ------ ------ ------- ------ ------
<S> <C> <C> <C> <C> <C> <C>
Proved Reserves:
Beginning of the year............ 14,627 19,131 7,431 28,797 1,852 13,918
Purchase of oil and gas reserves
in place....................... -- -- 15,068 39,204 6,920 5,972
Extensions, discoveries and other
additions...................... -- -- 960 4,235 112 5,762
Revisions of prior reserve
estimates...................... (89) (381) (7,821) (44,859) 1,806 13,451
Current production............... (615) (3,629) (778) (7,403) (270) (3,503)
Sales of oil and gas reserves in
place.......................... -- -- (233) (843) (2,989) (6,803)
------ ------ ------ ------- ------ ------
End of the year.................. 13,923 15,121 14,627 19,131 7,431 28,797
====== ====== ====== ======= ====== ======
Proved developed reserves........ 9,550 11,687 10,209 16,663 3,738 20,814
====== ====== ====== ======= ====== ======
</TABLE>
The 1995 year-end reserve estimates prepared by Netherland , Sewell &
Associates, Inc. ("NSAI") include significant downward revisions from previously
reported volumes. Total reserves have decreased from approximately 205 billion
cubic feet equivalents ("Bcfe"), as previously reported on a pro forma basis in
the Company's 1994 Annual Report to Shareholders after considering the property
acquisitions completed during 1995, to approximately 107 Bcfe at December 31,
1995. These year-end estimates decreased from amounts previously reported due to
production of approximately 15 Bcfe and significant downward revisions by NSAI
of previous estimates. Approximately 38 Bcfe of these revisions result from
differences in professional opinion between NSAI and the Company's predecessor
independent engineering firms, The Scotia Group, Huddleston & Co. and Veazey &
Associates. These differences, many of which relate to classification of
reserves within the different oil and gas reserve categories (i.e. proved,
probable and possible) are due to the numerous engineering, geological and
operational assumptions that generally are derived from limited data. Common
assumptions, which involve the exercise of subjective professional judgment,
include such matters as the areal extent and average thickness of a particular
reservoir, the average porosity and permeability of the reservoir, the
anticipated future production from existing and future wells, future development
and production costs, and the ultimate hydrocarbon recovery percentage.
Additional downward revisions are attributed to field development activity and
production data during the year. Drilling and recompletion activities, including
the unsuccessful well projects in the Company's East Hackberry and Bayou
Penchant fields resulted in significant reserve losses. The mechanical failure
of the Exxon Fee #23 well and the increased water production from the field also
had a negative effect on the Company's reserves at December 31, 1995. These
events, coupled with revised geological interpretation utilizing recent well
performance and reservoir data available, resulted in the further downward
revision of approximately 45 Bcfe.
F-29
<PAGE> 64
WRT ENERGY CORPORATION
(A DEBTOR-IN-POSSESSION AS OF FEBRUARY 14, 1996)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Discounted Future Net Cash Flows
Estimates of future net cash flows from proved oil and gas reserves were
made in accordance with SFAS No. 69, "Disclosures about Oil and Gas Producing
Activities." The following tables present the estimated future cash flows, and
changes therein, from the Company's proved oil and gas reserves as of December
31, 1996, 1995 and 1994, assuming continuation of economic conditions prevailing
at the end of each year.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Oil and Gas Reserves
<TABLE>
<CAPTION>
1996 1995 1994
------------- ------------ ------------
<S> <C> <C> <C>
Future cash inflows....................... $ 421,954,000 $311,419,000 $172,388,000
Future development costs.................. (107,627,000) (96,460,000) (21,547,000)
Future production costs................... (90,558,000) (89,187,000) (31,453,000)
Future production taxes................... (46,703,000) (35,411,000) (17,199,000)
------------- ------------ ------------
Future net cash flows before income
taxes................................... 177,066,000 90,361,000 102,189,000
10% annual discount for estimated timing
of cash flows........................... (78,399,000) (38,994,000) (37,667,000)
------------- ------------ ------------
Discounted future net cash flows.......... 98,667,000 51,367,000 64,522,000
Future income taxes, net of 10% annual
discount................................ -- -- (11,600,000)
------------- ------------ ------------
Standardized measure of discounted future
net cash flows.......................... $ 98,667,000 $ 51,367,000 $ 52,922,000
============= ============ ============
</TABLE>
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves
<TABLE>
<CAPTION>
1996 1995 1994
----------- ------------ ------------
<S> <C> <C> <C>
Sales and transfers of oil and gas produced,
net of production costs................... $(8,924,000) $(12,982,000) $ (7,146,000)
Net changes in prices and development and
production costs.......................... 55,345,000 (26,418,000) 1,202,000
Acquisitions of oil and gas reserves in
place, less related production costs...... -- 62,974,000 43,891,000
Extensions, discoveries and improved
recovery, less related costs.............. -- 4,859,000 5,354,000
Revisions of previous quantity estimates,
less related production costs............. (914,000) (44,100,000) 21,364,000
Sales of reserves in place.................. -- (1,089,000) (20,702,000)
Accretion of discount....................... 5,137,000 6,452,000 1,989,000
Net change in income taxes.................. -- 11,600,000 (9,747,000)
Other....................................... (3,344,000) (2,851,000) (1,316,000)
----------- ------------ ------------
Total change in standardized
measure of discounted future net
cash flows...................... $47,300,000 $ (1,555,000) $ 34,889,000
=========== ============ ============
</TABLE>
21. SUBSEQUENT EVENTS (UNAUDITED)
On July 11, 1997, the Plan for WRT became effective pursuant to its terms
and conditions. In addition, the transactions contemplated by the Plan to occur
on the effective date of the Plan were consummated in accordance with the terms
and conditions of the Plan. The terms, conditions, and contemplated transactions
of the effective Plan are essentially the same as the terms, conditions, and
contemplated transactions of the Plan detailed in Note 2 to the financial
statements.
F-30
<PAGE> 65
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10.DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS; COMPLIANCE
WITH SECTION 16(a) OF THE EXCHANGE ACT
DIRECTORS AND EXECUTIVE OFFICERS
On November 10, 1995, Steven S. McGuire resigned as a director, Chairman of
the Board and Chief Executive Officer of the Company. Samuel C. Guy, the
Company's Executive Vice President, also resigned as a director. Mr. Guy's
employment contract, which expired on February 29, 1996, was not renewed by the
Company. The Board of Directors appointed Raymond P. Landry, previously
President and Chief Operating Officer of the Company, to the position of
Chairman of the Board and Chief Executive Officer. In addition, employment
contracts for Mr. Wayne A. Munson, and Mr. William L. Walter, which expired on
March 20, 1996, and December 31, 1995, respectively, were not renewed. On
February 28, 1997, Thomas C. Stewart resigned as Vice President, Operations.
On July 11, 1997, all of the existing officers and directors of the Company
were terminated pursuant to the terms of the Plan and new officers and directors
were appointed as detailed below:
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Gary C. Hanna........................................... 39 President
Raymond P. Landry....................................... 58 Executive Vice President
Ronald D. Youtsey....................................... 41 Secretary and Treasurer
Charles E. Davidson..................................... 44 Director
Mike Liddell............................................ 43 Director
Mark Liddell............................................ 42 Director
Alan May................................................ 64 Director
Robert Brooks........................................... 50 Director
</TABLE>
Gary C. Hanna has served as President of New WRT since July 11, 1997. Mr.
Hanna also holds the position of Executive Vice President and Chief Operating
Officer of DLB, a position he has held since October 1994. From 1982 to October
1994, he was President and Chief Executive Officer of Hanna Oil Properties,
Inc., an Oklahoma City based petroleum-consulting company. Mr. Hanna received a
B.B.A. degree in economics from the University of Oklahoma. He is on the Board
of Directors of the Oklahoma Independent Producers Association.
Raymond P. Landry has served as Executive Vice President of New WRT since
July 11, 1997. Prior to that Mr. Landry held the position of Chairman of the
Board and Chief Executive Officer of the Company. Mr. Landry served as the
Executive Vice President of Offshore Pipelines, Inc. from June 1991 until March
1995 and continues to provide services on a consulting basis. Between June 1983
and June 1991, Mr. Landry served as a general partner for several real estate
ventures. Mr. Landry is a Certified Public Accountant and holds a BS degree in
Accounting from Louisiana State University.
Ronald D. Youtsey has served as Secretary and Treasurer of New WRT since
July 11, 1997. Mr. Youtsey also holds the position of Senior Vice President and
Chief Financial Officer of DLB. Mr. Youtsey joined DLB as Controller in 1991.
From 1979 to 1991, he was employed by French Petroleum Corporation, an oil and
gas exploration and production company, last serving as Vice President of
Finance. Mr. Youtsey is a Certified Public Accountant and a member of the
American Institute of Certified Public Accountants. He received a BS degree in
accounting from the University of Central Oklahoma.
35
<PAGE> 66
Charles E. Davidson has served as a director of New WRT since July 11,
1997. Mr. Davidson also holds the position of Chairman of the Board of Directors
of DLB. Since 1994, he has also served as managing partner of Wexford Capital
Corporation, a private investment firm. From 1984 to 1994, he was a partner in
Steinhardt Partners, L.P., a private investment firm. From 1977 to 1984, Mr.
Davidson was employed by Goldman, Sachs & Co., last serving as Vice President of
corporate bond trading. Mr. Davidson is Chairman of the Board of Resurgence
Properties, Inc. and is also a director of Presido Capital, Inc., both of which
are publicly held real estate companies. He holds a BA degree and a MBA degree
from the University of California at Los Angeles.
Mike Liddell has served as Chief Executive Officer of DLB since October
1994, and as a director of DLB since 1991. From 1991 to 1994, Mr. Liddell was
President of DLB. From 1979 to 1991, he was President and Chief Executive
Officer of DLB Energy. He received a B.S. degree in education from Oklahoma
State University. He is the brother of Mark Liddell.
Mark Liddell has served as a director of New WRT since July 11, 1997. Mr.
Liddell also holds the position of President of DLB, a position he has held
since October 1994. Mr. Liddell was Vice President of DLB from 1991 to 1994.
From 1985 to 1991, he was Vice President of DLB Energy. From 1991 to May 1995,
Mr. Liddell served as a director of TGX Corporation, a publicly held oil and gas
company, and from 1989 to 1990, he served as a director of Kaneb Services, Inc.,
a publicly held industrial services and pipeline transportation company. He
received a BS degree in education and a JD degree from the University of
Oklahoma.
Alan May has served as a director of New WRT since July 11, 1997. Mr. May
was a partner in Coopers & Lybrand, an accounting firm, until his retirement in
October 1995. He had been employed by Coopers & Lybrand or its predecessor,
Lybrand Ross Bros. & Montgomery since 1958. From 1956 to 1958, Mr. May served as
a commissioned officer in the United States Navy. He received his BS degree in
accounting from the University of California at Los Angeles.
Robert E. Brooks has served as a director of New WRT since July 11, 1997.
Mr. Brooks is currently a Senior Vice President in charge of Asset Finance and
Managed Assets for Bank One, Louisiana. Mr. Brooks is a Certified Public
Accountant and has worked as a banker for large commercial banks since 1974. He
has specialized in the oil and gas business, owns working interests in a number
of oil and gas properties, and has acted as an operator of oil and gas
properties. He received his BS degree from Purdue University in mechanical
engineering in 1969. He served four years as a Naval Officer in the United
States Navy and then graduated from the Graduate School of Business at the
University of Chicago with a degree in finance and accounting in 1974.
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT
Section 16(a) of the Securities Exchange Act of 1934, as amended, requires
the Company's officers, directors and persons who own more than ten percent of a
class of the Company's equity securities to file with the Securities and
Exchange Commission initial reports of ownership and reports of changes in
ownership of the Company's equity and derivative securities. On July 11, 1997
(the Effective Date), all equity and derivative securities of the Company were
cancelled in accordance with the Plan and the former equity and derivative
security owners no longer had an equity position in the Company.
ITEM 11. EXECUTIVE COMPENSATION
Director Compensation -- Up to the Effective Date, each director who was
not a salaried employee of the Company received $500 for his attendance at each
meeting of the Board of Directors and was reimbursed for expenses incurred in
connection with attending each such meeting. Employee directors and directors
who were exclusive, full-time consultants received no compensation, but were
eligible to participate in the Company's incentive stock option plans. Rights
under all existing incentive stock options plans were terminated as of the
Effective Date.
36
<PAGE> 67
Employment Agreements -- As called for in the Plan, Mr. Landry entered into
a two-year employment agreement with New WRT commencing on the Effective Date.
This employment agreement provides for a salary of $156,000 per year and stock
options to purchase 60,000 shares of New WRT stock at $3.50 per share. In
addition, New WRT assumed the rights and obligations of existing employment
contracts with Wayne A. Beninger and Thomas C. Stewart, both of which expired on
August 31, 1997 and called for annual salaries of $125,000 and $100,000,
respectively.
The following table provides certain summary information concerning
compensation paid or accrued during the three fiscal years ended December 31,
1996 to the Company's Chief Executive Officer and each of the four most highly
compensated executive officers of the Company, determined as of the end of the
last fiscal year, whose annual compensation exceeded $100,000.
<TABLE>
<CAPTION>
NAME AND POSITION YEAR SALARY BONUS OTHER
----------------- ---- -------- ------- --------
<S> <C> <C> <C> <C>
Steven S. McGuire(1)........................ 1996 $ -- $ -- $195,000
1995 168,366 50,000 90,000
1994 96,000 50,000 --
---- -------- ------- --------
Wayne A. Beninger(2)........................ 1996 116,804 -- --
1995 59,154 -- --
1994 -- -- --
---- -------- ------- --------
Ronald E. Hale, Jr.(3)...................... 1996 75,077 -- --
1995 84,462 27,000 18,000
1994 66,000 20,000 --
---- -------- ------- --------
Raymond P. Landry(4)........................ 1996 161,962 25,000 --
1995 90,558 -- --
1994 -- -- --
---- -------- ------- --------
Thomas C. Stewart(5)........................ 1996 108,808 -- --
1995 27,500 -- --
1994 -- -- --
</TABLE>
- ---------------
(1) Mr. McGuire resigned as Chairman of the Board and Chief Executive Officer on
November 10, 1995. During 1996, Mr. McGuire received $195,000 in other
compensation per the terms of a Consulting Agreement. During 1995, Mr.
McGuire received $18,000 in other compensation for the cancellation of
225,000 beneficially owned shares of restricted stock as a part of a 1993
Restricted Stock Grant, which was terminated by the Company's Board of
Directors on November 10, 1995.
(2) Mr. Beninger resigned as Vice President of Strategic Planning on August 31,
1997. During 1997, Mr. Beninger received $65,500 compensation as a
participant of the employee stay bonus program.
(3) Mr. Hale resigned as Chief Financial Officer on September 10, 1996. During
1995, Mr. Hale received $18,000 in other compensation for the cancellation
of 225,000 beneficially owned shares of restricted stock as part of a 1993
Restricted Stock Grant, which was terminated by the Company's Board of
Directors on November 10, 1995.
(4) Mr. Landry received a $25,000 sign-on bonus, per the terms of his employment
contract, payment of which was deferred to 1996. Mr. Landry received $78,000
compensation, during 1997, as a participant of the employee stay bonus
program.
(5) Mr. Stewart resigned as Vice President of Operations on July 11, 1997.
During 1997, Mr. Stewart received $53,000 compensation as a participant of
the employee stay bonus program.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER TRADING
No member of the Committee is a former or current officer or employee of
the Company and no employee of the Company serves or has served on the
compensation committee (or board of directors of a corporation lacking a
compensation committee) of a corporation employing a member of this Committee.
37
<PAGE> 68
BOARD COMMITTEE REPORT ON EXECUTIVE COMPENSATION
As a result of the Company's bankruptcy, the Compensation Committees'
meetings and subsequent reports were discontinued.
OTHER INFORMATION ABOUT DIRECTORS, OFFICERS
AND CERTAIN SHAREHOLDERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table sets forth certain information at July 10, 1997
regarding the beneficial ownership of the Company's Common Stock by (i) each
person known to be the beneficial owner of 5% or more of the Common Stock, (ii)
each principal executive officer or director of the Company, and (iii) all
executive officers and directors as a group. As a result of the bankruptcy
proceeding, all shares of WRT's Common Stock were extinguished on the effective
date of the Plan.
<TABLE>
<CAPTION>
AMOUNT AND NATURE OF PERCENT OF
NAME OF BENEFICIAL OWNER(1)(2) BENEFICIAL OWNERSHIP(3) CLASS
------------------------------ ----------------------- ----------
<S> <C> <C>
Raymond P. Landry(4).................................. 179,833 1.9%
Wayne A. Beninger(5).................................. 41,667 *
Thomas C. Stewart(6).................................. 33,333 *
Donnie Lam(7)......................................... 42,500 *
James T. Rash(7)...................................... 42,500 *
Charles R. Coates, Jr................................. 1,418,800 14.9%
All executive officers and directors as a group (6
persons)............................................ 640,913 6.3%
</TABLE>
- ---------------
* Less than one percent.
(1) Each listed person's percentage ownership is determined by assuming that
options, warrants and other convertible securities that are held by such
person and that are exercisable or convertible within 60b days have been
exercised or converted.
(2) Unless otherwise indicated, each listed person's mailing address is 3303 FM
1960 West, Houston, Texas 77068.
(3) Unless other wise indicated, each person or group has sole voting and
investment power with respect to all listed shares.
(4) Includes 133,333 presently exercisable (or exercisable within 60 days)
non-qualified plan stock options granted in connection with Mr. Landry's
employment agreement and 12,500 and 30,000 options presently exercisable
granted pursuant to the 1991 Outside Directors' Stock Option Plan and the
1994 Directors' Stock Option Grant, respectively.
(5) Includes 41,667 present exercisable non-plan stock options granted in
connection with Mr. Beninger's employment agreement.
(6) Includes 33,333 present exercisable non-plan stock options granted in
connection with Mr. Stewart's employment agreement.
(7) In connection with their election to serve as directors at the 1993 annual
meeting of shareholders, Dr. Lam and Mr. Rash were each granted a ten-year
option to purchase 12,500 shares of Common Stock at an exercise price of
$9.00 per share. In addition, pursuant to the 1994 Directors' Stock Option
Grant, approved at the 1994 annual meeting of shareholders, Dr. Lam and Mr.
Rash were each granted a five-year option to purchase 30,000 shares of
Common Stock at an exercise price of $10.00 per share. On May 8, 1995, the
exercise price on both the 1993 and 1994 option grant was changed to $6.69
per share.
38
<PAGE> 69
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
During 1996, DLB Oil & Gas, Inc. and Wexford Management LLC ("Wexford")
entered into an oral agreement to acquire the debt securities of and secured
claims against the Company. Pursuant to such agreement, DLB and Wexford acquired
an aggregate of approximately $34.3 million principal face amount of senior
notes of, and, through a jointly-owned entity, approximately $4.7 million
aggregate amount of asserted secured claims against, the Company.
The Company, DLB and Wexford have filed with the bankruptcy court a joint
plan of reorganization for the Company (the "WRT Plan"), which provides, among
other things, for an exchange of the notes and secured claims for common stock
in the reorganized WRT. On July 11, 1997, DLB and Wexford received an aggregate
of 12,580,000 million shares of new WRT common stock for various claims, assets
and cash as detailed below:
<TABLE>
<S> <C>
Unsecured debt of $34.3 million............................. 2.88 million shares
Contribution of DLB's interest in WCBB properties........... 5.62 million shares
Cash of $5,000,000.......................................... 1.43 million shares
Contribution of $9.3 million in secured and
Asserted secured claims................................... 2.65 million shares
Total shares issued to DLB and Wexford............ 12.58 million shares
</TABLE>
PERFORMANCE GRAPH
A Performance Graph has not been included in this report because it is not
meaningful due to the Company's Bankruptcy.
39
<PAGE> 70
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a)
(1) Financial Statements
(2) Financial Statement Schedules
(3) Exhibits required by Item 601 of Regulation S-K are as follows:
<TABLE>
<C> <S>
2.1 -- Final Order Authorizing Use of Proceeds from Oil and Gas
Operations.(1)
2.2 -- Letter agreement by and among WRT Energy Corporation, DLB
Oil & Gas, Inc. and Wexford Management, dated October 22,
1996.(2)
2.3 -- Debtor's and DLBW's First Amended Joint Plan of
Reorganization Under Chapter 11 of the United States
Bankruptcy Code dated January 20, 1997.(3)
2.4 -- First Amended Disclosure Statement Under 11 U.S.C. 1125
In Support of Debtor's and DLBW's First Amended Joint
Plan of Reorganization Under Chapter 11 of the United
States Bankruptcy Code dated January 20, 1997.(3)
2.5 -- Agreement and Plan Merger(4)
27.1 -- Financial Data Schedule
</TABLE>
(b) The Registrant filed the following reports on Form 8-K
Form 8-K filed January 5, 1996, announcing filing of class action
suit by two shareholders of the Company.
Form 8-K filed February 14, 1996 announcement of filing of
Chapter 11 proceeding in the United States Bankruptcy Court for
the Western District of Louisiana in Opelousas and the retaining
of Jefferies & Company, Inc. as financial advisor to the Company.
Form 8-K filed November 6, 1996 announcement of Commitment
Agreement between WRT Energy Corporation, DLB Oil & Gas, Inc. and
Wexford Management LLC.
Form 8-K filed March 3, 1997 announcing the First Amended Joint
Plan of Reorganization, First Amended Disclosure Statement.
Form 8-K filed March 14, 1997 concerning March 5, 1997 hearing on
ongoing operations and use of available cash.
Form 8-K filed on June 16, 1997 to correct Form 8-K filing of Pro
Forma Statement of Operations.
Form 8-K filed on July 22, 1997 announcing consummation of the
Second Amended Joint Plan of Reorganization as amended.
- ---------------
(1) Filed with Form 8-K dated March 14, 1997.
(2) Filed with Form 8-K dated November 6, 1996
(3) Filed with Form 8-K dated March 3, 1997.
(4) Filed with Form 8-K dated July 22, 1997.
40
<PAGE> 71
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EX. NO. DESCRIPTION
------- -----------
<C> <S>
2.1 -- Final Order Authorizing Use of Proceeds from Oil and Gas
Operations.(1)
2.2 -- Letter agreement by and among WRT Energy Corporation, DLB
Oil & Gas, Inc. and Wexford Management, dated October 22,
1996.(2)
2.3 -- Debtor's and DLBW's First Amended Joint Plan of
Reorganization Under Chapter 11 of the United States
Bankruptcy Code dated January 20, 1997.(3)
2.4 -- First Amended Disclosure Statement Under 11 U.S.C. 1125
In Support of Debtor's and DLBW's First Amended Joint
Plan of Reorganization Under Chapter 11 of the United
States Bankruptcy Code dated January 20, 1997.(3)
2.5 -- Agreement and Plan Merger(4)
27.1 -- Financial Data Schedule
</TABLE>
- ---------------
(1) Filed with Form 8-K dated March 14, 1997.
(2) Filed with Form 8-K dated November 6, 1996
(3) Filed with Form 8-K dated March 3, 1997.
(4) Filed with Form 8-K dated July 22, 1997.
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<CASH> 5,679
<SECURITIES> 0
<RECEIVABLES> 3,667
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 9,979
<PP&E> 82,659
<DEPRECIATION> 25,760
<TOTAL-ASSETS> 95,341
<CURRENT-LIABILITIES> 9,043
<BONDS> 0
0
0
<COMMON> 221
<OTHER-SE> 70,517
<TOTAL-LIABILITY-AND-EQUITY> 96,341
<SALES> 24,019
<TOTAL-REVENUES> 24,019
<CGS> 15,095
<TOTAL-COSTS> 15,095
<OTHER-EXPENSES> 7,973
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 5,562
<INCOME-PRETAX> (28,387)
<INCOME-TAX> 0
<INCOME-CONTINUING> (29,387)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (32,233)
<EPS-PRIMARY> (3.38)
<EPS-DILUTED> (3.38)
</TABLE>
